Item 1. Business.
Pogo Producing Company (the "Company"), incorporated in 1970, is engaged in oil and gas exploration, development and production activities on its properties located offshore in the Gulf of Mexico, onshore in selected areas in New Mexico, Texas and Louisiana, and internationally in the Gulf of Thailand. As of December 31, 1996, the Company had interests in 86 lease blocks offshore Louisiana and Texas, approximately 212,000 gross acres onshore in the United States and approximately 1,300,000 gross acres offshore in the Kingdom of Thailand. Unless otherwise specifically identified, the information set forth in this Annual Report, including production rates and the number of wells, platforms and blocks, is presented on a gross basis, rather than net to the Company.
In recent years, the Company has rationalized its asset base and concentrated its efforts in selected areas where it believes that its expertise, competitive acreage position, or ability to quickly take advantage of new opportunities offer the possibility of superior rates of return. As of January 1, 1997, seven significant operating areas, of which four are located in the Gulf of Mexico and one each in New Mexico, South Texas and Thailand, accounted for approximately 90% of the estimated proved natural gas reserves and approximately 93% of the estimated proved oil, condensate and natural gas liquids reserves of the Company. Six of these operating areas also accounted for approximately 73% of natural gas production and 88% of oil, condensate and natural gas liquids production for 1996. The seventh operating area, the Gulf of Thailand, did not commence production until February 1, 1997. Reserves, as estimated by Ryder Scott Petroleum Engineers, Houston Texas ("Ryder Scott"), and production data, as estimated by the Company, for the seven significant operating areas are shown in the following table. No other producing area accounted for more than 3% of the Company's estimated proved reserves as of January 1, 1997.
Significant Operating Areas
- ---------------------- (a) Net proved reserves and total net proved reserves each as of January 1, 1997. Total net reserves are calculated on an energy equivalent basis using a ratio of six Mcf equal to one Bbl of oil. Units of measurement used in this table include: thousand cubic feet ("Mcf"), million cubic feet ("MMcf"), barrels ("Bbls") and thousand barrels ("MBbls").
(b) "Liquids," includes oil, condensate and natural gas liquids.
(c) Initial production from the Tantawan Field commenced on February 1, 1997. After giving effect to the Company's March 1997 acquisition of its proportionate share of the shares of Maersk Oil (Thailand) Ltd., the Company's net proved reserves of natural gas and hydrcarbon liquids located in the Kingdom of Thailand would have been 166,160 MMcf and 26,163 MBbls, respectively, on a pro forma basis on January 1, 1997. This would have equated to 46% of the Company's total net proved hydrocarbon reserves, 43% of net proved natural gas reserves, and 48% of net proved liquids on a pro forma basis as of January 1, 1997, while the respective percentages of the Company's domestic hydrocarbon reserves as a percentage of the Company's total net proved reserves would have been proportionately reduced.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 66% of the Company's domestic proved reserves and 38% of its total proved reserves are now located. During 1996, approximately 82% of the Company's natural gas production and 67% of its oil and condensate production was from its domestic offshore properties, contributing approximately 72% of consolidated oil and gas revenues. Four offshore producing areas, Eugene Island, East Cameron, Main Pass and South Pass, account for approximately 33% of the Company's net proved natural gas reserves and approximately 31% of the Company's proved crude oil, condensate and natural gas liquids reserves. See "Significant Domestic Offshore Operating Areas during 1996."
Lease Acquisitions
The Company has participated, either on its own or with other companies, in bidding on and acquiring interests in federal and state leases offshore in the Gulf of Mexico since December 1970. As a result of such sales and subsequent activities, as of December 31, 1996, the Company owned interests in 77 federal leases and 9 state leases offshore Louisiana and Texas. Federal leases generally have primary terms of five years and state leases generally have terms of three years, in each case subject to extension by development and production operations.
As part of its strategy, the Company intends to continue an active lease evaluation program in the Gulf of Mexico in order to identify exploration and exploitation opportunities. During 1996, the Company was successful in acquiring interests in ten lease blocks through federal Outer Continental Shelf oil and gas lease sales. The Department of the Interior has announced its intention to hold two lease sales during 1997 covering federal acreage in the Central and Western portions of the Gulf of Mexico; and it is anticipated that various states will also hold sales covering offshore state acreage from time to time. As in the case of prior sales, the extent to which the Company participates in future bidding will depend on the availability of funds and its estimates of hydrocarbon deposits, operating expenses and future revenues which reasonably may be expected from available lease blocks. Such estimates typically take into account, among other things, estimates of future hydrocarbon prices, federal regulations, and taxation policies applicable to the petroleum industry. It is also the Company's objective to acquire certain producing leasehold properties in areas where additional low-risk drilling or improved production methods by the Company can provide attractive rates of return.
Exploration and Development
The scope of exploration and development programs relating to the Company's offshore interests is affected by prices for oil and gas, and by federal, state and local legislation, regulations and ordinances applicable to the petroleum industry. The Company's domestic offshore capital and exploration expenditures for 1996 were approximately $92,400,000 (excluding approximately $2,000,000 of net property acquisitions), or 144% higher than the Company's domestic offshore capital and exploration expenditures of approximately $37,800,000 (excluding approximately $650,000 of net property acquisitions) for 1995 and 91% higher than the Company's domestic offshore capital and exploration expenditures of approximately $48,400,000 for 1994 (excluding approximately $32,600,000 of net property acquisitions). The increase in the Company's domestic offshore capital and exploration expenditures for 1996, compared to 1995, resulted primarily from increased drilling activity and increased costs associated with the construction and installation of offshore platforms, pipelines and other facilities. The increase in the Company's domestic offshore capital and exploration expenditures for 1996, compared to 1994, resulted primarily from increased costs associated with construction and installation of offshore platforms, pipelines and other facilities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Leases acquired by the Company and other participants in its bidding groups are customarily committed, on a block-by-block basis, to separate operating agreements under which the appointed operator supervises exploration and development operations for the account and at the expense of the group. These agreements usually contain terms and conditions which have become relatively standardized in the industry. Major decisions regarding development and operations typically require the consent of at least a majority (in working interest) of the participants. Because the Company generally has a meaningful working interest position, the Company believes it can significantly influence (but not always control) decisions regarding development and operations on most of the leases in which it has a working interest even though it may not be the operator of a particular lease. The Company is currently the operator on all or a portion of 26 of the 86 offshore leases in which it has an interest.
Platforms are installed on an offshore lease block when, in the judgment of the lease interest owners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment. Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the last three years, the gross cost of production platforms to the joint ventures in which the Company has varying net interests has averaged approximately $7,000,000. Platform costs vary and more expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents, and sea floor conditions. During 1996, the Company installed, or substantially completed construction of, two new platforms on East Cameron Block 334 and one new platform on Ship Shoal Block 240. See "Significant Domestic Offshore Operating Areas During 1996."
Significant Domestic Offshore Operating Areas During 1996
Eugene Island
A significant portion of the Company's reserves and a substantial part of its production are located in the Eugene Island area off the Louisiana coast in the Gulf of Mexico. The Eugene Island area has been an important part of the Company's operations since the first lease in that area was purchased in 1970 and production began in 1973. The Company currently holds interests in 10 blocks in the Eugene Island area. These blocks comprise eight fields containing 67 oil and gas wells producing from multiple reservoirs and horizons. Through January 1997, the Company participated in the drilling of six wells in the Eugene Island operating area, including three highly successful wells in its Eugene Island 261 field where the Company has a 66.67% working interest that added new reserves and production capacity, bringing the total number of productive wells in this field to six.
The Eugene Island Block 330 field is one of the Company's most significant producing assets. The field, located in 245 feet of water, contains three drilling and production platforms in which the Company holds a 35% working interest, as well as an additional platform in which the Company holds a 30% working interest. There are currently 9 wells producing primarily natural gas and 34 wells producing primarily oil on the block. Reserves have been added to this field consistently since production commenced. These increases have been derived from new exploratory horizons, infill drilling, field expansions and higher than anticipated recovery efficiencies. The Company and its joint venture partners currently plan to drill seven wells in this field during 1997.
East Cameron
The first leasehold interest acquired by the Company in the East Cameron area off the Texas/Louisiana border in the Gulf of Mexico commenced production in February 1973. Presently, the Company has interests in three offshore blocks in this area which contain two fields and 15 producing gas wells.
During 1996, the Company and its partners were active in the East Cameron Block 334/335 field. In August 1996, the Company and one of its joint venture partners commenced production from the fourth platform to be installed in this field. In addition, together with the same partner, the Company drilled two additional wells and commenced construction of a fifth platform for this field which has been installed and is currently scheduled to commence production in the second quarter of 1997. Finally, during the fourth quarter of 1996, the Company and its joint venture partners drilled another exploratory well into a new untested fault block, the results of which the Company and its joint venture partners are currently evaluating for a possible sixth platform in the field.
Main Pass
The Company's 13 lease blocks in the Main Pass area, including one acquired in 1996, are located near the mouth of the Mississippi River in the Gulf of Mexico and include leases in which the Company has held an interest since 1974. The Company currently plans an active exploratory drilling program during 1997 to evaluate the new lease blocks that it acquired in the Main Pass Area. The majority of the Company's production from the Main Pass area comes from a field that includes Main Pass Blocks 72, 73 and 72/74 which was unitized in 1982. The Company's working interest in this field is 35%. This field contains 26 producing oil wells and 6 producing natural gas wells from three platforms operated by the Company's joint venture partner. The field is located in 125 feet of water. The Company plans to continue into 1997 its successful drilling program that commenced in 1995 which has been based in part on the analysis of a recent 3-D seismic survey over the field.
South Pass
The Company acquired its first leasehold interest in the South Pass area off of the mouth of the Mississippi River in September 1972. In 1996, the Company acquired an interest in three additional blocks in this area, bringing the total number of blocks in the South Pass area in which the Company currently owns an interest to ten, on which four production platforms have been set that produce oil and gas from 25 wells. One of the Company's fields in the South Pass area is located on South Pass Blocks 49 and 50. The Company holds a 50% working interest in South Pass Block 50 and a 20% interest in South Pass Block 49. The Company plans to drill additional wells in this field during 1997. Another field in which the Company has an interest in the South Pass area is the South Pass Block 78 field. Following analysis of a recently acquired 3-D seismic survey, the Company and several of its joint venture partners drilled and completed four highly deviated wells into previously unexplored reservoirs during late 1995 and 1996. The Company and its joint venture partners currently plan to drill an additional well or wells in this field during 1997.
DOMESTIC ONSHORE OPERATIONS
The Company has onshore division staffs in Houston and Midland, Texas. Its onshore activities are concentrated in known oil and gas provinces, principally the Permian Basin area of southeastern New Mexico, West Texas and Northwest Texas, and in the onshore Gulf Coast areas of South Texas, East Texas and South Louisiana. See "Significant Domestic Onshore Operating Areas During 1996."
Lease Acquisitions
Commencing in 1995 and continuing in 1996, the Company increased its activities in the onshore Gulf Coast areas of East Texas and South Louisiana. In addition to participating in the acquisition of several large 3-D seismic surveys, the Company acquired an interest in, or the right to acquire an interest in, 22,395 gross acres in East Texas and South Louisiana. As it has in recent years, in 1996 the Company also successfully participated in various onshore federal and state lease sales and acquired interests in prospective acreage from private individuals. As of December 31, 1996, the Company held interests in approximately 212,000 gross (103,000 net) acres onshore in the United States, an increase of approximately 40% (9% net) from year end 1995.
Exploration and Development
The Company's primary drilling objective in the Permian Basin is the Brushy Canyon (Delaware) formation which generally produces oil from depths of 6,000 to 9,000 feet. Since the Company began exploring in the Brushy Canyon (Delaware) formation in October 1989, it has participated in drilling 299 wells in the Permian Basin, West and Northwest Texas areas through December 31, 1996, including 40 wells in 1996.
The Company is also active in exploring for oil and gas in several other onshore Gulf Coast areas in Texas and Louisiana. In addition to the wells drilled in the Permian Basin, during 1996 the Company participated in the drilling of eight exploratory wells (principally in East Texas and South Louisiana) and ten development wells (principally in the Lopeno Field in South Texas). See "Significant Domestic Onshore Operating Areas During 1996." During 1996, approximately 18% of the Company's natural gas production and 33% of its oil and condensate production was from its domestic onshore properties, contributing approximately 23% of consolidated oil and gas revenues.
The Company generally conducts its onshore activities through joint ventures and other interest-sharing arrangements with major and independent oil companies. The Company operates many of its own onshore properties using independent contractors.
The Company's domestic onshore capital and exploration expenditures were approximately $43,000,000 (excluding approximately $3,800,000 of net property acquisitions) for 1996, or 31% higher than the Company's domestic onshore capital and exploration expenditures of approximately $32,950,000 (excluding approximately $7,750,000 of net property acquisitions) for 1995 and 34% higher than the Company's domestic onshore capital and exploration expenditures of approximately $32,000,000 for 1994. The increase in the Company's domestic onshore capital and exploration expenditures for 1996, compared to 1995 and 1994, resulted primarily from increased drilling activity in South Texas, East Texas and South Louisiana, as well as increased exploration costs
associated with conducting, processing and interpreting 3-D seismic surveys. Onshore reserves as of December 31, 1996, accounted for approximately 34% of the Company's domestic proved reserves and approximately 20% of its total proved reserves.
Significant Domestic Onshore Operating Areas During 1996
New Mexico
The Company believes that during the past five years it has been one of the most active companies drilling for oil and natural gas in the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin where the Company has interests in over 75,000 gross acres. The Company's primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin are generally characterized by production from relatively shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and relatively high initial rates of production (frequently equaling the top field allowables which typically range from of 142 Bbls to 230 Bbls per day, depending on the depth of production from the field). The Company has achieved rapid cost recovery with respect to its New Mexico wells drilled to date because of relatively low capital costs and high initial rates of production.
Since the Company began exploring in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin in October 1989, it has participated through December 31, 1996, in the drilling of, among others, 92 wells in the Sand Dunes field where the Company's working interest ranges from 4% to 100%, 27 wells in the East Loving field where the Company's working interest ranges from 33% to 98%, 57 wells in the Livingston Ridge field where the Company's working interest ranges from 25% to 100%, 58 wells in the Red Tank field where the Company's working interest ranges from 89% to 100%, 16 wells in the Cedar Canyon field where the Company's working interest ranges from 38% to 100% (including nine during 1996), and 3 wells in the Lost Tank field where the Company's working interest ranges from 50% to 100%. The oil fields in this area are generally developed on a 40 acre spacing pattern. The Company anticipates drilling many additional locations in these and other fields in southeastern New Mexico during 1997 including, in particular, an aggressive drilling program in the Cedar Canyon and Lost Tank fields.
Lopeno Field
The Lopeno Field is located in south Texas, within 40 miles of the Mexican border. The Company acquired its initial interest in the Lopeno Field in 1983. The Company currently has interests in over 7,800 gross acres containing 23 wells, with working interests generally averaging approximately 50%. The Lopeno Field produces from over 20 upper Wilcox sandstone reservoirs ranging in depth up to 12,500 feet. Following acquisition, processing and interpretation of a 3-D seismic survey over the field, the Company and its joint venture partners commenced an active development drilling program in the fourth quarter of 1995, including the drilling of seven wells in 1996. The Company and its joint venture partners currently plan to drill an additional seven wells in the Lopeno Field during 1997.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas throughout the world. The Company pursues a strategy of evaluating potentially high return prospects in areas of the world with a stable political and financial climate such as certain European and ASEAN ("Association of Southeast Asian Nations") countries. Currently, the Company maintains an office in Bangkok, Thailand from which it directs a field development project in the Gulf of Thailand on a portion of its Block B8/32 Concession (the "Concession") through its wholly owned subsidiary, Thaipo Limited ("Thaipo").
The Company's international capital and exploration expenditures were approximately $64,400,000 for 1996, or 84% higher than the Company's international capital and exploration expenditures of approximately $34,950,000 (excluding approximately $4,171,000 of net property acquisitions) for 1995 and 914% higher than the Company's international capital and exploration expenditures of approximately $6,350,000 for 1994. Substantially all of the Company's international capital and exploration expenditures for 1996 were related to the Company's license in the Kingdom of Thailand. In addition, the Company continues to evaluate other international opportunities that are consistent with the Company's international exploration strategy.
Platforms are installed on the Concession in fields where, in the judgment of Thaipo and its joint venture partners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment and the area where the platform would be located has been designated a production area by the Thai government. See "-- Contractual Terms Governing the Concession and Related Production." Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the last two years, the gross cost of the first three production platforms in the Tantawan Field (which includes the "C" platform being set in the first quarter of 1997) has averaged approximately $20,000,000. Platform costs vary and more (or less) expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents, and sea floor conditions. See "-- Significant International Operating Areas During 1996; Tantawan Field."
Significant International Operating Areas During 1996
Tantawan Field
In August 1995, at the request of Thaipo and its two joint venture partners, the government of Thailand designated a portion of the Concession comprising approximately 68,000 acres as the Tantawan production area. The Tantawan production area, of which Thaipo is the operator and has a 46.34% working interest, has been named the Tantawan Field. Through March 1, 1997, eleven exploration and twenty-three development wells have been drilled in the Tantawan Field. Initial production from the Tantawan Field commenced on February 1, 1997, from wells located on two platforms. Development drilling is due to commence from a third platform that is currently being installed. A fourth platform has been announced for the field and is currently under construction. Oil and gas production from the field is gathered through pipelines from the platforms into a Floating Production, Storage and Offloading system (an "FPSO") named the "Tantawan Explorer." The FPSO Tantawan Explorer is a converted oil tanker with a capacity of slightly less than 1,000,000 Bbls, that is moored in the Tantawan Field, on which hydrocarbon processing, separation, dehydration, compression, metering and other production related equipment is installed. Following processing on board the FPSO, natural gas produced from the field is delivered to the Petroleum Authority of Thailand ("PTT") through an export pipeline. Oil and condensate produced from the field is stored on board the FPSO and transferred to shore by oil tanker. The FPSO and its processing equipment is leased from a third party under a bareboat charter by Tantawan Services, LLC, an affiliate of Thaipo. See "Management's Discussion and Analysis of Financial Condition and Results of Operations --Liquidity and Capital Resources." Thaipo and its joint venture partners pay a processing fee to Tantawan Services, LLC, to process the production from the Tantawan Field through the FPSO.
Benchamas and Pakakrong Fields
Exploration efforts also continue on those portions of the Concession outside the Tantawan Field. Through March 1, 1997, fourteen exploration wells have been drilled on the Concession outside of the Tantawan Field. This includes nine wells, all of which encountered hydrocarbons, in the Benchamas Field and two wells, which also encountered hydrocarbons, in the Pakakrong Field. In January 1997, Thaipo and its joint venture partners formally requested that the government of Thailand designate certain Concession areas outside the Tantawan Field, including the Maliwan, North Benchamas, Benchamas and Pakakrong fields, as production areas. The government is currently considering the request. In the interim, Thaipo and its joint venture partners have commenced preliminary planning for the development of these fields. In March 1997, the Company and its joint venture partners in the Tantawan Field or their affiliates, acquired all of the outstanding shares of Maersk Oil (Thailand) Ltd., a former joint venture partner that owned 31.67% of those portions of the Concession not currently a part of the Tantawan Field, including the Benchamas and Pakakrong Fields. With this acquisition, the Company now indirectly owns a 46.34% working interest in the entire Concession and its subsidiary Thaipo is the operator of the entire Concession.
Other Areas on the Concession
In addition to the above mentioned fields, Thaipo and its joint venture partners have identified other potentially promising areas on the Concession. Since acquiring their interest in the Concession, Thaipo and its joint
venture partners have acquired 3-D seismic surveys covering approximately 452,000 acres of the Concession and are currently planning to acquire additional 3-D seismic data over other prospective portions of the Concession during 1997. In addition to the ongoing interpretation of recently acquired 3-D seismic data, Thaipo and its joint venture partners are currently engaged in an exploratory drilling program evaluating the North Benchamas prospect, following which they currently plan to test the Maliwan prospect.
Contractual Terms Governing the Concession and Related Production
As set forth in the August 1991 Concession agreement, the current exploratory term of the Concession agreement expires on July 31, 1997, subject to further extension as described below. At the end of the Concession agreement's current exploration term on July 31, 1997, Thai petroleum law permits the government to grant, upon application by a concessionaire, an additional three year exploration term on up to fifty percent of the Concession acreage that has not been previously designated as a production area or returned to the government, subject to certain terms and conditions including the agreement to undertake a work program and the payment of substantial fees and rentals. The Company and its joint venture partners are currently discussing with governmental authorities what the relevant work program, fees and rentals may be for an extension of the current exploratory term. Currently, the Company and its joint venture partners intend to apply to the government for a three year extension of the exploratory term of the Concession which would include the maximum amount of acreage permitted by applicable law. For those portions of the Concession designated as production areas, which currently includes the Tantawan Field and, subject to the governmental approval discussed above, may include other portions of the Concession such as the Maliwan, North Benchamas, Benchamas and Pakakrong fields, the initial production period term is 20 years, which is also subject to extension. See also "-- Miscellaneous; Sales."
Production resulting from the Concession (including the Tantawan production area) is subject to a royalty ranging from 5% to 15% of oil and gas sales, plus certain fixed dollar amounts payable at specified cumulative production levels. Revenue from production in Thailand is also subject to income taxes and other similar governmental charges including a Special Remuneratory Benefit tax ("SRB").
On November 7, 1995, Thaipo and its joint venture partners announced the signing of a thirty-year gas sales agreement with PTT, initially governing gas production from the Tantawan Field. Subsequently, Thaipo and its joint venture partners reached an agreement in principle to amend this gas sales agreement to include the reserves and anticipated gas production from the remainder of the Concession, including the Benchamas Field. Initial terms of the agreement include an initial minimum daily contract quantity ("DCQ") during the first year of production of 75 MMcf per day with the DCQ rising to 85 MMcf per day in the following year. The DCQ is the minimum daily volume that PTT has agreed to take, or pay for if not taken under the agreement. Mutual agreement on dedicated reserves would be renegotiated as and when the DCQ exceeds 125 MMcf per day. Initial base gas prices start at approximately $2.00 per Mcf, subject to semi-annual adjustments based upon a formula which takes into account, among other things, changes in Singapore fuel oil prices, Thai wholesale prices and the U.S./Thai currency exchange rate. In late 1996, Thaipo and its joint venture partners signed a memorandum of understanding with PTT providing for the sale of crude oil and condensate to PTT at prices which fluctuate, based upon posted world prices, and which take into account the anticipated high quality of the production from Tantawan Field, and the field's close proximity to Thai markets.
MISCELLANEOUS
Other Assets
The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in seven pipelines (excluding field gathering pipelines) through which offshore hydrocarbon production is transported. In addition, the Company owns an approximately 19.3% interest in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to process up to 186 MMcf of natural gas and 5,478 Bbls of natural gas liquids per day. The plant is not currently operating at full capacity.
In 1989, the Company entered into a limited partnership agreement as general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo Gulf Coast"). As of December 31, 1996, Pogo Gulf Coast had interests in 5 federal offshore leases. The Company owns 40% of any interest in properties acquired by the limited part-
nership. Unless otherwise noted, the statistical data reported in this Annual Report reflect only the Company's share of Pogo Gulf Coast's holdings.
Sales
The marketing of offshore oil and gas production is subject to the availability of pipelines and other transportation, processing and refining facilities, as well as the existence of adequate markets. As a result, even if hydrocarbons are discovered in commercial quantities, a substantial period of time may elapse before commercial production commences. If pipeline facilities in an area are insufficient, the Company may have to await the construction or expansion of pipeline capacity before production from that area can be marketed. The Company's domestic offshore properties are generally located in areas where a pipeline infrastructure is well developed and there is adequate availability in such pipelines to handle the Company's current and projected future production.
The Company's concession in Thailand is traversed by two major (34 inches and 36 inches in diameter, respectively) natural gas pipelines that are owned and operated by PTT and which come within approximately 25 miles of the Tantawan Field (and are slightly closer to the Benchamas and Pakakrong Fields). Thaipo and its joint venture partners in the Tantawan Field signed a long term gas sales contract with PTT in November 1995 covering production from the Tantawan Field. In addition, in November 1996, Thaipo and its joint venture partners entered into a memorandum of understanding which provides that oil and condensate production from the Tantawan Field will initially be stored aboard the FPSO, sold to PTT and transferred to shore by means of oil tankers. See "-- International Operations; Contractual Terms Governing the Concession and Related Production."
The marketing of onshore oil and gas production is also subject to the availability of pipelines, crude oil hauling and other transportation, processing and refining facilities as well as the existence of adequate markets. Generally, the Company's onshore domestic oil and gas production is located in areas where commercial production of economic discoveries can be rapidly effectuated.
Most of the Company's domestic natural gas sales are currently made in the "spot market" for no more than one month at a time at then currently available prices. Prices on the spot market fluctuate with demand. Crude oil and condensate production is also generally sold one month at a time at the currently available prices. Other than any futures contracts which may exist from time to time, and which are referred to in "-- Miscellaneous; Competition and Market Conditions," and the gas sales contract for production from the Company's Concession in Thailand (see "-- International Operations; Contractual Terms Governing the Concession and Related Production"), the Company has no existing contracts that require the delivery of fixed quantities of oil or natural gas other than on a best efforts basis. See also "Financial Statements and Supplementary Data -- Note 4 to Notes to Consolidated Financial Statements and -- Unaudited Supplementary Financial Data."
Competition and Market Conditions
The Company experiences competition from other oil and gas companies in all phases of its operations, as well as competition from other energy related industries. The Company's profitability and cash flow are highly dependent upon the prices of oil and natural gas, which historically have been seasonal, cyclical and volatile. In general, prices of oil and gas are dependent upon numerous factors beyond the control of the Company, including various weather, economic, political and regulatory conditions. In the past, when natural gas prices in the United States were lower than they are currently, the Company at times elected to curtail certain quantities of its production. For example, in the fourth quarter of 1994 the Company curtailed a small portion of its daily natural gas production. As of March 1, 1997, the Company was not curtailing any of its natural gas production as a result of low natural gas prices. Should natural gas prices fall again in the future, the Company may again elect to curtail certain quantities of its natural gas production. Any significant decline in oil or gas prices could have a material adverse effect on the Company's operations and financial condition and could, under certain circumstances, result in a reduction in funds available under the Company's bank credit facility.
Because it is impossible to predict future oil and gas price movements with any certainty, the Company from time to time enters into contracts on a portion of its production to hedge against the volatility in oil and gas prices. Such hedging transactions, historically, have never exceeded 50% of the Company's total oil and gas production on an energy equivalent basis for any given period. While intended to limit the negative effect of price declines,
such transactions could effectively limit the Company's participation in price increases for the covered period, which increases could be significant. As of March 1, 1997, the Company was not a party to any natural gas futures contracts or crude oil swap agreements. When the Company does engage in such hedging activities, it may satisfy its obligations with its own production or by the purchase (or sale) of third party production. The Company may also cancel all delivery obligations by offsetting such obligations with equivalent agreements, thereby effecting a purely cash transaction.
Operating and Uninsured Risks
The Company's operations are subject to risks inherent in the exploration for and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution and other environmental risks. Offshore oil and gas operations are subject to the additional hazards of marine and helicopter operations, such as capsizing, collision and adverse weather and sea conditions. These hazards could result in substantial losses to the Company due to injury or loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company carries insurance which it believes is in accordance with customary industry practices, but is not fully insured against all risks incident to its business.
Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. The availability of a ready market for the Company's natural gas production depends on a number of factors, including the demand for and supply of natural gas, the proximity of natural gas reserves to pipelines, the capacity of such pipelines and government regulations.
Risks of Foreign Operations
Ownership of property interests and production operations in Thailand, and in any other areas outside the United States in which the Company may choose to do business, are subject to the various risks inherent in foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. The Company seeks to manage these risks by concentrating its international exploration efforts in areas where the Company believes that the existing government is stable and favorably disposed towards United States exploration and production companies. The Company believes that the Kingdom of Thailand currently presents favorable conditions in which to conduct international operations.
EXPLORATION AND PRODUCTION DATA
In the following data "gross" refers to the total acres or wells in which the Company has an interest and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company.
Acreage
The following table shows the Company's interest in developed and undeveloped oil and gas acreage as of December 31, 1996:
Developed Acreage (a) Undeveloped Acreage (b) --------------------- ----------------------- Gross Net Gross Net ----- --- ----- --- DOMESTIC ONSHORE Louisiana 869 209 28,072 9,373 New Mexico 21,246 11,882 54,354 39,119 Texas 13,676 4,987 90,597 37,452 Other 3,200 333 238 55 ------- ------- --------- ------- Total Domestic Onshore 38,991 17,411 173,261 85,999 ------- ------- --------- ------- DOMESTIC OFFSHORE Louisiana (State) 8,756 3,326 1,508 753 Louisiana (Federal)(c) 169,625 58,453 117,901 35,797 Texas (Federal) 46,080 11,819 17,280 8,640 ------- ------- --------- ------- Total Domestic Offshore 224,461 73,598 136,689 45,190 ------- ------- --------- ------- TOTAL DOMESTIC 263,452 91,009 309,950 131,189 ------- ------- --------- ------- INTERNATIONAL Thailand (Offshore) 67,995 31,510 1,283,561 406,461 ------- ------- --------- ------- TOTAL COMPANY 331,447 122,519 1,593,511 537,650 ======= ======= ========= ======= - ------------ (a) "Developed acreage" consists of lease acres spaced or assignable to production on which wells have been drilled or completed to a point that would permit production of commercial quantities of oil or natural gas.
(b) "Undeveloped acreage" includes acreage under lease or subject to lease or purchase options that the Company currently expects to exercise. Approximately 9% of the Company's total domestic offshore net undeveloped acreage is under leases that have terms expiring in 1997 (unless otherwise extended) and no domestic offshore undeveloped acreage will expire in 1998. Approximately 5% of the Company's total domestic onshore net undeveloped acreage is under leases that have terms expiring in 1997 (unless otherwise extended) and another approximately 10% of total domestic onshore net undeveloped acreage will expire in 1998 (unless otherwise extended). All of the Company's international undeveloped acreage must be relinquished to the Thai government in 1997 unless designated as a production area or unless the exploration term is extended as discussed above. See "Business -- International Operations; Contractual Terms Governing the Concession and Related Production."
(c) The Company also owns overriding royalty interests in one federal lease offshore Louisiana totaling 5,000 gross acres (1,250 net acres).
Drilling Activity and Productive Wells
The following table shows the number of successful gross and net exploratory and development wells in which the Company has participated and the number of gross and net wells abandoned as dry holes during the periods indicated. An onshore well is considered successful upon the installation of permanent equipment for the production of hydrocarbons or when electric logs run to evaluate such wells indicate the presence of commercial hydrocarbons and the Company currently intends to complete such wells. Successful offshore wells consist of exploratory or development wells that have been completed or are "suspended" pending completion (which has been determined to be feasible and economic) and exploratory test wells that were not intended to be completed and that encountered commercially producible hydrocarbons. A well is considered a dry hole upon reporting of permanent abandonment to the appropriate agency.
1996 1995 1994 --------------- --------------- --------------- Successful Dry Successful Dry Successful Dry ---------- --- ---------- --- ---------- --- GROSS WELLS: Offshore United States Exploratory 4.0 2.0 7.0 4.0 2.0 -- Development 17.0 3.0 3.0 1.0 25.0 2.0 Onshore United States Exploratory 12.0 4.0 8.0 1.0 3.0 6.0 Development 39.0 1.0 47.0 1.0 51.0 3.0 Offshore Kingdom of Thailand Exploratory 7.0 -- 3.0 -- 5.0 -- Development 16.0 -- 7.0 -- -- -- ---- --- ---- --- ---- ---- Total 95.0 10.0 75.0 7.0 86.0 11.0 ==== ==== ==== === ==== ====
1996 1995 1994 --------------- --------------- --------------- Successful Dry Successful Dry Successful Dry ---------- --- ---------- --- ---------- --- NET WELLS: Offshore United States Exploratory 1.7 1.5 3.0 1.6 0.6 -- Development 4.9 1.5 1.0 0.4 8.4 1.4 Onshore United States Exploratory 6.5 0.9 4.6 1.0 2.8 3.6 Development 24.4 0.7 31.3 0.1 29.9 0.9 Offshore Kingdom of Thailand Exploratory 2.4 -- 1.1 -- 1.6 -- Development 7.4 -- 3.2 -- -- -- ---- --- ---- --- ---- --- Total 47.3 4.6 44.2 3.1 43.3 5.9 ==== === ==== === ==== ===
As of December 31, 1996, the Company was participating in the drilling of 3 gross (1.3 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1 gross (0.3 net) wells offshore the Kingdom of Thailand.
The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 1996. Productive wells are producing wells plus wells "capable of production" (e.g., natural gas wells waiting for pipeline connections or necessary governmental certification to commence deliveries and oil wells waiting to be connected to production facilities).
Natural Oil Wells (a) Gas Wells (a) -------------- ------------- Gross Net Gross Net ----- ----- ----- ---- Offshore United States 180 46.0 178 58.8 Onshore United States 285 183.4 84 35.2 Kingdom of Thailand(b) -- -- 9 4.2 --- ----- --- ---- Total 465 229.4 271 98.2 === ===== === ====
- ---------- (a) One or more completions in the same bore hole are counted as one well. The data in the above table includes 25 gross (6.7 net) oil wells and 14 gross (5.7 net) natural gas wells with multiple completions.
(b) The number of wells set forth in this table as "capable of production" in Thailand does not include 9 gross (4.2 net) wells that had been drilled and were awaiting completion and connection at year end. All of such wells have subsequently been completed as productive wells during the first two months of 1997.
Production and Sales
The following table summarizes the Company's average daily production, net of all royalties, overriding royalties and other outstanding interests, for the periods indicated. Natural gas production refers only to marketable production of natural gas on an "as sold" basis.
1996 1995 1994 ---- ---- ---- PRODUCTION SALES: Natural Gas (Mcf per day) 107,700 121,000 144,800 ======= ======= ======= Liquid Hydrocarbons (Bbls per day) Crude Oil and Condensate 11,968 11,786 11,100 Natural Gas Liquids(a) 2,173 1,998 2,222 ------- ------- ------- Total Liquid Hydrocarbons 14,141 13,784 13,322 ======= ======= ======= - ---------- (a) Natural Gas Liquids production sales includes sales attributable to both the Company's leasehold and plant ownership.
The following table shows the average sales prices received by the Company for its production and the average production (lifting) costs per unit of production during the periods indicated. See "-- Miscellaneous; Competition and Market Conditions and Sales."
1996 1995 1994 ---- ---- ---- SALES PRICES: Natural Gas (per Mcf) $ 2.40 $ 1.63 $ 1.88 Crude Oil and Condensate (per Bbl) $22.12 $17.80 $16.08 Natural Gas Liquids (per Bbl) $14.92 $11.10 $11.33 PRODUCTION (LIFTING) COSTS(a): Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per Mcf equivalent) $ 0.53 $ 0.47 $ 0.36 - ---------- (a) Production costs were converted to common units of measure on the basis of relative energy content. Such production costs exclude all depletion and amortization associated with property and equipment.
Reserves
The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 1996, 1995, and 1994, and the present value as of such dates (based on an annual discount rate of 10%) of the estimated future net revenues from the production and sale of those reserves, as estimated by Ryder Scott in accordance with criteria prescribed by the Commission. The summary report of Ryder Scott on the reserve estimates, which includes definitions and assumptions, is set forth as an exhibit to this Annual Report and the definitions, assumptions and descriptions of methodology following the tables are based upon the Ryder Scott report.
As of December 31, --------------------------------- 1996 1995 1994 -------- -------- ------- TOTAL PROVED RESERVES: Oil, condensate, and natural gas liquids (MBbls) -- Located in the United States 28,270 26,185 26,188 Located in the Kingdom of Thailand 21,332 18,997 7,674 -------- -------- -------- Total Company 49,602 45,182 33,862 ======== ======== ======== Natural Gas (MMcf) -- Located in the United States 215,946 196,454 186,151 Located in the Kingdom of Thailand 144,998 131,607 56,739 -------- -------- -------- Total Company 360,944 328,061 242,890 ======== ======== ======== Present value of estimated future net revenues, before income taxes (in thousands)(a) -- Located in the United States $773,127 $400,845 $330,868 Located in the Kingdom of Thailand 181,418 131,630 52,112 -------- -------- -------- Total Company $954,545 $532,475 $382,980 ======== ======== ========
TOTAL DEVELOPED RESERVES: Oil, condensate, and natural gas liquids (MBbls) -- Located in the United States 25,898 22,488 24,670 Located in the Kingdom of Thailand 5,192 -- -- -------- -------- -------- Total Company 31,090 22,488 24,670 ======== ======== ======== Natural Gas (MMcf) -- Located in the United States 192,034 164,679 178,518 Located in the Kingdom of Thailand 45,998 -- -- -------- -------- -------- Total Company 238,032 164,679 178,518 ======== ======== ======== Present value of estimated future net revenues, before income taxes (in thousands)(a) -- Located in the United States $710,871 $359,984 $321,514 Located in the Kingdom of Thailand 69,062 -- -- -------- -------- -------- Total Company $779,933 $359,984 $321,514 ======== ======== ======== - ---------- (a) The Company believes, for the reasons set forth in suceeding paragraphs, that the present value of estimated future net revenues set forth in this Annual Report and calculated in accordance with Commission guidelines are not necessarily indicative of the true present value of the Company's reserves and, due to the fact that essentially all of the Company's domestic natural gas production is currently sold on the spot market, whereas all of the Company's Thai natural gas production is sold pursuant to a long term gas sales contract, such estimates of future net revenues from the Company's domestic and Thai reserves are not even useful for comparative purposes.
Natural gas liquids comprise approximately 8% of the Company's total proved liquids reserves and approximately 12% of the Company's proved developed liquids reserves. All hydrocarbon liquid reserves are expressed in standard 42 gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure and temperature basis of the area where the gas reserves are located.
Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (i) that portion delineated by drilling and defined by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data becomes available. Proved natural gas reserves are comprised of nonassociated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of liquids, for lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Reserves that can be produced economically through the application of established improved recovery techniques are included in the proved classification when these qualifications are met: (i) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (ii) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including, (i) pressure maintenance, (ii) cycling, and (iii) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Estimates of proved reserves do not include crude oil, condensate, natural gas, or natural gas liquids being held in underground storage. Depending on the status of development, these proved reserves are further subdivided into:
(i) "developed reserves" which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) "developed producing reserves" which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) "developed non-producing reserves" which are those proved developed reserves which exist behind casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of new wells; and
(ii) "undeveloped reserves" which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
The Company has interests in certain tracts which may have substantial additional hydrocarbon quantities which cannot be classified as proved and are not included herein. The Company has active exploratory and development drilling programs which in all likelihood will result in the reclassification of significant additional quantities to the proved category.
In computing future revenues from gas reserves attributable to the Company's domestic interests, prices in effect at December 31, 1996 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Commission guidelines, the gas prices that were used make no allowances for seasonal variations in gas prices which are likely to cause future yearly average gas prices to be
somewhat lower than December gas prices. For domestic gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. In computing future revenues from liquids attributable to the Company's domestic interests, prices in effect at December 31, 1996 were used and these prices were held constant to depletion of the properties. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves as well as any ad valorem and other severance taxes but do not include, unless otherwise noted, any provisions for corporate income taxes.
In computing future revenues from the Company's gas reserves attributable to the Company's interests in the Kingdom of Thailand, the current contract price under the gas sales agreement with PTT was used, without giving effect to any of the adjustments provided for in the gas sales agreement, due to their indeterminate nature as of December 31, 1996, in accordance with Commission guidelines. In computing future revenues from liquids attributable to the Company's interests in the Kingdom of Thailand, a price of $24.56 was used, which the Company believes approximates the price that the Company would have received for production from the Concession under the memorandum of understanding with PTT on December 31, 1996, if production had been sold to PTT on that date, and this price was held constant until depletion of the Company's reserves in the Kingdom of Thailand. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves and the Company's obligations under the Concession, including the payment of SRB and applicable production bonuses, but does not include, unless otherwise noted, any provisions for U.S. or Thai corporate income or other taxes.
The estimates of future net revenue from the Company's domestic and Thailand properties are based on existing law where the properties are located and are calculated in accordance with Commission guidelines. Operating costs for the leases and wells include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs are based on authorization for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. For properties located onshore, the estimates of future net revenues and the present value thereof do not consider the salvage value of the lease equipment or the abandonment cost of the lease since both are relatively insignificant and tend to offset each other. The estimated net cost of abandonment after salvage was considered for offshore properties where such costs net of salvage are significant.
No deduction was made for indirect costs such as general and administrative and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. Accumulated gas production imbalances, if any, have been taken into account.
Production data used to arrive at the estimates set forth above includes estimated production for the last few months of 1996. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allowables set by regulatory bodies. Properties which are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates.
The future prices received by the Company for the sales of its production may be higher or lower than the prices used in calculating the estimates of future net revenues and the present value thereof as set forth herein, and the operating costs and other costs relating to such production may also increase or decrease from existing levels; however, such possible changes in prices and costs were, in accordance with rules adopted by the Commission, omitted from consideration in arriving at such estimates.
There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of Ryder Scott, the Company's reserve engineers. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered.
The Company is periodically required to file estimates of its oil and gas reserve data with various U.S. governmental regulatory authorities and agencies, including the Federal Energy Regulatory Commission ("FERC") and the Federal Trade Commission and, with respect to reserves located in Thailand, the Kingdom of Thailand's Department of Mineral Resources. In addition, estimates are from time to time furnished to governmental agencies in connection with specific matters pending before such agencies. The basis for reporting reserves to these agencies, in some cases, is not comparable to that furnished above because of the nature of the various reports required. The major differences generally include differences in the time as of which such estimates are made, differences in the definition of reserves, requirements to report in some instances on a gross, net or total operator basis and requirements to report in terms of smaller geographical units. During 1996, no estimates by the Company of its total proved net oil and gas reserves were filed with or included in reports to any governmental authority or agency other than the Commission and, with respect to reserves relating to the Company's properties located in Thailand, the Kingdom of Thailand's Department of Mineral Resources.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying degrees by political developments and governmental laws and regulations. Rates of production of oil and gas have for many years been subject to governmental conservation laws and regulations, and the petroleum industry has been subject to federal and state tax laws dealing specifically with it.
Federal Income Tax
The Company's operations are significantly affected by certain provisions of the federal income tax laws applicable to the petroleum industry. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic "intangible drilling and development costs" and to claim depletion on a portion of its domestic oil and gas properties based on 15% of its oil and gas gross income from such properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas) even though the Company has little or no basis in such properties. Under certain circumstances, however, a portion of such intangible drilling and development costs and the percentage depletion allowed in excess of basis will be tax preference items that will be taken into account in computing the Company's alternative minimum tax.
Environmental Matters
Domestic oil and gas operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") also known as the "Superfund Law." The recent trend towards stricter standards in environmental legislation and regulation may continue, and this could increase costs to the Company and others in the industry. Regulations of the Department of the Interior currently impose absolute liability upon the lessee under a federal lease for the costs of clean-up of pollution resulting from a lessee's operations, and such lessee may also be subject to possible legal liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may, as it has in the past, also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.
The operators of the Company's properties have numerous applications pending before the Environmental Protection Agency (the "EPA") for National Pollution Discharge Elimination System water discharge permits with respect to offshore drilling and production operations. The issue generally involved is whether effluent discharges from each facility or installation comply with the applicable federal regulations.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. For tank vessels, including mobile offshore drilling rigs, the OPA imposes on owners, operators and charterers of the vessels, an obligation to maintain evidence of financial responsibility of up to $10,000,000 depending on gross tonnage. With respect to offshore facilities, proof of greater levels of financial responsibility may be applicable. For offshore facilities that have a worst case oil spill potential of more than 1,000 barrels (which includes many of the Company's offshore producing facilities), certain amendments to the OPA that were enacted in 1996 provide that the amount of financial responsibility that must be demonstrated for most facilities ranging from $10,000,000 to $35,000,000, depending upon location, with higher amounts, up to $150,000,000 in certain limited circumstances. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities at no significant increase in expense over recent prior years. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely effect the Company. The impact, however, should not be any more adverse to the Company that it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.
The Company's onshore operations are subject to numerous United States federal, state, and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment including CERCLA. Such laws and regulations, among other things, impose absolute liability on the lessee under a lease for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Federal, state and local initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these initiatives could have a similar impact on the Company.
The Company is asked to comment on the costs it incurred during the prior year on capital expenditures for environmental control facilities and the amount it anticipates incurring during the coming year. The Company believes that, in the course of conducting its oil an gas operations, many of the costs attributable to environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 1996, the Company incurred capital expenditures of approximately $1,971,000 for environmental control facilities, primarily relating to the completion of two salt water disposal facilities in New Mexico and the installation of certain environmental control facilities on two platforms installed in the Gulf of Thailand and on one platform installed in the Gulf of Mexico. The Company currently has budgeted approximately $1,240,000 for expenditures involving environmental control facilities during 1997, including, among other things, two salt water disposal facilities and environmental control equipment for one platform in the Gulf of Mexico.
Other Laws and Regulations
Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of oil and gas including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company's properties and to limit the allowable production from the successful wells completed on the Company's properties, thereby limiting the Company's revenues.
The MMS administers the oil and gas leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. In a letter dated May 3, 1993, the MMS announced a reinterpretation of its right to collect royalty payments from producers on certain settlements in which such producers and pipeline companies were involved a number of years ago. The MMS
reinterpretation has been challenged in court by various producers and trade groups representing them. On August 27, 1996, in Independent Petroleum Association of America, et al. v. Babbit et al., Nos. 95-5210 etc., the United States Court of Appeals for the District of Columbia Circuit held that the May 3, 1993, reinterpretation was invalid and unenforceable. Unless and until this or other similar cases are resolved in favor of the MMS' reinterpretation of its regulations, it is unlikely that the Company or other producers will be legally required to pay royalties on such settlement agreements. The Company was involved in several settlement agreements with pipelines that could be subject to the MMS' new reinterpretation. The MMS has reviewed the Company's and other producers' settlement agreements, to determine whether it believes any additional royalty payments may be due and has asserted that additional royalties may be due in connection with two of the Company's settlement agreements. Based upon existing case law, the Company has asserted through the administrative appeals process, and continues to believe, that it does not owe any additional royalties beyond what it has previously paid. However, in the event that the MMS is able to successfully assert that additional royalty is due from the Company in connection with settlement agreements to which the Company is a party, the Company does not currently believe that such additional assessment will have a material adverse impact on the financial position or results of operations of the Company.
The FERC has recently embarked on regulatory initiatives relating to its jurisdiction over rates for natural gas gathering services provided by interstate pipelines and to the availability of market-based and other alternative rate mechanisms to such pipelines for transmission and storage services. Among the FERC initiatives is a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. This negotiated/recourse rate policy has been challenged in the United States Court of Appeals for the of District of Columbia, and the appeal remains pending. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC's rate jurisdiction. Many of these orders have been challenged on rehearing to the FERC, and on appeal to the courts. The Company cannot predict the ultimate outcome of these developments, nor the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the gas prices received by the Company for the sale of its production, the FERC's actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated gas producers and sellers.
EMPLOYEES
As of December 31, 1996, the Company and its subisidiary Thaipo had 132 full-time employees, including eight in its Bangkok, Thailand office. None of the Company's employees are presently represented by a union for collective bargaining purposes. The Company considers its relations with its employees to be excellent.
ITEM 2.
ITEM 2. PROPERTIES.
The information appearing in Item 1 of this Annual Report is incorporated herein by reference.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company is a party to various other legal proceedings consisting of routine litigation incidental to its businesses, but believes that any potential liabilities resulting from these proceedings are adequately covered by insurance or are otherwise immaterial at this time. See "Business -- Government Regulation; Other Laws and Regulations."
ITEM 4.
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 March 1, 1997, and the year each was elected to his present position are as follows:
Year Executive Officer Executive Office Age Elected - ----------------------------------------------------------------------- Paul G. Van Wagenen Chairman of the Board, President and Chief Executive Officer 51 1991 Kenneth R. Good Corporate Senior Vice President 59 1996 Stuart P. Burbach Vice President and Offshore Division Manager 44 1991 Jerry A. Cooper Vice President and Western Division Manager 48 1990 John W. Elsenhans Vice President -- Finance and Treasurer 44 1995 Harvey L. Gold Vice President -- Engineering 61 1988 Thomas E. Hart Vice President and Controller 54 1988 R. Phillip Laney Vice President and International Division Manager 56 1991 John O. McCoy, Jr. Vice President and Chief Administrative Officer 45 1989 J. D. McGregor Vice President -- Sales 52 1988 Ronald B. Manning Vice President and General Counsel 43 1995 Sammie M. Shaw Vice President -- Operations 65 1992 Gerald A. Morton Corporate Secretary and Associate General Counsel 38 1995
Prior to assuming their present positions with the Company, the business experience of each executive officer for more than the last five years was as follows: Mr. Van Wagenen, who joined the Company in 1979, served as President and Chief Operating Officer of the Company since 1990; Mr. Good, who joined the Company in 1977, served as Senior Vice President -- Land and Budgets since 1991; Mr. Burbach, who rejoined the Company in 1991, was Vice President of Norfolk Holding Inc. from 1986 until rejoining the Company; Mr. Cooper served in various positions since joining the Company in 1979; Mr. Elsenhans was Director, Corporate Finance for the Company since 1991; Mr. Gold was Manager of Reservoir Engineering for the Company since joining the Company in 1977; Mr. Hart was Controller for the Company since joining the Company in 1977; Mr. Laney, who joined the Company in 1977, served as International Exploration Manager for the Company since 1983; Mr. McCoy served as Director of Personnel and Administration for the Company since joining the Company in 1978; Mr. McGregor was Manager of Hydrocarbon Sales and Contracts for the Company since joining the Company in 1981; Mr. Manning, who joined the Company in 1987, was Corporate Secretary and an Associate General Counsel for the Company since 1990; Mr. Shaw was Operations Manager for the Company since joining the Company in 1981; Mr. Morton was an Associate General Counsel for the Company since 1993 and prior thereto was an attorney with the law firm of Weil, Gotshal & Manges since 1988.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS.
The following table shows the range of low and high sales prices of the Company's Common Stock (the "Common Stock") on the New York Stock Exchange composite tape where the Company's common stock trades under the symbol PPP. The Company's common stock is also listed on the Pacific Stock Exchange.
Low High --- ---- 1st Quarter 16 20 1/2 2nd Quarter 19 1/2 25 3/8 3rd Quarter 21 1/8 25 4th Quarter 19 3/8 29
1st Quarter 24 3/8 34 3/4 2nd Quarter 31 3/8 38 1/4 3rd Quarter 32 1/4 38 3/4 4th Quarter 35 3/4 48 3/8
As of March 10, 1997, there were 3,141 holders of record of the Company's Common Stock.
In each of 1995 and 1996, the Company paid four quarterly dividends of $0.03 per share on its Common Stock. In this regard, the Company reinstated the practice of declaring a quarterly cash dividend commencing in the third quarter of 1994. However, the declaration and payment of future dividends will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors.
Pursuant to the Company's revolving credit agreement with its banks under which the Company has borrowed funds, the Company may not, subject to certain exceptions, pay any dividends on its capital stock or make any other distributions on shares of its capital stock (other than dividends or distributions payable solely in shares of such capital stock) or apply any funds, property or assets to the purchase, redemption, sinking fund or other retirement of its capital stock, if the aggregate amount of all such dividends, purchases, and redemptions would exceed an amount determined based on the consolidated income of the Company and its consolidated subsidiaries from and after a specified date plus the proceeds of the issuance of capital stock after the same specified date or if the net worth of the Company is negative. As of December 31, 1996, $98,659,000 was available for dividends under this limitation.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
The Company reported net income for 1996 of $32,760,000 or $0.96 per share ($35,843,000 or $0.94 per share on a fully diluted basis) compared to net income for 1995 of $9,230,000 or $0.28 per share (on both a primary and a fully diluted basis) and net income for 1994 of $27,067,000 or $0.81 per share (on both a primary and a fully diluted basis). The Company recorded extraordinary losses of $307,000 during the second quarter of 1994 related to the early retirement of the Company's 10.25% Convertible Subordinated Notes, due 1999 (the "10.25% Notes") with the proceeds from the Company's issuance on March 16, 1994, of its 5-1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes") and $821,000 during the second quarter of 1996 related to the early retirement of the Company's 8% Convertible Subordinated Debentures, due 2005 (the "8% Debentures") with the proceeds from the Company's issuance on June 18, 1996, of its 5-1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes").
Earnings per common share are based on the weighted average number of common and common equivalent shares outstanding for 1996 of 34,034,000 (37,951,000 on a fully diluted basis), compared to 33,490,000 (on both a primary and a fully diluted basis) for 1995 and 33,352,000 (36,451,000 on a fully diluted basis) for 1994. The yearly increases in the weighted average number of common and common equivalent shares outstanding resulted primarily from the issuance of shares of common stock upon the exercise of stock options pursuant to the Company's stock option plans. Earnings per common share computations on a fully diluted basis primarily reflect additional common shares issuable upon the assumed conversion of the Company's 2004 Notes in 1994 and 1996 (the only convertible securities of the Company that were dilutive during the applicable periods) and the elimination of related interest requirements, as adjusted for applicable federal income taxes. Earnings applicable to common stock for 1994, assuming full dilution, was $29,448,000. However, the dilution resulting from the assumed conversion of the 2004 Notes in 1994 was not sufficient to change reported earnings per share in 1994.
The Company's total revenues for 1996 were $203,977,000, an increase of approximately 29% from total revenues of $157,559,000 for 1995, and an increase of approximately 17% from total revenues of $173,608,000 for 1994. The increase in the Company's total revenues for 1996, compared to 1995 and 1994, resulted primarily from the substantial increase in prices that the Company received for its natural gas and liquid hydrocarbon (including crude oil, condensate and natural gas liquid ("NGL")) production volumes and, to a lesser extent, an increase in the Company's liquid hydrocarbon production volumes, which was only partially offset by a decline in the Company's natural gas production volumes.
The Company's oil and gas revenues for 1996 were $204,142,000, an increase of approximately 30% from oil and gas revenues of $157,459,000 for 1995, and an increase of approximately 18% from oil and gas revenues of $173,556,000 for 1994. The following table reflects an analysis of variances in the Company's oil and gas revenues between 1996 and the previous two years:
1996 Compared To ----------------------- 1995 1994 ---- ---- (Expressed in thousands) Increase (decrease) in oil and gas revenues resulting from variances in: Natural Gas Price $ 33,907 $ 27,685 Production (11,350) (32,189) -------- -------- 22,557 (4,504) -------- -------- Crude oil and condensate Price 18,614 24,486 Production 1,737 7,281 -------- -------- 20,351 31,767 -------- -------- Natural gas liquids ("NGL") and other, net 3,775 3,323 -------- -------- Total increase in oil and gas revenues $ 46,683 $ 30,586 ======== ========
The average price that the Company received for its natural gas production during 1996 averaged $2.40 per Mcf. The average price that the Company received for its natural gas production in 1996 compared favorably with the average price that the Company had received during the preceding two years of $1.63 per Mcf for 1995 (an increase of approximately 47%) and $1.88 per Mcf for 1994 (an increase of approximately 28%). The Company's natural gas production for 1996 averaged 107.7 MMcf per day, a decrease of approximately 11% from average production of 121 MMcf per day in 1995, and a decrease of approximately 26% from average production of 144.8 MMcf per day for 1994. The decrease in the Company's average natural gas production for 1996, compared to 1995 and 1994, resulted primarily from the difference between the high initial natural gas production rates from horizontal wells drilled from the Company's Eugene Island Block 295 "B" platform which commenced in late February 1994 and the subsequent natural production decline from those reservoirs, the slowdown of development drilling, workover and recompletion work on certain of the Company's non-operated properties in the Gulf of Mexico, largely due to a decrease in planned drilling by the operators of such properties and production curtailments due to adverse weather conditions (and drilling and workover operations on certain of the Company's properties), along with the natural decline in deliverability from certain of the Company's more mature properties. Those decreases were only partially offset by new and increased production from the Company's continued offshore drilling and workover program. As of March 1, 1997, the Company was not a party to any natural gas futures contracts.
Crude oil and condensate prices received by the Company averaged $22.12 per barrel in 1996, an increase of approximately 24% compared to an average of $17.80 per barrel in 1995, and an increase of approximately 38% compared to an average price of $16.08 per barrel that the Company received in 1994. Crude oil and condensate production for 1996 averaged 11,968 Bbls per day, an increase of approximately 2% from 11,786 Bbls per day for 1995, and an increase of approximately 8% from 11,100 Bbls per day for 1994. The increase in the Company's crude oil and condensate production for 1996, compared to 1995 and 1994, resulted primarily from ongoing development drilling and workover programs in the Gulf of Mexico and in Lea and Eddy Counties of southeastern New Mexico, which was only partially offset by the slowdown of development drilling, workover and recompletion work on certain of the Company's non-operated properties in the Gulf of Mexico, largely due to a decrease in planned drilling by the operators of such properties and production curtailments due to adverse weather conditions (and drilling and workover operations on certain of the Company's properties), along with the natural decline in deliverability from certain of the Company's more mature properties. As of March 1, 1997, the Company was not a party to any crude oil swap agreements.
Liquid products are often extracted from natural gas streams and sold separately as NGL. In addition, the Company's oil and gas revenues for 1996, 1995 and 1994 also reflect adjustments for various miscellaneous items. The Company's NGL and other, net revenues for 1996 increased $3,775,000 from those reported in 1995, and $3,323,000 from those reported in 1994. The increase in NGL and other, net revenues in 1996, compared with 1995 and 1994, primarily related to an increase in the price that the Company received for its NGL production volumes and, to a lesser extent, an increase in such production volumes.
The Company's average liquid hydrocarbon (including crude oil, condensate and NGL) production during 1996 was 14,141 Bbls per day, an increase of approximately 3% from an average total liquids production of 13,784 Bbls per day for 1995, and an increase of approximately 6% from an average total liquids production of 13,322 Bbls per day for 1994.
The Company currently anticipates that its ongoing exploration and development drilling program during 1996, both domestically and in the Gulf of Thailand, should lead to substantially increased production during 1997. In particular, the Company currently anticipates that production from its interest in the Tantawan Field, which came on production in early February 1997, and two wells drilled from the East Cameron Block 334 "E" platform should contribute a substantial amount of new production to the Company's total natural gas and liquid hydrocarbon production volumes by mid-1997. See "Business -- Domestic Offshore Operations; Significant Offshore Operating Areas During 1996; East Cameron, and -- International Operations; Significant International Operating Areas During 1996; Tantawan Field."
Lease operating expenses for 1996 were $37,628,000, an increase of approximately 7% from lease operating expenses of $35,071,000 for 1995, and an increase of approximately 26% from lease operating expenses of $29,768,000 for 1994. The increase in lease operating expenses for 1996, compared to 1995 and 1994, resulted primarily from increased costs to the Company (and the entire offshore oil industry) because of an increasing short-
age of qualified offshore service contractors, which has permitted such contractors to increase the costs of their services significantly in the last year, a year to year increase in the level of the Company's operating activities, including increased operating costs related to additional properties brought on production and an increased ownership interest in certain properties as a result of the acquisition of such interests. To a lesser extent, lease operating expenses for 1996, compared to 1995 and 1994, also increased as a result of a general maintenance and repair program that was undertaken on many of the Company's operated properties, for which no corresponding offsets of such magnitude existed in the comparable prior periods.
General and administrative expenses for 1996 were $18,028,000, an increase of approximately 10% from general and administrative expenses of $16,400,000 for 1995, and an increase of approximately 13% from general and administrative expenses of $15,984,000 for 1994. The increase in general and administrative expenses for 1996, compared to 1995 and 1994, was related to, among other things, the costs associated with the establishment of a Company office in Bangkok, Thailand in connection with the Company's development project and other activities in the Gulf of Thailand, an increase in the number of Company employees resulting from the Company's increased exploration and production related activities and to normal salary and concomitant benefit expense adjustments.
Exploration expenses consist primarily of delay rentals and geological and geophysical costs which are expensed as incurred. Exploration expenses for 1996 were $16,777,000, an increase of approximately 125% from exploration expenses of $7,468,000 for 1995, and an increase of approximately 219% from exploration expenses of $5,257,000 for 1994. The increase in exploration expenses for 1996, compared to 1995 and 1994, resulted primarily from increased geophysical activity by the Company, including the costs of conducting and processing certain proprietary 3-D seismic surveys on its domestic onshore and offshore properties, as well as in the Gulf of Thailand, together with the cost of acquiring several non-proprietary 3-D seismic surveys in the Gulf of Mexico. In addition, a portion of the increase in exploration expenses was attributable to increased delay rental expense resulting from the Company's acquisition of additional prospective oil and gas acreage. While increases in the Company's exploration expenses are a component of, and generally correlate fairly closely with, increases in the Company's capital and exploration budget, the Company does not currently expect its exploration expenses in 1997 to increase significantly over those incurred in 1996.
Dry hole and impairment expenses relate to costs of unsuccessful wells drilled along with impairments due to decreases in expected reserves from producing wells. The Company's dry hole and impairment expenses for 1996 were $8,579,000, an increase of approximately 28% from dry hole and impairment costs of $6,703,000 for 1995, and an increase of approximately 21% from dry hole and impairment costs of $7,088,000 for 1994.
The Company accounts for its oil and gas activities using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred.
The provision for depreciation, depletion and amortization ("DD&A") is based on capitalized costs as determined in the preceding paragraph, plus future costs to abandon offshore wells and platforms, and is determined on a cost center by cost center basis using the units of production method. The Company's DD&A expense for 1996 was $61,857,000, a decrease of approximately 10% from DD&A expenses of $68,489,000 for 1995, and a decrease of approximately 2% from DD&A expenses of $63,308,000 for 1994. The decrease in the Company's DD&A expenses for 1996, compared to 1995, resulted primarily from a decrease in the Company's composite DD&A rate and from a decrease in the Company's natural gas production. The decreases in the Company's DD&A expenses for 1996, compared to 1994, resulted primarily from a decrease in the Company's natural gas production, partially offset by an increase in the Company's composite DD&A rate. The composite DD&A rate for all of the Company's producing fields for 1996 was $0.87 per equivalent Mcf ($5.20 per equivalent barrel), a decrease of approximately 4% from a composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent barrel) for 1995, but an increase of approximately 13% from a composite DD&A rate of $0.77 per equivalent Mcf ($4.59 per equivalent barrel) for 1994. The Company produced 70,472,000 equivalent Mcf (11,745,000 equivalent Bbls) in 1996, a decrease of approximately 5% from the 74,337,000 equivalent Mcf (12,389,000 equivalent Bbls) produced in 1995, and a decrease of approximately 14% from the 82,008,000 equivalent Mcf (13,668,000 equivalent Bbls) produced in 1994. See "Financial Statements and Supplementary Data --Note 1 of Notes to Consolidated Financial Statements."
Interest charges for 1996 were $13,203,000, an increase of approximately 18% from interest charges of $11,167,000 for 1995, and an increase of approximately 31% from interest charges of $10,104,000 for 1994. The increase in the Company's interest charges for 1996, compared to 1995 and 1994, resulted primarily from an increase in the amount of debt outstanding that was only partially offset by, among other things, a decrease in the average interest rate paid by the Company on its debt. Capitalized interest for 1996 was $4,244,000, an increase of approximately 131% from capitalized interest of $1,834,000 for 1995, and an increase of approximately 474% from capitalized interest of $739,000 for 1994. The increase in the amount of interest capitalized by the Company in 1996, compared to 1995 and 1994, related primarily to the capitalization of interest expenses resulting from the engineering, acquisition and construction of facilities and equipment for the Company's Tantawan Field and the Company's East Cameron 334/335 Block "D" platform (both of which commenced in 1995) and the Company's East Cameron 334/335 Block "E" platform (commencing in 1996). See "Business -- Domestic Offshore Operations; Significant Offshore Operating Areas During 1996; East Cameron."
As of March 1, 1997, the Company was a party to an interest rate swap agreement. The swap agreement, which terminates on March 10, 1998, effectively changes the interest rate paid by the Company on $5,000,000 of debt from a market based variable rate to a fixed rate of 7.2%.
Income tax expense for 1996 was $18,800,000, an increase of approximately 284% from income tax expense of $4,891,000 for 1995, and an increase of approximately 21% from income tax expense of $15,517,000 for 1994. The increase in income tax expense for 1996, compared to 1995 and 1994, resulted primarily from increased pretax income.
LIQUIDITY AND CAPITAL RESOURCES
The Company's Consolidated Statement of Cash Flows for the year ended December 31, 1996, reflects net cash provided by operating activities of $92,898,000. In addition to the net cash provided by operating activities, the Company also received $3,378,000 from the exercise of stock options, had net borrowings of $7,000,000 under its revolving credit agreement and uncommitted money market credit lines with certain banks and received net proceeds totaling $111,884,000 from the offering of the 2006 Notes. The Company invested $172,032,000 of such cash flow in capital projects during 1996, paid $40,699,000 to redeem its 8% Debentures and paid $3,979,000 ($0.03 per share for four quarters) in cash dividends to holders of the Company's common stock. Of the $172,032,000 invested in capital projects, $35,254,000 was applicable to 1995 projects and $136,778,000 was applicable to 1996 capital projects. The Company's total debt at December 31, 1996, was $246,230,000. As of December 31, 1996, the Company had $3,054,000 in cash and cash investments.
The Company's capital and exploration budget for 1996, which does not include any amounts which may be expended for the purchase of proved reserves or any interest which may be capitalized resulting from projects in progress, has been established by the Company's Board of Directors at $210,000,000, an increase of approximately 2% from the Company's capital and exploration expenditures (excluding purchased reserves and interest capitalized) of $206,267,000 for 1996, an increase of approximately 113% over capital and exploration expenditures (excluding purchased reserves and interest capitalized) of $98,560,000 for 1995, and an increase of approximately 139% over capital and exploration expenditures (excluding purchased reserves and interest capitalized) of approximately $88,300,000 for 1994.
In addition to anticipated capital and exploration expenditures, other material 1997 cash requirements that the Company currently anticipates include ongoing operating, general and administrative, income tax, and interest expenses and the payment of dividends on its common stock, including a $0.03 per share dividend on its common stock paid on February 21, 1997, to stockholders of record on February 7, 1997. The Company currently anticipates that cash provided by operating activities, funds available under its Credit Agreement, uncommitted money market credit lines and amounts that the Company currently believes it can raise from external sources, will be sufficient to fund the Company's ongoing expenses, acquisitions, its 1997 capital and exploration budget and anticipated future dividend payments. In this regard, the Company reinstated the practice of declaring a quarterly cash dividend commencing in the third quarter of 1994. However, the declaration and payment of future dividends will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors.
Effective June 1, 1995, the Company entered into an amended and restated credit agreement (the "Credit Agreement") with the same banks that were parties to the credit agreement that it superseded. The Credit Agreement provides for an unsecured $150,000,000 revolving/term credit facility which will be fully revolving until January 1, 1998, after which the balance will be due in eight quarterly term loan installments, commencing April 30, 1998. However, the Company has established a history of refinancing its bank debt before scheduled maturity payments commence and expects to do so again before the amortization of the amounts due under the Credit Agreement which commences in 1998. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base, determined semiannually by the lenders in accordance with the Credit Agreement, based on the discounted present value of future net revenues from certain of the Company's oil and gas reserves and the provisions of the Credit Agreement. As of March 1, 1997, the borrowing base exceeded $150,000,000. The Credit Agreement is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, and limitations on indebtedness, creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. See "Market for the Registrant's Common Stock and Related Security Holder Matters." In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Agreement currently bear interest at a base (prime) rate, a certificate of deposit rate plus 1-1/8%, or LIBOR plus 1%, at the Company's option. A commitment fee on the unborrowed amount under the Credit Agreement is also charged. The commitment fee is 5/16 of 1% per annum on the unborrowed amount under the Credit Agreement that is designated as "active" and 1/8 of 1% per annum on the unborrowed amount under the Credit Agreement that is designated as "inactive." Of the $150,000,000 that is currently available under the Credit Agreement (subject to borrowing base limitations), $100,000,000 is designated as "active" and $50,000,000 is designated as "inactive."
The Company has also entered into separate letter agreements with two banks under which each bank may provide a $10,000,000 uncommitted money market line of credit. The two lines of credit are on an as available or offered basis and neither bank has an obligation to make any advances under its respective line of credit. Although loans made under these letter agreements are for a maximum term of 30 days, they are reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under its Credit Agreement. Both letter agreements permit either party to terminate such letter agreement at any time. Under its Credit Agreement, the Company is currently limited to incurring a maximum of $10,000,000 of additional senior debt, which would include debt incurred under these lines of credit. As of December 31, 1996, indebtedness in the principal amount of $45,000,000 was outstanding under the Credit Agreement and the two letter agreements.
The outstanding principal amount of the 2004 Notes was $86,230,000 as of December 31, 1996. The 2004 Notes are convertible into Common Stock at $22.188 per share, subject to adjustment upon the occurrence of certain events. The 2004 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after March 15, 1998, at a redemption price of 103.3% of their principal amount and decreasing percentages thereafter. No sinking fund payments are required on the 2004 Notes. The 2004 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change of control and other circumstances as defined in the indenture governing the 2004 Notes), at 100% of the principal amount.
The outstanding principal amount of the 2006 Notes was $115,000,000 as of December 31, 1996. The 2006 Notes are convertible into Common Stock at $42.185 per share, subject to adjustment upon the occurrence of certain events. The 2006 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% of their principal amount and decreasing percentages thereafter. No sinking fund payments are required on the 2006 Notes. The 2006 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change of control and other circumstances as defined in the indenture governing the 2006 Notes), at 100% of the principal amount.
As of February 9, 1996, Tantawan Services, LLC ("TS"), a company that is currently a wholly owned subsidiary of the Company, entered into a Bareboat Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter of a FPSO for use in the Tantawan Field. See "Business -- International Operations." The term of the Charter is for a period ending July 31, 2008, subject to extension. In addition, TS has a purchase option on the FPSO throughout the term of the Charter. The Charter currently provides for an estimated charter hire commitment of
$24,000,000 per year ($11,122,000 net to Thaipo), commencing upon its installation in the field. TS has also contracted with another company, SBM Marine Services (Thailand) Ltd., to operate the FPSO on a reimbursable basis throughout the initial term of the Charter. Performance of both the Charter and the agreement to operate the FPSO are non-recourse to TS and the Company. However, performance is secured by a negative pledge on any hydrocarbons stored on the FPSO and is guaranteed by each of the working interest holders in the Tantawan Field, including Thaipo. Thaipo's guarantee is limited to its percentage interest in the Tantawan Field (currently 46.34%).
OTHER MATTERS
Publicly held companies are asked to comment on the effects of inflation on their business. Currently annual inflation in terms of the decrease in the general purchasing power of the dollar is running much below the general annual inflation rates experienced in the past. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the dollar, such effect is not currently considered significant.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1996
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Pogo Producing Company:
We have audited the accompanying consolidated balance sheets of Pogo Producing Company (a Delaware corporation) and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pogo Producing Company and subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas February 3, 1997
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
The accompanying notes to consolidated financial statements are an integral part hereof.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations -
Pogo Producing Company was incorporated in 1970. Pogo Producing Company and its subsidiaries (the "Company") are engaged in oil and gas exploration, development and production activities on its properties located offshore in the Gulf of Mexico, onshore in the United States and internationally in the Gulf of Thailand. The Company has interests in 86 lease blocks offshore Louisiana and Texas, approximately 212,000 gross acres onshore in the United States and approximately 1,300,000 gross acres offshore in the Kingdom of Thailand.
Use of Estimates -
The preparation of these financial statements requires the use of certain estimates by management in determining the Company's assets, liabilities, revenues and expenses. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of proved oil and gas reserves. There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of crude oil, condensate, natural gas and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions.
Principles of Consolidation -
The consolidated financial statements include the accounts of Pogo Producing Company and its subsidiary and affiliated companies, after elimination of all significant intercompany transactions.
Inventories -
Inventories consist primarily of tubular goods used in the Company's operations and are stated at the lower of average cost or market value.
Interest Capitalized -
Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until production commences if the projects are evaluated as successful.
Earnings per Share -
Earnings per common and common equivalent share (primary earnings per share) are based on the weighted average number of shares of Common Stock and common equivalent shares outstanding during the periods. The dilutive effect of stock options was considered in the earnings per share reported for the periods. The 8% Debentures (retired on June 28, 1996) were common stock equivalents and were anti-dilutive in all periods in which they were outstanding. Earnings per common and common equivalent share assuming full dilution (fully diluted earnings per share) considered the 10.25% Notes (retired on April 18, 1994) which were anti- dilutive in all periods in which they were outstanding, the 2004 Notes (issued on March 16, 1994) which were dilutive for the portion of 1994 in which they were outstanding (such dilution was not sufficient to change reported earnings per share) and anti-dilutive for 1995, and dilutive in 1996, the 2006 Notes (issued June 18, 1996) were anti-dilutive in the 1996 period they were outstanding. Earnings per share are based on the following:
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Production Imbalances -
Owners of an oil and gas property often take more or less production from a property than entitled to based on their ownership percentages in the property. This results in a condition known in the industry as a production imbalance. The Company follows the "take" (cash) method of accounting for production imbalances. Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers. The Company's crude oil imbalances are not significant. At December 31, 1996, the Company had taken approximately 3,850 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 1,963 MMcf more than its entitlement on other properties placing the Company at year end in a net under-delivered position of approximately 1,887 MMcf of natural gas based on its working interest ownership in the properties.
Oil and Gas Activities and Depreciation, Depletion and Amortization -
The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above, plus future costs to abandon offshore wells and platforms, and is determined on a cost center by cost center basis using the units of production method.
Other properties are depreciated using a straight-line method in amounts which in the opinion of management are adequate to allocate the cost of the properties over their estimated useful lives.
Consolidated Statements of Cash Flows -
For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and as such will not be disclosed in the Consolidated Statements of Cash Flows. Certain such noncash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to shares issued in connection with the Long- Term Incentive Plan and the conversion of debentures into Common Stock in 1996.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Commitments and Contingencies -
The Company has commitments for operating leases for office space in Houston, Midland and Bangkok and a commitment for an operating lease for a floating production, storage and off-loading vessel (FPSO) in the Gulf of Thailand. Rental expense for office space was $1,054,000 in 1996, $861,000 in 1995, and $819,000 in 1994. Lease payments for the FPSO will commence in 1997. Future minimum lease payments (in thousands of dollars) at December 31, 1996 are as follows:
1997............................ $11,535 1998............................ 12,499 1999............................ 12,383 2000............................ 12,316 2001............................ 12,286
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three years in the period ended December 31, 1996, are as follows (expressed in thousands):
1996 1995 1994 ------- ------- ------- United States........... $56,380 $16,899 $44,931 Foreign................. (3,999) (2,778) (2,040) ------- ------- ------- Total................ $52,381 $14,121 $42,891 ======= ======= =======
The components of federal income tax expense (benefit) for each of the three years in the period ended December 31, 1996, are as follows (expressed in thousands):
1996 1995 1994 ------- ------- ------- United States, current......... $12,500 $ -- $ 7,500 United States, deferred (a).... 7,162 5,602 8,374 Foreign, current............... (862) (711) (357) ------- ------- ------- Total....................... $18,800 $ 4,891 $15,517 ======= ======= =======
(a) Excludes $443,000 and $165,000 in 1996 and 1994, respectively, of deferred tax benefits on extraordinary losses of $1,264,000 and $472,000 in 1996 and 1994, respectively.
Total federal income tax expense (benefit) for each of the three years in the period ended December 31, 1996, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as a percent of pretax income):
1996 1995 1994 ---- ----- ----- Federal statutory income tax rate............... 35.0% 35.0% 35.0% Increases (reductions) resulting from: Statutory depletion in excess of tax basis... (0.2) (2.2) (0.1) Foreign taxes................................ 1.1 1.6 0.9 Other........................................ -- 0.2 0.4 ---- ---- ---- 35.9% 34.6% 36.2% ==== ==== ====
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The deferred federal income tax provision is the result of the difference between deferred tax liabilities determined at each balance sheet date. The deferred tax liabilities are determined by applying current tax laws to temporary differences in the recognition of revenue and expense for tax and financial purposes. The principal components of the Company's deferred income tax liability include the following at December 31, 1996 and 1995 (expressed in thousands):
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1996 and 1995, consists of the following (dollars expressed in thousands):
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Effective June 1, 1995, the Company entered into an amended and restated bank revolving credit agreement (the "Credit Agreement") which extends to the Company an unsecured $150,000,000 revolving/term credit facility. The Credit Agreement will be fully revolving until January 1, 1998 and will convert to a term loan with eight quarterly installments commencing April 30, 1998. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base determined semiannually by the lenders in accordance with the Credit Agreement based on the discounted present value of future net revenue from certain of the Company's oil and gas reserves and the provisions of the Credit Agreement. The borrowing base currently exceeds $150,000,000. The Credit Agreement is governed by various financial covenants including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge ratio, and limitations on indebtedness, creation of liens, the pre- payment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Agreement bear interest at a base (prime) rate, certificate of deposit rate plus 1-1/8%, or LIBOR plus 1%, at the Company's option. A commitment fee on the unborrowed amount under the Credit Agreement is also charged. The commitment fee is 5/16 of 1% per annum on the unborrowed amount under the "active" portion of the Credit Agreement and 1/8 of 1% per annum on the unborrowed amount of the "inactive" portion of the Credit Agreement. Of the $150,000,000 that is currently available under the Credit Agreement (subject to borrowing base limitations), $100,000,000 is designated as "active" and $50,000,000 is designated as "inactive." The Company incurred commitment fees of $271,000 in 1996, $352,000 in 1995, and $409,000 in 1994 under this and a prior revolving credit agreement.
The Company has also entered into separate letter agreements with two banks under which each bank may provide a $10,000,000 uncommitted money market line of credit. The two lines of credit are on an as available or offered basis and the banks have no obligations to make any advances under the lines. Loans made under the agreements are for a maximum term of 30 days and are reflected as long-term debt as the Company has the intent and ability to reborrow such amounts under its bank revolving credit agreement discussed above. The agreements may be terminated at any time by the Company or either bank.
The 5-1/2% Convertible Subordinated Notes due 2004 (the "2004 Notes") are convertible into Common Stock at $22.188 per share subject to adjustment upon the occurrence of certain events. The 2004 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after March 15, 1998, at a redemption price of 103.3% and decreasing percentages thereafter. No sinking fund is provided. The 2004 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount.
On June 18, 1996 the Company issued $115,000,000 of 5-1/2% Convertible Subordinated Notes due 2006 ("the 2006 Notes"). The 2006 Notes are convertible into common stock of the Company at a price of $42.185 per share. The proceeds from the issuance of the 2006 Notes were used to retire the Company's 8% Convertible Subordinated Debentures due 2005 (the "8% Debentures"), to repay amounts outstanding under the Company's bank revolving credit agreement and uncommitted lines of credit with banks, and to purchase short-term cash investments. The 2006 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% and decreasing percentages thereafter. No sinking fund is provided. The 2006 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount.
Current maturities and sinking fund requirements during the next five years in connection with the above long-term debt are none in 1997, $20,250,000 in 1998, $15,750,000 in 1999, $9,000,000 in 2000 and none in 2001. All of the current maturities reflected above are related to retirement of the Company's bank debt. The Company has established a history of refinancing its bank debt before scheduled maturity payments commence and expects to do so again before the amortization of bank debt commences in 1998.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that generally sells its oil and gas to numerous customers on a month-to-month basis. Sales to the following customers exceeded 10% of revenues during any one of the three years indicated (expressed in thousands):
1996 1995 1994 ------- ------- ------- Enron Corp. and affiliates......... $58,101 $42,895 $27,630 Coastal Gas Marketing Company...... $18,376 $18,117 $27,609 Scurlock Oil Company............... $ 240 $ 1,757 $21,134
(5) CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1996 and 1995, result from oil and gas sales and joint interest billings to other companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarily affected by industry- wide changes in economic or other conditions. Such receivables are generally not collateralized. Historically, credit losses incurred by the Company on receivables generally have not been material. No known material credit losses were experienced during 1996 or 1995.
(6) EMPLOYEE BENEFITS
The Company's stock option plans authorize the granting of options to key employees and non-employee directors at prices equivalent to the market value at the date of grant. Options generally become exercisable in three annual installments commencing one year after the date of grant and, if not exercised, expire 10 years from the date of grant. In 1996, the Company adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 123, Accounting For Stock-Based Compensation ("SFAS No. 123"). As permitted by SFAS No. 123, the Company elected to continue to account for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, the adoption of SFAS No. 123 in 1996 had no effect on the Company's results of operations. A summary of the status of the Company's plans as of December 31, 1996, 1995, and 1994, and changes during the years ended on those dates is presented below:
Weighted Number Average of Exercise Options Price --------- ---------- Outstanding, December 31, 1993 1,490,676 $ 9.32 Granted 291,000 $21.77 Exercised (376,639) $ 9.76 Forfeited or expired (17,500) $16.25 --------- Outstanding, December 31, 1994 1,387,537 $11.72 ========= Exercisable, December 31, 1994 957,455 $ 8.86 ========= Available for grant, December 31, 1994 2,088,893 =========
Outstanding, December 31, 1994 1,387,537 $11.72 Granted 389,000 $22.34 Exercised (181,136) $ 9.48 Forfeited or expired (20,000) $14.88 ========= Outstanding, December 31, 1995 1,575,401 $14.56 ========= Exercisable, December 31, 1995 1,006,686 $10.87 ========= Available for grant, December 31, 1995 1,719,893 ========= Weighted-average fair value of options granted during 1995 $ 8.77
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Weighted Number Average of Exercise Options Price --------- ---------- Outstanding, December 31, 1995 1,575,401 $14.56 Granted 406,500 $34.59 Exercised (274,714) $12.30 --------- Outstanding, December 31, 1996 1,707,187 $19.70 ========= Exercisable, December 31, 1996 1,077,658 $14.31 ========= Available for grant, December 31, 1996 1,313,393 ========= Weighted-average fair value of options granted during 1996 $13.56
The following table summarizes information about stock options outstanding at December 31, 1996:
Options Outstanding Options Exercisable ----------------------------------- ---------------------- Weighted Average Remaining Weighted Weighted Contractual Average Average Range of Number Life Exercise Number Exercise Option Prices Outstanding (days) Price Exercisable Price - ------------- ------------ ----------- --------- ----------- --------- $ 4.38 128,500 377 $ 4.38 128,500 $ 4.38 $ 5.56 to $ 8.06 376,512 1,484 $ 6.84 376,512 $ 6.84 $15.13 to $19.13 198,320 2,385 $16.21 197,653 $16.20 $20.31 to $23.88 597,355 2,973 $22.11 319,993 $22.18 $33.06 to $34.50 320,500 3,498 $33.94 -- -- $35.13 to $37.06 75,500 3,458 $36.03 55,000 $36.00 $44.00 to $44.38 10,500 3,598 $44.27 -- -- --------- --------- Total 1,707,187 2,505 $19.70 1,077,658 $14.31 ========= =========
As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and related interpretations in accounting for its stock option plans. Since the exercise price of the options granted is equal to the quoted market price of the Company's stock at the date of grant, no compensation cost has been recognized for its stock option plans. Had compensation costs been determined based on fair value at the grant dates for awards made in 1996 and 1995 consistent with the methods of SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands of dollars, except for per share amounts):
1996 1995 ------- ------ Net income: As reported $32,760 $9,230 Pro forma $31,301 $8,781
Earnings per share: As reported -- Primary $ 0.96 $ 0.28 As reported -- Fully Diluted $ 0.94 $ 0.28 Pro forma -- Primary $ 0.92 $ 0.26 Pro forma -- Fully Diluted $ 0.91 $ 0.26
The fair value of grants was estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used in 1996 and 1995, respectively: risk-free interest rates of 6.25% and 6.00%, expected volatility of 39.15% and 41.78%, dividend yields of 0.34% and 0.54%, and an expected life of the options of 4 years in both 1996 and 1995.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company has a tax-advantaged savings plan in which all salaried employees may participate. Under such plan, a participating employee may allocate up to 10% of his salary, and the Company makes matching contributions of up to 6% thereof. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six separate funds. Amounts contributed by the employee and earnings and accretions thereon may be used to purchase shares of Common Stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. Matching funds contributed to the savings plan by the Company are invested only in Common Stock. The Company contributed $471,000 to the savings plan in 1996, $277,000 in 1995 and $375,000 in 1994.
A trusteed retirement plan has been adopted by the Company for its salaried employees. The benefits are based on years of service and the employee's average compensation for five consecutive years within the final ten years of service which produce the highest average compensation. The Company makes annual contributions to the plan in the amount of retirement plan cost accrued or the maximum amount which can be deducted for federal income tax purposes. The following table sets forth the plan's funded status (in thousands of dollars) as of December 31, 1996, 1995, and 1994.
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.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following is an analysis (in thousands of dollars) of the annual expense and activity in the deferred cost and benefits obligation accounts for 1994, 1995 and 1996. The computation assumes that future increases in medical costs will trend down from 8.8% to 5% per year over the next 9 years for purposes of estimating future costs. The medical cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed medical cost trend rate by one percent in each year would increase the aggregate of service and interest cost components of net periodic postretirement benefit cost for 1996 by $130,000 and the accumulated postretirement benefit obligation as of December 31, 1996 by $980,000.
The accumulated postretirement benefit obligation (in thousands of dollars) at December 31, 1996 is attributable to the following groups:
Retirees and beneficiaries................. $1,892 Dependents of retirees..................... 949 Fully eligible active employees............ 515 Active employees, not fully eligible....... 2,539 ------ $5,895 ======
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(7) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value.
Cash and Cash Investments
Fair value is carrying value as no cash equivalents or cash investments are included in the balances as of December 31, 1996 and 1995.
Debt
Instrument Basis of Fair Value Estimate ---------- ---------------------------- Bank revolving credit agreement Fair value is carrying value as of December 31, 1996 and 1995, based on the market value interest rates.
Uncommitted credit lines with banks Fair value is carrying value as of December 31, 1996 and 1995, based on the market value interest rates.
2004 Notes Fair value is 166% and 118%, of carrying value as of December 31, 1996 and 1995, respectively, based on the quoted market prices for this publicly traded debt.
2006 Notes Fair value is 120% of carrying value as of December 31, 1996, based on a Value Line evaluation.
8% Debentures Fair value is 102.5% of carrying value as of December 31, 1995, based on the quoted market price for this publicly traded debt.
The carrying value and estimated fair value of the Company's financial instruments at December 31, 1996 and 1995 (in thousands of dollars) are as follows:
The Company occasionally enters into forward and futures contracts to minimize the impact of oil and gas price fluctuations. However, such forward and futures contracts are not financial instruments since these contracts require or permit settlement by the delivery of the underlying commodity. Gains and losses on these activities are recognized in revenues when the hedged production occurs. No such contracts were outstanding as of December 31, 1996 or 1995.
POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(8) EVENT SUBSEQUENT TO DATE OF AUDITOR'S REPORT (UNAUDITED)
On March 3, 1997, the Company completed the purchase of a 46.34% interest in Maersk Oil (Thailand) Ltd. ("MOTL"). With this acquisition, the Company owns a 46.34% working interest in the entire B8/32 concession in the Gulf of Thailand. The purchase on a pro-forma basis would have increased the Company's net proved oil and gas reserves as of December 31, 1996, by the following amounts (all dollar amounts are expressed in thousands):
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.
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.
UNAUDITED SUPPLEMENTARY FINANCIAL DATA - (Continued)
The following information regarding estimates of the Company's proved oil and gas reserves, which are located offshore in United States waters of the Gulf of Mexico, onshore in the United States and offshore in the Kingdom of Thailand is based on reports prepared by Ryder Scott Company Petroleum Engineers. Their summary report dated February 28, 1997, is set forth as an exhibit to this Annual Report on Form 10-K and includes definitions and assumptions that served as the basis for the discussions under the caption "Item 1, Business - Exploration and Production Data - Reserves." Such definitions and assumptions should be referred to in connection with the following information.
The following information regarding the Company's Kingdom of Thailand oil and gas reserves as of December 31, 1996 should be read in conjunction with Note 8 "Event Subsequent to Date of Auditor's Report (Unaudited)."
Estimates of Proved Reserves
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - UNAUDITED
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.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - UNAUDITED (CONTINUED)
2. The estimated future gross revenues from proved reserves are priced on the basis of year end prices, except in those instances where fixed and determinable natural gas price escalations are covered by contracts.
3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year end cost estimates, and the estimated effect of future income taxes. These cost estimates are subject to some uncertainty, particularly those estimates relating to the Company's properties located in the Kingdom of Thailand.
The standardized measure of discounted future net cash flows does not purport to present the fair market value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized measure of discounted future net cash flows. All amounts are related to changes in reserves located in the United States and the Kingdom of Thailand, as noted.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - UNAUDITED (CONTINUED)
QUARTERLY RESULTS - UNAUDITED
Summaries of the Company's results of operations by quarter for the years 1996 and 1995 are as follows:
- ---------------------- (a) Represents revenues less lease operating, exploration, dry hole and impairment, and depreciation, depletion and amortization expenses.
Item 9.
Item 9. Disagreements on Accounting and Financial Disclosures.
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information regarding nominees and continuing directors in the Company's definitive Proxy Statement for its annual meeting to be held on April 22, 1997, to be filed within 120 days of December 31, 1996, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the Company's "1997 Proxy Statement"), is incorporated herein by reference. See also Item S-K 401(b) appearing in Part I of this Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The information regarding executive compensation in the Company's 1997 Proxy Statement, other than the information regarding the Compensation Committee Report on Executive Compensation, is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information regarding ownership of the Company securities by management and certain other beneficial owners in the Company's 1997 Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information regarding certain relationships and related transactions with management in the Company's 1997 Proxy Statement is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, FINANCIAL STATEMENT SCHEDULES AND EXHIBITS
1. Financial Statements and Supplementary Data:
Page ---- Report of Independent Public Accountants......... 29 Consolidated statements of income................ 30 Consolidated balance sheets...................... 31 Consolidated statements of cash flows............ 32 Consolidated statements of shareholders' equity.. 33 Notes to consolidated financial statements....... 34 Unaudited supplementary financial data........... 45
2. Financial Statement Schedules:
All Financial Statement Schedules have been omitted because they are not required, are not applicable or the information required has been included elsewhere herein.
3. Exhibits:
3(a) --Restated Certificate of Incorporation of Pogo Producing Company.
*3(a)(i) --Certificate of Designation, Preferences and Rights of Preferred Stock of Pogo Producing Company, dated March 25, 1987. (Exhibit 3(a)(1), Annual Report on Form 10-K for the year ended December 31, 1987, File No. 0-5468).
*3(b) --Bylaws of Pogo Producing Company, as amended and restated through July 24, 1990. (Exhibit 3(a), Quarterly Report on Form 10-Q for the quarter ended June 30, 1990, File No. 0-5468).
*4(a) --Amended and Restated Credit Agreement dated as of June 1, 1995 among Pogo Producing Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque Paribas as the Co-Agent. (Exhibit 4(a), Quarterly Report on Form 10-Q for the quarter ended September 30, 1995, File No. 1-7792).
*4(b) --Indenture dated as of June 15, 1996 to Fleet National Bank, as Trustee. (Exhibit 4(f), Quarterly Report pm Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792).
*4(c) --Indenture dated as of March 23, 1994 to Shawmut Bank Connecticut, National Association, as Trustee. (Exhibit 4(c), Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-7792).
*4(d) --Rights Agreement dated as of April 26, 1994 between Pogo Producing Company and Harris Trust Company of New York, as Rights Agent. (Exhibit 4, Current Report on Form 8-K filed April 26, 1994, File No. 1-7792).
*4(e) --Certificate of Designations of Series A Junior Participating Preferred Stock of Pogo Producing Company dated April 26, 1994. (Exhibit 4(d), Registration Statement on Form S-8 filed August 9, 1994, File No. 33-54969).
*4(f) --Registration Rights Agreement, dated as of June 18, 1996, by and among the Company, Goldman, Sachs & Co., Merrill Lynch & Co. and Merrill Lynch, Pierce, Fenner & Smith Incorporated. (Exhibit 4(c), Registration Statement on Form S-3 filed September 13, 1996, File No. 333-11927).
Pogo Producing Company agrees to furnish to the Commission upon request a copy of any agreement defining the rights of holders of long-term debt of Pogo Producing Company and all its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed under which the total amount of securities authorized does not exceed 10% of the total assets of Pogo Producing Company and its subsidiaries on a consolidated basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits 10(a) through 10(h)(2), inclusive)
*10(a) --1977 Stock Option Plan of Pogo Producing Company, as amended as of September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(a)(1) --Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and without employment restrictions). (Exhibit 10(a)(1), Annual Report on From 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(2) --Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and without employment restrictions), (Exhibit 10(a)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(3) --Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and with employment restrictions). (Exhibit 10(a)(3), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(4) --Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(4), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(5) --Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (with stock appreciation rights and with employment restrictions). (Exhibit 10(a)(5), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(6) --Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (with stock option appreciation rights and with employment restrictions). (Exhibit 10(a)(6), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(7) --Form of Amended Nonqualified Stock Option Agreement under 1977 Stock Option Plan (without stock appreciation rights and without employment restrictions). (Exhibit 10(a)(7), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(a)(8) --Form of Amended Incentive Stock Option Agreement under 1977 Stock Option Plan (without stock option appreciation rights and without employment restrictions). (Exhibit 10(a)(8), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(b) --1981 Stock Option Plan of Pogo Producing Company, as amended as of July 24, 1984. (Exhibit 10(b), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(b)(1) --Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (with stock appreciation rights). Exhibit 10(b)(1), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(b)(2) --Form of Stock Option Agreement under 1981 Nonqualified Stock Option Plan (without stock appreciation rights). Exhibit 10(b)(2), Annual Report on Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(c) --1981 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as amended as of July 24, 1984. (Exhibit 10(c), Annual Report on Form 10-K for the year ended December 31, 1984, File No. 0-5468).
*10(c)(1) --Form of Stock Option Agreement under 1981 Incentive Stock Option Plan. (Exhibit 10(c)(1), Annual Report of Form 10-K for the year ended December 31, 1981, File No. 0-5468).
*10(d) --1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as amended and restated effective January 25, 1994. (Exhibit 99, Definitive Proxy Statement on Schedule 14A, filed March 22, 1994, File No. 1-7792).
*10(d)(1) --Form of Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan, as amended and restated effective January 22, 1991. (Exhibit 10(d)(1), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10(d)(2) --Form of Director Stock Option Agreement under 1989 Incentive and Nonqualified Stock Option Plan as amended and restated effective January 22, 1991. (Exhibit 10(d)(2), Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-5468).
*10(e) --Form of Letter Agreement respecting treatment of options upon change in control. (Exhibit 19(f), Quarterly Report on Form 10-Q for the quarter ended June 30, 1982. File No. 0-5468).
*10(f) --1995 Long-Term Incentive Plan. (Exhibit 4(c), Registration Statement on Form S-8 filed May 22, 1996, File No. 333- 04233).
*10(g)(1)(i) --Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated February 1, 1996. (Exhibit 10(f)(1), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(1)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Stuart P. Burbach, dated effective February 1, 1997.
*10(g)(2)(i) --Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated February 1, 1996. (Exhibit 10(f)(2), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(2)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper, dated effective February 1, 1997.
*10(g)(3)(i) --Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated February 1, 1996. (Exhibit 10(f)(3), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(3)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good, dated effective February 1, 1997.
*10(g)(4)(i) --Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated February 1, 1996. (Exhibit 10(f)(4), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(4)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney, dated effective February 1, 1997.
*10(g)(5)(i) --Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated February 1, 1996. (Exhibit 10(f)(5), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(5)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy, Jr., dated effective February 1, 1997.
*10(g)(6)(i) --Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated February 1, 1996. (Exhibit 10(f)(6), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
10(g)(6)(ii) --Extension Agreement to Continue Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated effective February 1, 1997.
*10(h)(1) --Excess Benefits Letter Agreement by and between Pogo Producing Company and Kenneth R. Good, dated March 2, 1995. (Exhibit 10(g)(1), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
*10(h)(2) --Excess Benefits Letter Agreement by and between Pogo Producing Company and Paul G. Van Wagenen, dated March 2, 1995. (Exhibit 10(g)(2), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
*10(i) --Undertaking by Pogo Producing Company dated as of August 8, 1977. (Exhibit 10(e), Annual Report on Form 10-K for the year ended December 31, 1980, File No. 0-5468).
*10(j) --Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit 19, Quarterly Report on Form 10-Q for the quarter ended June 30, 1989, File No. 0-5468).
*10(k) --Bareboat Charter Agreement by and between Tantawan Services, LLC and Tantawan Production B.V., dated as of February 9, 1996. (Exhibit 10(j), Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
*10(l) --Gas Sales Agreement dated November 7, 1995, among The Petroleum Authority of Thailand, Thaipo, Limited, Thai Romo Ltd. and The Sophonpanich Co., Ltd. (Exhibit 10(k), Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792).
*21 --List of Subsidiaries of Pogo Producing Company. (Exhibit 21, Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-7792).
23(a) --Consent of Independent Public Accountants.
23(b) --Consent of Independent Petroleum Engineers.
24 --Powers of Attorney from each Director of Pogo Producing Company whose signature is affixed to this Form 10-K for the year ended December 31, 1996.
27 --Financial Data Schedule.
99 --Summary of Reserve Report of Ryder Scott Company Petroleum Engineers dated February 28, 1997, relating to oil and gas reserves of Pogo Producing Company. - ---------- * Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K None
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POGO PRODUCING COMPANY (Registrant)
By: /s/ PAUL G. VAN WAGENEN ----------------------------------- Paul G. Van Wagenen Chairman of the Board, President and Chief Executive Officer
Date: March 20, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on March 20, 1997.
Signatures Title
/s/ PAUL G. VAN WAGENEN Principal Executive -------------------------------- Officer and Director Chairman of the Board, President and Chief Executive Officer
/s/ JOHN W. ELSENHANS Principal Financial -------------------------------- Officer Vice President - Finance and Treasurer
/s/ THOMAS E. HART Principal Accounting -------------------------------- Officer Vice President and Controller
TOBIN ARMSTRONG* Director --------------------------------
JACK S. BLANTON* Director --------------------------------
W. M. BRUMLEY, JR.* Director --------------------------------
JOHN B. CARTER, JR.* Director --------------------------------
WILLIAM L. FISHER* Director --------------------------------
WILLIAM E. GIPSON* Director --------------------------------
GERRIT W. GONG* Director --------------------------------
J. STUART HUNT* Director --------------------------------
FREDERICK A. KLINGENSTEIN* Director --------------------------------
NICHOLAS R. PETRY* Director --------------------------------
JACK A. VICKERS* Director --------------------------------
*By: /s/ THOMAS E. HART ----------------------------- Attorney-in-Fact