ITEM 1. BUSINESS.
CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS
GENERAL. We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect the Company and to take advantage of the "safe harbor" protection for forward-looking statements afforded under federal securities laws. From time to time, the Company's management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about the Company. These statements may include projections and estimates concerning the timing and success of specific projects and the Company's future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal" or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this Form 10-K, the matters discussed in this Form 10-K are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially.
We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward-looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our stockholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement.
VOLATILITY AND LEVEL OF HYDROCARBON COMMODITY PRICES. Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets generally and are outside of our control. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on (1) the Company's financial position and results of operations (including reduced cash flow and borrowing capacity), (2) the quantities of natural gas and crude oil reserves that we can economically produce, (3) the quantity of estimated proved reserves that may be attributed to our properties and (4) our ability to fund our capital program.
PRODUCTION RATES AND RESERVE REPLACEMENT. Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering factors, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climate. Another factor affecting production rates is our ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, our ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, our finding and
development costs may not justify the use of resources to explore for and develop such reserves. There can be no assurances as to the level or timing of success, if any, that we will be able to achieve in finding and developing or acquiring additional reserves. Acquisitions that result in successful exploration or exploitation projects require assessment of numerous factors, many of which are beyond our control. There can be no assurance that any acquisition of property interests by us will be successful and, if unsuccessful, that such failure will not have an adverse effect on our financial condition, results of operations and cash flows.
RESERVE ESTIMATES. Our forward-looking statements may be predicated on our estimates of our oil and gas reserves. All of the reserve data in this Form 10-K or otherwise made by or on behalf of the Company are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond our control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, it is common that estimates made by different engineers will vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.
LAWS AND REGULATIONS. Our forward-looking statements are generally based on the assumption that the legal and regulatory environment will remain stable. Changes in the legal and/or regulatory environment could have a material adverse effect on our future results of operations and financial condition. Our ability to economically produce and sell our oil and gas production is affected and could possibly be restrained by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting (1) oil and gas production, including allowable rates of production by well or proration unit, (2) taxes applicable to the Company and/or our production, (3) the amount of oil and gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities and (5) the marketing of competitive fuels. Our operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These environmental laws and regulations continue to change and may become more onerous or restrictive in the future. Our forward-looking statements are generally based upon the expectation that we will not be required in the near future to expend amounts to comply with environmental laws and regulations that are material in relation to our total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, we are unable to accurately predict the ultimate cost of such compliance.
DRILLING AND OPERATING RISKS. Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. In addition, a substantial amount of our operations are currently offshore, domestically and internationally, and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision and damage or loss from severe weather. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.
COMPETITION. The Company's forward-looking statements are generally based on a stable competitive environment. Competition in the oil and gas industry is intense both domestically and internationally. We actively compete for reserve acquisitions and exploration leases and licenses, as well as in the gathering and marketing of natural gas and crude oil. Our competitors include the major oil companies, independent oil and gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. To the extent our competitors have greater financial resources than currently available to us, we may be disadvantaged in effectively competing for certain reserves, leases and licenses. Recently announced consolidations in the industry may enhance the financial
resources of certain of our competitors. From time to time, the level of industry activity may result in a tight supply of labor or equipment required to operate and develop oil and gas properties. The availability of drilling rigs and other equipment, as well as the level of rates charged, may have an effect on our ability to compete and achieve success in our exploration and production activities.
In marketing our production, we compete with other producers and marketers on such factors as deliverability, price, contract terms and quality of product and service. Competition for the sale of energy commodities among competing suppliers is influenced by various factors, including price, availability, technological advancements, reliability and creditworthiness. In making projections with respect to natural gas and crude oil marketing, we assume no material decrease in the availability of natural gas and crude oil for purchase. We believe that the location of our properties, our expertise in exploration, drilling and production operations, the experience of our management and the efforts and expertise of our marketing units generally enable us to compete effectively. In making projections with respect to numerous aspects of our business, we generally assume that there will be no material change in competitive conditions that would adversely affect us.
GENERAL
Noble Affiliates, Inc. is a Delaware corporation organized in 1969, and is principally engaged, through its subsidiaries, in the exploration, production and marketing of oil and gas.
In this report, unless otherwise indicated or the context otherwise requires, the "Company" or the "Registrant" refers to Noble Affiliates, Inc. and its subsidiaries, "Samedan" refers to Samedan Oil Corporation and its subsidiaries, "EDC" refers to Energy Development Corporation and its subsidiaries, "NGM" refers to Noble Gas Marketing, Inc. and its subsidiary, and "NTI" refers to Noble Trading, Inc. Samedan's subsidiaries include EDC. In this report, quantities of oil or natural gas liquids are expressed in barrels ("BBLS"); quantities of natural gas are expressed in thousands of cubic feet ("MCF"), millions of cubic feet ("MMCF"), billions of cubic feet ("BCF"), trillions of cubic feet ("TCF") and million British Thermal Units ("MMBTU"). Equivalent units are expressed in thousand cubic feet of gas equivalents ("MCFe"), million cubic feet of gas equivalents ("MMCFe"), billion cubic feet of gas equivalents ("BCFe"), trillion cubic feet of gas equivalents ("TCFe"), converting oil to gas at one barrel of oil equaling six thousand cubic feet of gas, or barrel of oil equivalents ("BOE") converting gas to oil at six thousand cubic feet of gas to one barrel of oil.
The Company's wholly-owned subsidiary, NGM, markets the majority of the Company's natural gas as well as third-party gas. The Company's wholly-owned subsidiary, NTI, markets a portion of the Company's oil as well as third-party oil. For more information regarding NGM's operations and NTI's operations, see "Item 1. Business--Oil and Gas--Marketing" of this Form 10-K.
The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), a 50 percent owned joint venture that indirectly owns 90 percent of Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol plant in Equatorial Guinea. AMCCO is accounted for using the equity method within the Registrant's wholly-owned subsidiary, Samedan of North Africa, Inc. For more information, see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K.
OIL AND GAS
The Company's wholly-owned subsidiary, Samedan, directly or through various arrangements with other companies, explores for, develops and produces oil and gas hydrocarbons. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which the Company has exploration rights. Samedan has been engaged in the exploration, production and marketing of oil and gas since 1932. Samedan has exploration, exploitation and production operations domestically and internationally. The domestic areas consist of: offshore in the Gulf of Mexico and California; the Gulf Coast Region (Louisiana, New Mexico and Texas); the Mid-Continent Region (Oklahoma and Southern Kansas); and the Rocky Mountain Region (Colorado, Montana, North Dakota, Wyoming and California). The international areas of operations include
Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea, the North Sea, and Vietnam. For more information regarding Samedan's oil and gas properties, see "Item 2.
ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Registrant is located in Houston, Texas. The Company maintains offices for international, domestic onshore, and domestic offshore operations in Houston, Texas. The Company also maintains offices in China, Ecuador, Israel, the United Kingdom, and Vietnam. NGM's office is located in Houston, Texas, and NTI's office is located in Ardmore, Oklahoma. The Company also maintains offices in Ardmore, Oklahoma for centralized accounting, lease records, human resources and related administrative functions.
OIL AND GAS
The Company, directly or through various arrangements with others, searches for potential oil and gas properties, seeks to acquire exploration rights in areas of interest and conducts exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which it acquired exploration rights. During 2000, Samedan drilled or participated in the drilling of 268 gross (146 net) wells, comprised of 50 gross (11.5 net) international wells and 218 gross (134.5 net) domestic wells. For more information regarding Samedan's oil and gas properties, see "Item 1. Business--Oil and Gas" of this Form 10-K.
DOMESTIC OFFSHORE. During 2000, an exploitation program at Samedan's South Timbalier field consisting of two development wells, four workovers and additional compression increased production 66 MMCF of gas per day, net to the Company's interest.
Upgrades at East Cameron 331/332 have resulted in a net incremental increase in total production of nearly 20 MMCF of gas and 1,080 BBLS of oil per day.
An exploitation project consisting of seven sidetracks was completed at Main Pass 306, increasing production 875 net BBLS of oil per day.
The High Island A-517 A-8 and A-14 development wells commenced production of 8.2 net MMCF of gas per day each.
The Vermilion 161 BJ-6 development well commenced production of 7.5 MMCF of gas and 330 BBLS of oil per day, net to Samedan's interest.
Production began from the 12 block Viosca Knoll 252 Unit. Four wells were producing approximately 42 MMCF of gas per day, net to Samedan's 40 percent interest. Additional exploration and development opportunities remain.
Samedan recompleted its West Delta 58 C-4 well to the OX sand. The zone contains 68 feet of hydrocarbon pay and commenced production at the rate of 9.7 MMCF of gas and 992 BBLS of condensate per day, net to Samedan's interest.
A workover in the Vermilion 167 field yielded a net incremental increase of 600 BBLS of oil per day.
Samedan entered into an exploration alliance with McMoRan Exploration Company and committed to participate with a 25 percent working interest in six prospects. Additionally, Samedan agreed to work with McMoRan in identifying future prospects on approximately 660,000 acres previously accumulated by McMoRan. Samedan's estimated costs for the committed exploration prospects are approximately $25 million.
The Vermilion 196 #2 well, in which Samedan owns a 25 percent working interest, logged 70 feet of net hydrocarbon pay in three sands. The property expansion is continuing with two development wells and initial production is expected in the third quarter of 2001.
Samedan purchased an additional 13.2 percent working interest (for a total working interest of 33.2 percent) in Vermilion 408 from McMoRan Exploration Company for $2.8 million. The block contains two wells with reserves estimated to be four million BOE.
DOMESTIC ONSHORE. In 2000, Samedan maintained an active drilling program in the Bowdoin field located in Phillips and Valley Counties, Montana where 95 successful wells were drilled.
The Harry Stagg #1 located in Lafayette Parish, Louisiana commenced production at a rate of 5.6 MMCF of gas and 274 BBLS of condensate per day, net to the Company's interest, with 8,400 pounds per square inch of flowing tubing pressure.
The Runnels #3 in Matagorda County, Texas commenced production at the daily rate of 2.6 MMCF of natural gas and 68 BBLS of oil, net to Samedan's interest.
EQUATORIAL GUINEA. The expansion of the 34 percent owned Alba field has been completed with the successful drilling of the Alba #8 well. The expansion included engineering, fabrication, transportation, and installation of a tripod well platform, a four-pile 12 slot manned platform with compression, various infield flow lines, a 19-mile pipeline and the drilling of several wells, some for production and some for reinjection. The expansion will increase the production capacity of the field, which lies 18 miles off the coast of Equatorial Guinea, to 225 MMCF of gas per day from 90 MMCF of gas per day.
Approximately 125 MMCF of gas per day will be supplied to a methanol plant on Bioko Island, scheduled to start production in the second quarter of 2001. Approximately 10 MMCF of gas per day will be used for onshore operations, and the remainder will be reinjected.
The Company, through its 50 percent ownership interest in AMCCO, indirectly owns a 45 percent working interest in AMPCO, which is constructing a methanol plant to use gas from the Alba field. The plant is designed to produce 2,500 metric tons of methanol per day, which is the equivalent of approximately 20,000 BBLS per day. The plant is designed to use approximately 125 MMCF of gas per day and is approximately 95 percent complete. It is being built under a turnkey construction contract and projected to be completed and begin production in the second quarter of 2001. For additional information, see "Item 1. Business--Unconsolidated Subsidiary" of this Form 10-K.
ECUADOR. The Company owns a 100 percent working interest in the Block 3 concession, located offshore Ecuador in the Gulf of Guayaquil. The concession includes 12,355 gross developed acres and 851,771 gross undeveloped acres encompassing the Amistad gas field. The Company constructed and set a drilling and production platform for the Amistad gas field. A platform drilling rig had drilled three wells at year end. Additional evaluation wells will be drilled in 2001.
Gas from the field is targeted to supply an electrical power generation facility to be constructed near the city of Machala. The Company has made progress payments to General Electric for the construction of two units that will ultimately be capable of producing 240 megawatts of electricity when in a combined cycle configuration.
ISRAEL. The Company made a gas discovery approximately 15 miles off the coast of Israel with the Mari-B #1 well. The Mari-B #2 well was drilled approximately one mile east of the Mari-B #1 discovery. A delineation well was drilled to appraise the southern extension of the nearby Noa field which was discovered in 1999. Based on the data
from these wells, it is estimated that the combined Noa/Mari-B areas contain recoverable reserves in excess of 1.2 TCF of gas.
In late 2000, the Company increased its interest in the exploration agreement from 40 to 47 percent. The agreement covers 11 licenses, permits or leases encompassing 1,081,974 gross acres offshore Israel.
The partners in the exploration agreement are currently negotiating a supply contract with Israel Electric Corporation Ltd.
CHINA. In October 2000, the Chinese government granted final approval of the development plan for the Cheng Dao Xi field to the Company's wholly-owned indirect subsidiary Energy Development Corporation (China), Inc. The field is located in the southern portion of Bohai Bay. The plan includes a drilling and production platform set in approximately 25 feet of water and 16 wells to develop the field, including injection wells to maintain field pressure. The production facilities are designed to process 10,000 BBLS of oil per day.
A five-mile pipeline will also be installed to connect the field to the existing onshore infrastructure located in the Shengli oil field. The total projected $101 million cost for the development and construction of the field and pipeline will be shared 57 percent by the Company and 43 percent by the China Petro-Chemical Corporation. Initial production is expected in the second quarter of 2002.
VIETNAM. Oil and gas exploration rights were acquired on two blocks in the Nam Con Son basin offshore Vietnam. Samedan will be the operator with a 60 percent interest in the two blocks, which encompass 1.7 million acres. Both oil and gas have been tested on the blocks in wells drilled by previous operators, but the discoveries were not developed. Two exploratory wells are planned for 2001.
NORTH SEA. EDC (Europe) Limited, a wholly-owned indirect subsidiary of the Company, acquired, through an asset exchange, a 12 percent interest in Block 21/20a in the Cook field, 100 miles east of Aberdeen, Scotland. This field commenced production of 12,000 gross BBLS of oil per day in April 2000. Recoverable reserves are estimated in excess of 20 million BBLS of oil to be produced over a span of at least five years.
Interests in two licenses in the Hanze field in the Dutch sector of the North Sea were acquired. The Company owns a 15 percent interest in one license in which production is expected to start during the second half of 2001. An exploration well on the second license, in which the Company owns 40 percent, is planned in 2001. A new oil platform, currently under construction, is expected to have a production rate of approximately 31,500 BBLS of oil per day. The Hanze field would be the first oil field to come into production in the Dutch sector of the North Sea in 10 years.
ARGENTINA. The Company participated with a 13 percent working interest in 38 exploitation wells in the El Tordillo field during 2000. The Company is awaiting government approval on an oil and gas exploration permit of approximately 1.2 million acres. The permit is located in the Cuyo Basin of Mendoza Province in western Argentina. The Company was the successful bidder on an adjacent permit of approximately 1.1 million acres. Seismic work should commence in 2001.
NET EXPLORATORY AND DEVELOPMENTAL WELLS. The following table sets forth, for each of the last three years, the number of net exploratory and development wells drilled by or on behalf of Samedan. An exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the following table and as defined in the rules and regulations of the Securities and Exchange Commission, is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency.
- ---------- (1) A productive well is an exploratory or a development well that is not a dry hole. (2) A dry hole is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
At January 31, 2001, Samedan was drilling 9 gross (4.3 net) exploratory wells and 8 gross (3.6 net) development wells. These wells are located in Oklahoma, Texas, Louisiana, Argentina, and offshore in the Gulf of Mexico, Israel, Ecuador, Equatorial Guinea, and the North Sea. These wells have objectives ranging from approximately 5,500 feet to 25,000 feet. The drilling cost to Samedan of these wells is approximately $47 million if all are dry and approximately $62 million if all are completed as producing wells.
OIL AND GAS WELLS. The number of productive oil and gas wells in which Samedan held an interest as of December 31, were as follows:
(1) Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
(2) During 1999, the Company sold 250 net non-strategic wells contributing to the decreased well count.
(3) One or more completions in the same bore hole is counted as one well in this table. The following table summarizes multiple completions and non-producing wells as of December 31 for the years shown. Included in wells not producing are productive wells awaiting additional action, pipeline connections or shut-in for various reasons.
At year-end 2000, Samedan had less than two percent of its oil and gas sales volumes committed to long-term supply contracts and had no similar agreements with foreign governments or authorities in which Samedan acts as producer.
Since January 1, 2000, no oil or gas reserve information has been filed with, or included in any report to any federal authority or agency other than the Securities and Exchange Commission and the Energy Information Administration ("EIA"). Samedan files Form 23, including reserve and other information, with the EIA.
AVERAGE SALES PRICE. The following table sets forth for each of the last three years the average sales price per unit of oil produced and per unit of natural gas produced, and the average production cost per unit.
(1) Net production amounts used in this calculation include royalties.
(2) Reflects a reduction of $2.92 per BBL in 2000 from hedging in the United States.
(3) Oil production is converted to gas equivalents (MCFe) based on one BBL of oil equals six MCF of gas.
[MAP OF GULF OF MEXICO OPERATIONS]
SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (INTERESTS ROUNDED TO NEAREST WHOLE PERCENT)
NET WORKING BLOCK INTEREST (%) - -------------------------
EAST BREAKS - ----------- 279 33 420* 48 421* 48 464* 48 465* 48 475* 100 510* 33 519* 100 563* 100 588* 97 589* 97 632* 97 633* 97
GREEN CANYON - ------------ 23* 50 24* 43 25* 43 27* 43 85* 50 227* 50 228* 50 303* 40 723* 100 724* 100 768* 100
WEST CAMERON - ------------ 136 40 392 100 393 100 400 100 438 100 443 100 446 100 583 100 602 100 614 25
VERMILION - --------- 195 25 207 25 232 50 278 100 280 50 283 50 285 50 286 100 300 50 312 100 349 75 353 100 360 67 361 67 365 50 377 100 394 75
GARDEN BANKS - ------------ 34 100 35 100 62 25 63 25 64 25 78 100 107 25 116 100 122 100 154 100 326* 100 751* 100 795* 100 841* 39
MAIN PASS - --------- 192 100 293 100
GALVESTON - --------- 249-L 50 250-L 50 274-L 50 275-L 50 277-L 50 340-S 50 341-S 50 349-S 50
MUSTANG ISLAND - -------------- 829 80 830 80
SOUTH MARSH ISLAND - ------------------ 38 100 62 67 63 67 64 67 65 67 70 50 104 100 167 100 179 35 180 35 185 35 186 35 195 50
MISSISSIPPI CANYON - ------------------ 524* 50 573 100 583* 50 595* 24 639* 24 661* 25 665* 50 705* 25 849* 48
SOUTH TIMBALIER - --------------- 98 50 156 67 201 100 315 30
BRAZOS - ------ 308-L 50 336-L 50 337-L 50 543 100
EWING BANK - ---------- 833* 14 834* 14 949 97 993 48 995 43 996 43
EUGENE ISLAND - ------------- 96 25 97 25 109 25 300 67 317 67
HIGH ISLAND - ----------- A-218 100 A-230 100 A-232 100 A-426 33 A-435 33 A-516 100
VIOSCA KNOLL - ------------ 344 100 697 50 820 50 908* 100
ATWATER VALLEY - -------------- 327* 39 533* 40
* Located in water deeper than 1,000 feet.
The developed and undeveloped acreage (including both leases and concessions) that Samedan held as of December 31, 2000, is as follows:
(1) Developed acreage is acreage spaced or assignable to productive wells.
(2) A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
(3) Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are those leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well so holding such lease.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Noble Drilling litigation disclosed in the Company's 1999 Form 10-K was settled during 2000.
The Company has other lawsuits pending but does not believe the outcome of the lawsuits, individually or collectively, will materially impair the Company's financial and operational condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth quarter of 2000.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 12, 2001, with respect to the executive officers of the Registrant.
- ---------------
(1) Robert Kelley served as President and Chief Executive Officer of the Registrant from August 1, 1986 until October 2000 and as Chairman of the Board since October 27, 1992. Prior to August 1986, he had served as Executive Vice President of the Registrant from January 1986. Mr. Kelley served as President and Chief Executive Officer of Samedan, positions he held since 1984. For more than five years prior thereto, Mr. Kelley served as an officer of Samedan. He has served as a director of the Company since 1986. Mr. Kelley has announced his retirement effective April 30, 2001.
(2) Charles D. Davidson was elected President and Chief Executive Officer of the Company on October 2, 2000. Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar.
(3) Alan R. Bullington was promoted to Vice President and General Manager, International Division of Samedan on January 1, 1998. Prior thereto, he served as Manager-International Operations and Exploration and as Manager-International Operations. Prior to his employment with Samedan in 1990, he held various management positions within the exploration and production division of Texas Eastern Transmission Company.
(4) Robert K. Burleson has served as President of Noble Gas Marketing, Inc. since June 14, 1995. Prior thereto, he served as Vice President- Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment with the Company, he was employed by Reliant Energy as Director of Business Development for their interstate pipeline, Reliant Gas Transmission.
(5) Dan O. Dinges was promoted to Senior Vice President and General Manager, Offshore Division of Samedan on January 1, 1998. Prior thereto, he had served as Vice President and General Manager, Offshore Division of Samedan since January 1989. Mr. Dinges has been a member of the Operating Committee of Samedan since January 31, 1995.
(6) Albert D. Hoppe was elected Senior Vice President, General Counsel and Secretary of the Registrant on December 5, 2000. Prior thereto, he served as Vice President, General Counsel and Secretary of Vastar Resources, Inc. from 1994 through 2000.
(7) James L. McElvany has served as Vice President-Finance and Treasurer of the Registrant since July 1, 1999. Prior to July 1999, he had served as Vice President-Controller of the Registrant since December 1997. Prior thereto, he served as Controller of the Registrant since December 1983. He has been a member of the Operating Committee of Samedan since July 1, 1999.
(8) Richard A. Peneguy, Jr. was promoted to Vice President and General Manager, Onshore Division of Samedan on January 1, 2000. Prior thereto, he had served as General Manager, Onshore Division of Samedan since January 1, 1991.
(9) W. A. Poillion was promoted to Senior Vice President-Production and Drilling of Samedan on January 1, 1998. Prior thereto, he had served as Vice President-Production and Drilling of Samedan since November 1990. He has been a member of the Operating Committee of Samedan since November 1, 1990. From March 1, 1985 to October 31, 1990, he served as Manager of Offshore Production and Drilling for Samedan.
(10) Kenneth P. Wiley has served as Vice President-Information Systems since July 1998. Prior thereto, he served as Manager-Information Systems for Samedan since November 1994.
The terms of office for the officers of the Registrant continue until their successors are chosen and qualified. With the exception of Mr. Davidson, no other officer or executive officer of the Registrant has an employment agreement with the Registrant or any of its subsidiaries. There are no family relationships between any of the Registrant's officers.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
COMMON STOCK. The Registrant's Common Stock, $3.33 1/3 par value ("Common Stock"), is listed and traded on the New York Stock Exchange under the symbol "NBL." The declaration and payment of dividends are at the discretion of the Board of Directors of the Registrant and the amount thereof will depend on the Registrant's results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.
STOCK PRICES AND DIVIDENDS BY QUARTERS. The following table sets forth, for the periods indicated, the high and low sales price per share of Common Stock on the New York Stock Exchange and quarterly dividends paid per share.
TRANSFER AGENT AND REGISTRAR. The transfer agent and registrar for the Common Stock is First Chicago Trust Company of New York, P.O. Box 2500, Jersey City, New Jersey 07303.
STOCKHOLDERS' PROFILE. As of December 31, 2000, the number of holders of record of Common Stock was 1,179. The following chart indicates the common stockholders by category.
RECENT SALES OF UNREGISTERED SECURITIES. The Company's unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), is a 50 percent owned joint venture that indirectly owns 90 percent of Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol plant in Equatorial Guinea. On November 10, 1999, AMCCO issued $125 million of 10.875% Series A-1 Senior Secured Notes and $125 million of 8.95% Series A-2 Senior Secured Notes ("Series A-2 Notes") due 2004, which are not included in the Company's balance sheet, to fund the Company's portion of the remaining construction payments.
The Company has guaranteed the payment of interest on the Series A-2 Notes. In addition, the Company established a new series of preferred stock, Series B Mandatorily Convertible Preferred Stock, par value $1.00 per share (the "Series B Preferred"). The Company issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of the Series B Preferred to Noble Share Trust, which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in the Noble Share Trust.
Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2 Notes. The Series A-2 indenture trustee, and the holders of 25 percent of the outstanding principal amount of the Series A-2 Notes, would have the right to require a public offering of the Series B Preferred to generate proceeds sufficient to repay the Series A-2 Notes, upon the occurrence of certain events ("Trigger Dates"), including (i) defaults under the Indenture governing the Series A-2 Notes, (ii) a default and acceleration of the Company's debt exceeding five percent of the Company's consolidated net tangible assets, and (iii) the simultaneous occurrence of a downgrade of the Company's unsecured senior debt rating to "Ba1" or below by Moody's or "BB+" or below by Standard & Poor's and a decline in the closing price of the Company's common stock for three consecutive trading days to below $17.50. The exercise of this mandatory remarketing right is subject to certain forbearance provisions that would allow the Company the opportunity to obtain funds for the repayment of the Series A-2 Notes by alternative means for a specified period of time.
The terms of the Series B Preferred, including dividend and conversion features, would be reset at the time of the remarketing, based on the recommendation of Donaldson, Lufkin & Jenrette, as Remarketing Agent, as to the terms necessary to generate proceeds to repay the Series A-2 Notes. If the Remarketing Agent is not able to complete a registered public offering of the Series B Preferred, it may under certain circumstances conduct a private placement of such stock. If it is impossible for legal reasons to remarket the Series B Preferred, the Company would be obligated to repay the Series A-2 Notes.
The Series B Preferred stock would be mandatorily convertible into the Company's common stock three years after remarketing (or failed remarketing). Generally, each share of Series B Preferred would then be mandatorily convertible at the "Mandatory Conversion Rate," which is equal to the following number of shares of the Company's common stock:
(a) if the Mandatory Conversion Date Market Price is greater than or equal to the Threshold Appreciation Price, the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price;
(b) if the Mandatory Conversion Date Market Price is less than the Threshold Appreciation Price but is greater than the Reset Price, the quotient of $1,000 divided by the Mandatory Conversion Date Market Price; and
(c) if the Mandatory Conversion Date Market Price is less than or equal to the Reset Price, the quotient of $1,000 divided by the Reset Price.
"Mandatory Conversion Date Market Price" means the average closing price per share of the Company's common stock for the 20 consecutive trading days immediately prior to, but not including, the mandatory conversion date.
"Threshold Appreciation Price" means the product of (i) the Reset Price (as the same may be adjusted from time to time) and (ii) 110 percent.
"Reset Price" means the higher of (i) the closing price of a share of the Company's common stock on the Trigger Date or (ii) the quotient (rounded up to the nearest cent) of $125,000,000 divided by the number, as of the Trigger Date, of the authorized but unissued shares of common stock that have not been reserved as of the Trigger Date by the Company's Board of Directors for other purposes.
In addition to the mandatory conversion discussed above, each share of the Series B Preferred is generally convertible, at the option of the holder thereof at any time before the mandatory conversion date, into 36.364 shares of the Company's common stock (the "Optional Conversion Rate"); provided, however, that the Optional Conversion Rate shall adjust, as of the earlier to occur of remarketing or failed remarketing, to the quotient of (i) $1,000 divided by (ii) the Threshold Appreciation Price.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
For additional information, see "Item 8. Financial Statements and Supplementary Data" of this Form 10-K.
OPERATING STATISTICS
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
The Company's net cash provided from operations in 2000 was significantly higher than 1999 due to higher commodity prices during the second half of the year for crude oil and natural gas.
The oil price received by the Company in 2000 increased 50 percent from 1999 and the gas price received by the Company increased 69 percent in 2000 over the price received in 1999. In 1999, the Company's oil price increased 40 percent and the natural gas price increased two percent compared to 1998.
CASH PROVIDED FROM OPERATIONS
[CHART - dollars per BOE] [CHART - dollars per share]
The Company's unconsolidated subsidiary, AMCCO, is a 50 percent owned joint venture that indirectly owns 90 percent of AMPCO, which is constructing a methanol plant in Equatorial Guinea. During 1999, AMCCO issued $250 million senior secured notes due 2004 which are not included in the Company's balance sheet, to fund the remaining construction payments. The plant construction started during 1998 and commercial production is expected during the second quarter of 2001. The construction cost of the turnkey contract is $322.5 million. Other associated expenditures required to complete the project and produce marketable supplies of methanol are projected to be $125.5 million. The total cost of the methanol project is estimated to be $448 million including various contingencies and capitalized interest, with the Company responsible for $224 million. Payments are due upon the completion of specific phases of the construction. During 2000, the Company recorded costs of $72 million toward the project, including capitalized interest, and $45.6 million in construction contract payments. The Company has construction contract phase payments totaling $8.1 million due in 2001.
During 2000, $512 million was spent on exploration and development projects, $72 million on the methanol project and $27 million on the Machala power project in Ecuador for total expenditures of $611 million. The 2001 exploration and development budget is approximately $700 million, including $45 million for the methanol project and $42 million on the Machala power project.
The Company's current ratio (current assets divided by current liabilities) was .83:1 at December 31, 2000, compared with .76:1 at December 31, 1999. The increase in the current ratio was due primarily to an increase in cash and short-term investments along with a $17.5 million decrease in other current liabilities. The Company's cash and short-term investments increased from $2.9 million at December 31, 1999, to $23.2 million at December 31, 2000.
FINANCING
The Company's total long-term debt, net of unamortized discount, at December 31, 2000, was $525 million compared to $445 million at December 31, 1999. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 38 percent at December 31, 2000, compared with 39 percent at December 31, 1999.
The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100 million of 7 1/4% Senior Debentures Due 2097 and the outstanding balance of $80 million on a $300 million credit facility. Other than the $80 million due on the credit facility, there is no principal payment due on long term debt during the next five years.
The Company has a $300 million credit facility which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the Company had no borrowing against this facility.
On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized.
OTHER
The Company has paid quarterly cash dividends of $.04 per share since 1989, and currently anticipates it will continue to pay quarterly dividends of $.04 per share.
The Company's Board of Directors authorized a repurchase of up to $50 million of the Company's common stock. As of March 1, 2001, the Company had completed 60.5 percent of the repurchase plan. The repurchase of 1,386,400 shares during 2000 at an average cost of $21.84 per share was funded from the Company's current cash flow.
The Company has sold a number of non-strategic oil and gas properties over the past three years. Total amounts of oil and gas reserves associated with the 2000, 1999 and 1998 dispositions were 1.2 million BBLS of oil and 4.8 BCF of gas, 5.1 million BBLS of oil and 34.2 BCF of gas, and .2 million BBLS of oil and 2.2 BCF of gas, respectively. The Company believes the disposition of non-strategic properties furthers the goal of concentrating its efforts on strategic properties.
The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1998. The Statement establishes accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders' equity until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS No. 133, the Company is required to adopt the statement for fiscal years beginning after June 15, 2000. A company may also implement the statement as of the beginning of any fiscal quarter after the statement's issuance (that is, fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at the Company's election, before January 1, 1998).
During 2000, the FASB issued SFAS No. 138 which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities and should be adopted concurrently with SFAS No. 133, according to its provisions and the issuance of SFAS No. 137. The normal purchases and normal sales exception may be applied to contracts that implicitly or explicitly permit net settlement and contracts that have a market mechanism to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138 effective January 1, 2001. The adoption of these FASB's did not have a material impact on the Company's results of operations or financial position.
RESULTS OF OPERATIONS
NET INCOME AND REVENUES
The Company's net income for 2000 of $191.6 million was primarily the result of a 50 percent and 69 percent increase in the average oil and gas price to $24.37 per BBL and $3.77 per MCF, respectively, compared to 1999. The impact of the increased oil price was approximately $76 million in additional oil revenues compared to 1999. The impact of the increase in the 2000 average natural gas price was approximately $229 million in additional gas revenues compared to 1999. The increase in net income for 1999 compared to 1998, is primarily due to significantly higher oil prices received during 1999 coupled with the $143 million charge for property impairments in 1998.
NATURAL GAS INFORMATION
Natural gas revenues increased dramatically in 2000, due to a 69 percent increase in the average price. The 69 percent increase in the average price received for the Company's 2000 gas production offset a decline of 11 percent in the average daily gas production. Gas production in both the third and fourth quarters of 2000 rose above the low experienced in the second quarter of 2000. Natural gas accounted for 71 percent of the Company's total gas and oil revenues in 2000. Gas sales and average daily production for 1999 declined despite a slight increase in the Company's average price. Revenues were down because natural gas production declined 20 percent in 1999 compared to 1998. The table below depicts daily natural gas production in MMCF by area for the last three years.
Natural gas production during 2000 ranged from a low of 354.2 MMCF per day in June, to a high of 438.3 MMCF per day in December.
2000 DAILY PRODUCTION BY QUARTER
[CHART - MMCF] [CHART - MBBLS]
CRUDE OIL INFORMATION
Crude oil revenues increased during 2000 due to significantly stronger oil prices. The 50 percent increase in the average price received for the Company's 2000 oil production offset a decline of 14 percent in the average daily production. Oil production in both the third and fourth quarters of 2000 rose above the low experienced in the second quarter of 2000. Crude oil accounted for 29 percent of the Company's total oil and gas revenues in 2000. Oil sales increased 40 percent and average daily production declined 19 percent in 1999, compared to 1998. The table below depicts daily oil production in BBLS by area for the last three years.
Crude oil production during 2000 ranged from a low of 24,019 BBLS per day in May, to a high of 27,434 BBLS per day in August. The Company's December 2000 oil production volume was 25,974 BBLS per day.
HEDGING ACTIVITY
The Company, through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars, and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company's oil and gas production are recorded in oil and gas sales and royalties. For more information, see "Item 7a.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to market risk in the normal course of its business operations. Management believes that the Company is well positioned with its mix of oil and gas reserves to take advantage of future price increases that may occur. However, the uncertainty of oil and gas prices continues to impact the domestic oil and gas industry. Due to the volatility of oil and gas prices, the Company, from time to time, has used derivative hedging and may do so in the future as a means of controlling its exposure to price changes. The swap component of the contracts discussed in the following paragraphs was treated as a hedge for accounting purposes only.
The Company had entered into three crude oil premium swap contracts related to its production for calendar year 2000. Two of the contracts provided for payments based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL. These two contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the settlement price for each NYMEX trading day was less than the trigger price, provided the NYMEX price was also greater than the $17.00 per BBL knockout price. If a daily settlement price was $17.00 per BBL or less, then neither party had any liability to the other for that day. If a
daily settlement price was above the applicable trigger price, then the Company would owe the counterparty for the excess of the settlement price over the trigger price for that day. Payment was made monthly under each of these contracts, in an amount equal to the net amount due to either party based on the sum of the daily amounts determined as described in this paragraph for that month.
The third contract related to 2,500 BBLS per day and provided for payments based on monthly average NYMEX settlement prices. The contract entitled the Company to receive monthly settlements from the counterparty in an amount, if any, by which the arithmetic average of the daily NYMEX settlement prices for the month was less than the trigger price, which was $21.73 per BBL, multiplied by the number of days in the month, provided such average NYMEX price was also greater than the $17.00 per BBL knockout price. If the average NYMEX settlement price for the month was $17.00 per BBL or less, then neither party would have any liability to the other for that month. If the average NYMEX settlement price for the month was above the trigger price, then the Company would pay the counterparty an amount equal to the excess of the average settlement price over the trigger price, multiplied by the number of days in the month.
The net effect of these premium swap contracts was a $2.87 per BBL reduction in the average crude oil price realized by the Company in 2000.
The Company has treated the swap component of these contracts as a hedge (for accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20 per BBL, which existed at the dates it entered into these contracts. In addition, the Company has separately accounted for the premium component of these contracts by marking them to market, resulting in a gain of $2,921,000 recorded in other income for the year ended December 31, 2000.
In addition to the premium swap crude oil hedging contracts, the Company had entered into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the monthly average settlement price for each NYMEX trading day during a contract month was less than the floor price. If the monthly average settlement price was above the applicable cap price, then the Company would owe the counterparties for the excess of the monthly average settlement price over the applicable cap price. If the monthly average settlement price fell between the applicable floor and cap price, then neither party would have any liability to the other party for that month. Payment, if any, was made monthly under each of the contracts in an amount equal to the net amount due either party based on the volumes per day multiplied by the difference between the NYMEX average price and the cap, if the NYMEX average price exceeded the cap price, or if the NYMEX average price was less than the floor price, then the volumes per day multiplied by the difference between the floor price and the NYMEX average price.
The net effect of these costless collar hedges was a $.05 per BBL reduction in the average crude oil price realized by the Company in 2000.
The Company had no oil or gas hedging contracts for future production as of December 31, 2000.
During 1999 and 1998, the Company had no oil or gas hedging transactions for its production.
NGM, from time to time, employs hedging arrangements in connection with its purchases and sales of production. While most of NGM's purchases are made for an index-based price, NGM's customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NGM may convert a fixed or NYMEX sale to an index-based sales price (such as by purchasing an index-based futures contract obligating NGM for delivery of production). Due to the size of such transactions and certain restraints imposed by contract and by Company guidelines, as of December 31, 2000, the Company had no material market risk exposure from NGM's hedging activity.
The Company has a $300 million credit agreement (see Note 3 - Debt, to the Consolidated Financial Statements) which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. All other Company long-term debt is fixed-rate and, therefore, does not expose the Company to the risk of earnings or cash flow loss due to changes in market interest rates.
On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized.
The Company does not invest in foreign currency derivatives. The U.S. dollar is considered the primary currency for each of the Company's international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and the Company does not believe it is currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense on the income statement. However, certain sales transactions are concluded in foreign currencies and the Company, therefore, is exposed to potential risk of loss based on fluctuation in exchange rates from time to time.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
All other financial statement schedules have been omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements, including the notes thereto.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Noble Affiliates, Inc.:
We have audited the accompanying consolidated balance sheet of Noble Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 2000. 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 auditing standards generally accepted in the United States. 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 Noble Affiliates, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma January 26, 2001
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY NOBLE AFFILIATES, INC. AND SUBSIDIARIES
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated accounts include Noble Affiliates, Inc. (the "Company") and the consolidated accounts of its wholly-owned subsidiaries: Noble Gas Marketing, Inc. ("NGM"); Noble Trading, Inc. ("NTI"); NPM, Inc.; and Samedan Oil Corporation ("Samedan"). Listed below are consolidated entities at December 31, 2000.
NOBLE AFFILIATES, INC. Noble Gas Marketing, Inc. Noble Gas Pipeline, Inc. Noble Trading, Inc. NPM, Inc. Samedan Oil Corporation Samedan of North Africa, Inc. Samedan International Machalapower Cia. Ltda. Samedan, Mediterranean Sea Samedan Transfer Sub Samedan Vietnam Limited Samedan, Mediterranean Sea, Inc. Samedan of Tunisia, Inc. Samedan Oil of Canada, Inc. Samedan Oil of Indonesia, Inc. Samedan Pipe Line Corporation Samedan Royalty Corporation Energy Development Corporation ("EDC") EDC Australia, Ltd. EDC Ecuador Ltd. EDC Ecuador Limited EDC Portugal Ltd. EDC (UK) Limited EDC (Denmark) Inc. EDC (Europe) Limited EDC (ISE) Limited EDC (Oilex) Limited Brabant Oil Limited Burnside Overseas Exploration Ltd. Energy Development Corporation (Argentina), Inc. Energy Development Corporation (China), Inc. Energy Development Corporation (HIPS), Inc. Gasdel Pipeline System Incorporated HGC, Inc. Producers Service, Inc.
NATURE OF OPERATIONS
The Company is an independent energy company engaged through its subsidiaries in the exploration, development, production and marketing of oil and gas. Samedan operates throughout the major basins in the United States, including the Gulf of Mexico, as well as international operations in Argentina, China, Ecuador, Equatorial Guinea, the
Mediterranean Sea, the North Sea, and Vietnam. The Company markets its oil and gas production through NGM, NTI and Samedan.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities. Such estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statements as well as amounts of revenues and expenses recognized during the reporting period. Of the estimates and assumptions that affect reported results, the estimate of the Company's oil and gas reserves is the most significant.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the primary currency for each of the Company's international operations. Transactions that are completed in a foreign currency are translated into U.S. dollars and recorded in the financial statements. Translation gains or losses were not material in any of the periods presented and are included in other expense on the income statement.
INVENTORIES
Materials and supplies inventories, consisting principally of tubular goods and production equipment, are stated at the lower of cost or market, with cost being determined by the first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for its oil and gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing oil and gas properties are amortized to operations by the unit-of-production method based on proved developed oil and gas reserves on a property-by-property basis as estimated by Company engineers. Estimated future restoration and abandonment costs are recorded by charges to depreciation, depletion and amortization ("DD&A") expense over the productive lives of the related properties. The Company has provided $79.7 million for such future costs classified with accumulated DD&A in the December 31, 2000 balance sheet. The total estimated future dismantlement and restoration costs of $136.1 million are included in future production and development costs for purposes of estimating the future net revenues relating to the Company's proved reserves. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
Individually significant undeveloped oil and gas properties are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other undeveloped properties are amortized on a composite method based on the Company's experience of successful drilling and average holding period. Geological and geophysical costs, delay rentals and costs to drill exploratory wells which do not find proved reserves are expensed. Repairs and maintenance are charged to expense as incurred.
Developed oil and gas properties and other long-lived assets are periodically assessed to determine if circumstances indicate that the carrying amount of an asset may not be recoverable. The Company performs this review of recoverability by estimating future cash flows. If the sum of the expected future cash flows is less than the carrying amount of the asset, an impairment is recognized based on the discounted amount of such cash flows.
INCOME TAXES
The Company files a consolidated federal income tax return. Deferred income taxes are provided for temporary differences between the financial reporting and tax bases of the Company's assets and liabilities.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the development and construction of significant properties or projects.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term investments include cash on hand and investments purchased with original maturities of three months or less.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic income per share of common stock has been computed on the basis of the weighted average number of shares outstanding during each period. The diluted net income per share of common stock includes the effect of outstanding stock options. The following table summarizes the calculation of basic earnings per share ("EPS") and diluted EPS components required by SFAS No. 128, as of December 31:
(1) In 1998, the diluted EPS is antidilutive as a result of the net operating loss; therefore, the basic EPS and diluted EPS are the same.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan and EDC have gas sales contracts with NGM, whereby Samedan and EDC are paid an index price for all gas sold to NGM. NGM records sales, including hedging transactions, as gathering, marketing and processing revenues. NGM records the amount paid to Samedan, EDC and third parties as cost of sales in gathering, marketing and processing. All intercompany sales and costs have been eliminated.
The Company follows an entitlements method of accounting for its gas imbalances. Gas imbalances occur when the Company sells more or less gas than its entitled ownership percentage of total gas production. Any excess amount received above the Company's share is treated as a liability. If less than the Company's entitlement is received, the underproduction is recorded as a receivable. The Company records the noncurrent liability in Other Deferred Credits and Noncurrent Liabilities, and the current liability in Other Current Liabilities. The Company's gas imbalance liabilities were $14.2 million and $12.0 million for 2000 and 1999, respectively. The Company records the noncurrent receivable in Other Assets, and the current receivable in Other Current Assets. The Company's gas imbalance receivables were $18.5 million and $17.9 million for 2000 and 1999, respectively, and are valued at the amount which is expected to be received.
TAKE-OR-PAY SETTLEMENTS
The Company records gas contract settlements which are not subject to recoupment in Other Income when the settlement is received.
TRADING AND HEDGING ACTIVITIES
The Company, through its subsidiaries, from time to time, uses various hedging arrangements in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such arrangements include fixed price hedges, costless collars, and other contractual arrangements. Although these hedging arrangements expose the Company to credit risk, the Company monitors the creditworthiness of its counterparties, which generally are major financial institutions, and believes that losses from nonperformance are unlikely to occur. Hedging gains and losses related to the Company's oil and gas production are recorded in oil and gas sales and royalties. The swap component of the contracts discussed in the following paragraphs was treated as a hedge for accounting purposes only.
The Company had entered into three crude oil premium swap contracts related to its production for calendar year 2000. Two of the contracts provided for payments based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL. These two contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the settlement price for each NYMEX trading day was less than the trigger price, provided the NYMEX price was also greater than the $17.00 per BBL knockout price. If a daily settlement price was $17.00 per BBL or less, then neither party had any liability to the other for that day. If a daily settlement price was above the applicable trigger price, then the Company would owe the counterparty for the excess of the settlement price over the trigger price for that day. Payment was made monthly under each of these contracts, in an amount equal to the net amount due to either party based on the sum of the daily amounts determined as described in this paragraph for that month.
The third contract related to 2,500 BBLS per day and provided for payments based on monthly average NYMEX settlement prices. The contract entitled the Company to receive monthly settlements from the counterparty in an amount, if any, by which the arithmetic average of the daily NYMEX settlement prices for the month was less than the trigger price, which was $21.73 per BBL, multiplied by the number of days in the month, provided such average NYMEX price was also greater than the $17.00 per BBL knockout price. If the average NYMEX settlement price for the month was $17.00 per BBL or less, then neither party would have any liability to the other for that month. If the average NYMEX settlement price for the month was above the trigger price, then the Company would pay the counterparty an amount equal to the excess of the average settlement price over the trigger price, multiplied by the number of days in the month.
The net effect of these premium swap contracts was a $2.87 per BBL reduction in the average crude oil price realized by the Company in 2000.
The Company has treated the swap component of these contracts as a hedge (for accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20 per BBL, which existed at the dates it entered into these contracts. In addition, the Company has separately accounted for the premium component of these contracts by marking them to market, resulting in a gain of $2,921,000 recorded in other income for the year ended December 31, 2000.
In addition to the premium swap crude oil hedging contracts, the Company had entered into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the Company to receive settlements from the counterparties in amounts, if any, by which the monthly average settlement price for each NYMEX trading day during a contract month was less than the floor price. If the monthly average settlement price was above the applicable cap price, then the Company would owe the counterparties for the excess of the monthly average settlement price over the applicable cap price. If
the monthly average settlement price fell between the applicable floor and cap price, then neither party would have any liability to the other party for that month. Payment, if any, was made monthly under each of the contracts in an amount equal to the net amount due either party based on the volumes per day multiplied by the difference between the NYMEX average price and the cap, if the NYMEX average price exceeded the cap price, or if the NYMEX average price was less than the floor price, then the volumes per day multiplied by the difference between the floor price and the NYMEX average price.
The net effect of these costless collar hedges was a $.05 per BBL reduction in the average crude oil price realized by the Company in 2000.
The Company had no oil or gas hedging contracts for future production as of December 31, 2000.
During 1999 and 1998, the Company had no oil or gas hedging transactions for its production.
In addition to the hedging arrangements pertaining to the Company's production as described above, NGM employs various hedging arrangements in connection with its purchases and sales of third party production to lock in profits or limit exposure to gas price risk. Most of the purchases made by NGM are on an index basis; however, purchasers in the markets in which NGM sells often require fixed or NYMEX related pricing. NGM may use a hedge to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility. During 2000, NGM had hedging transactions with broker-dealers that ranged from 423,000 MMBTU to 1,023,000 MMBTU of gas per day. At December 31, 2000, NGM had in place hedges ranging from approximately 20,000 MMBTU to 1,133,000 MMBTU of gas per day for January 2001 to May 2006 for future physical transactions.
In 1999, NGM had hedging transactions with broker-dealers that ranged from 146,000 MMBTU to 815,000 MMBTU of gas per day. During 1998, NGM had hedging transactions with broker-dealers that ranged from 508,811 MMBTU to 1,061,536 MMBTU of gas per day. NGM records hedging gains or losses relating to fixed term sales as gathering, marketing and processing revenues in the periods in which the related contract is completed.
SELF-INSURANCE
The Company self-insures the medical and dental coverage provided to certain of its employees, certain workers' compensation and the first $200,000 of its general liability coverage.
A provision for self-insured claims is recorded when sufficient information is available to reasonably estimate the amount of the loss.
UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company ("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent interest in Atlantic Methanol Production Company ("AMPCO"). The Company accounts for its interest in AMCCO using the equity method within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating with a 50 percent expense interest (45 percent ownership net of a five percent government carried interest) to construct a methanol plant in Equatorial Guinea.
RECLASSIFICATION
Certain reclassifications have been made to the 1999 and 1998 consolidated financial statements to conform to the 2000 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1998. The Statement establishes
accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value. The Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met wherein gains and losses are reflected in shareholders' equity until the hedged item is recognized. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS No. 133, the Company is required to adopt the statement for fiscal years beginning after June 15, 2000. A company may also implement the statement as of the beginning of any fiscal quarter after the statement's issuance (that is, fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired, or substantively modified after December 31, 1997 (and, at the Company's election, before January 1, 1998).
During 2000, the FASB issued SFAS No. 138 which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and certain hedging activities and should be adopted concurrently with SFAS No. 133, according to its provisions and the issuance of SFAS No. 137. The normal purchases and normal sales exception may be applied to contracts that implicitly or explicitly permit net settlement and contracts that have a market mechanism to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138 effective January 1, 2001. The adoption of these FASB's did not have a material impact on the Company's results of operations or financial position.
NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each class of financial instruments pursuant to the requirements of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments."
CASH AND SHORT-TERM INVESTMENTS
The carrying amount approximates fair value due to the short maturity of the instruments.
OIL AND GAS PRICE HEDGE AGREEMENTS
The fair value of oil and gas price hedges is the estimated amount the Company would receive or pay to terminate the hedge agreements at the reporting date taking into account creditworthiness of the hedging parties.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's financial instruments as of December 31, for each of the years are as follows:
NOTE 3 - DEBT
A summary of debt at December 31 follows:
The Company's total long-term debt, net of unamortized discount, at December 31, 2000, was $525 million compared to $445 million at December 31, 1999. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 38 percent at December 31, 2000, compared with 39 percent at December 31, 1999.
The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100 million of 7 1/4% Senior Debentures Due 2097 and the outstanding balance of $80 million on a $300 million credit facility. Other than the $80 million due on the credit facility, there is no principal payment due on long term debt during the next five years.
The Company has a $300 million credit facility which exposes the Company to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2000, there was $80 million borrowed against the credit facility which has a maturity date of December 24, 2002. The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the Company had no borrowing outstanding on this facility.
On June 17, 1999, the Company entered into a new $100 million 364 day credit agreement with certain commercial lending institutions. This agreement, which is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the percentage of utilization, expired in 2000 without ever having been utilized.
NOTE 4 - INCOME TAXES
The following table details the difference between the federal statutory tax rate and the effective tax rate for the years ended December 31:
The net current deferred tax asset (liability) in the following table is classified as Other Current Assets in the Consolidated Balance Sheet. The tax effects of temporary differences which gave rise to deferred tax assets and liabilities as of December 31 were:
The components of income from operations before income taxes for each year are as follows:
The income tax provision (benefit) relating to operations for each year consists of the following:
NOTE 5 - COMMON STOCK, STOCK OPTIONS AND STOCKHOLDER RIGHTS
The Company has two stock option plans, the 1992 Stock Option and Restricted Stock Plan ("1992 Plan") and the 1988 Non-Employee Director Stock Option Plan ("1988 Plan"). The Company accounts for these plans under APB Opinion 25. Compensation expense totaling $781,275 was recognized in 2000, due to the accelerated vesting of stock options as a result of the retirement of certain employees and is recorded in selling, general and administrative expense in the accompanying Consolidated Statement of Operations.
Under the Company's 1992 Plan, the Board of Directors may grant stock options and award restricted stock. No restricted stock has been issued under the 1992 Plan. Since the adoption of the 1992 Plan, stock options have been issued at the market price on the date of grant. The earliest the granted options may be exercised is over a three year period at the rate of 33 1/3% each year commencing on the first anniversary of the grant date. The options expire ten years from the grant date. The 1992 Plan was amended in 2000, by a vote of the shareholders, to increase the maximum number of shares of common stock that may be issued under the 1992 Plan to 6,500,000 shares. At December 31, 2000, the Company had reserved 5,799,221 shares of common stock for issuance, including 2,353,006 shares available for grant, under its 1992 Plan.
The Company's 1988 Plan allows stock options to be issued to certain non-employee directors at the market price on the date of grant. The options may be exercised one year after issue and expire ten years from the grant date. The 1988 Plan provides for the grant of options to purchase a maximum of 550,000 shares of the Company's authorized but unissued common stock. At December 31, 2000, the Company had reserved 399,000 shares of common stock for issuance, including 165,500 shares available for grant, under its 1988 Plan.
The Company adopted a stockholder rights plan on August 27, 1997, designed to assure that the Company's stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right ("Right") on each share of Noble Affiliates, Inc. common stock. Each Right will entitle the holder to purchase one one-hundredth of a share of a new Series A Junior Participating Preferred Stock, par value $1.00 per share, at an exercise price of $150.00. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires beneficial ownership of 15 percent or more of Noble Affiliates, Inc. common stock. The dividend distribution was made on September 8, 1997, to stockholders of record at the close of business on that date. The Rights will expire on September 8, 2007.
Stock options outstanding under the plans mentioned above and one previously terminated plan are presented for the periods indicated.
The SFAS No. 123 method of accounting is based on several assumptions and should not be viewed as indicative of the operations of the Company in future periods. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for grants in 2000, 1999 and 1998, respectively, as follows:
The weighted average fair value of options granted using the Black-Scholes option pricing model for 2000, 1999 and 1998, respectively, is as follows:
The Company applies APB Opinion No. 25 in accounting for its fixed price stock options. Compensation expense totaling $781,275 was recognized in 2000, due to the accelerated vesting of stock options as a result of the retirement of certain employees. The table below sets forth the Company's net income and earnings per share for each of the years ended December 31, as reported and on a pro forma basis as if the compensation cost of stock options had been determined consistent with SFAS No. 123, "Accounting for Stock-Based Compensation."
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a non-contributory defined benefit pension plan covering substantially all of its domestic employees. The benefits are based on an employee's years of service and average earnings for the 60 consecutive calendar months of highest compensation. The Company also has an unfunded restoration plan to ensure payments of amounts for which employees are entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. The Company's funding policy has been to make annual contributions equal to the actuarially computed liability to the extent such amounts are deductible for income tax purposes. Plan assets consist of equity securities and fixed income investments.
The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and life insurance benefits. The following table reflects the required SFAS No. 132, "Employers' Disclosures About Pension and Other Postretirement Benefits," disclosures at December 31:
The following table reflects the aggregate pension obligation components required by SFAS No. 132 for the defined benefit pension plan and the restoration benefit plan, which are aggregated in the previous tables, at December 31:
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following results:
EMPLOYEE SAVINGS PLAN ("ESP")
The Company has an ESP which is a defined contribution plan. Participation in the ESP is voluntary and all regular employees of the Company are eligible to participate. The Company may match up to 100 percent of the participant's contribution not to exceed six percent of the employee's base compensation. The following table indicates the Company's contribution for the years ended December 31:
NOTE 7 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful accounts at December 31:
Other current assets include the following at December 31:
Other current liabilities include the following at December 31:
Oil and gas operations expense included the following for the years ended December 31:
Oil and gas exploration expense included the following for the years ended December 31:
During the past three years, there was no purchaser that accounted for more than ten percent of total oil and gas sales and royalties.
NOTE 8 - IMPAIRMENT OF LONG-LIVED ASSETS
The Company follows SFAS No. 121 and any assets impaired are oil and gas properties maintained under the successful efforts method of accounting. The excess of the net book value over the projected discounted future net revenue of the impaired properties is charged to "Impairment of Operating Assets." The Company recorded no asset impairments under SFAS No. 121 during 2000 or 1999. In December 1998, the Company recorded a $223.3 million pre-tax charge for the write-down under SFAS No. 121 of properties due to downward reserve revisions.
NOTE 9 - UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, AMCCO, a 50 percent owned joint venture that owns an indirect 90 percent interest in AMPCO. The Company accounts for its interest in AMCCO using the equity method within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating with a 50 percent expense interest (45 percent ownership net of a five percent government carried interest) to construct a methanol plant in Equatorial Guinea. The total projected cost of the plant and supporting facilities is estimated to be $448 million including various contingencies and capitalized interest, with the Company responsible for $224 million. The plant is designed to produce 2,500 metric tons of methanol per day, which equates to approximately 20,000 BBLS per day. At this level of production, the plant would use approximately 125 MMCF of gas per day from the Alba field as feedstock. Reserve estimates indicate the Alba field can deliver sufficient gas for the plant to operate 30 years. The construction contract stipulates that first production should be achieved by the second quarter of 2001. Current marketing plans are to use two tankers, which are under long-term contracts, to transport the methanol to markets in Europe and the United States. On November 10, 1999, AMCCO issued $125 million of 10.875% Series A-1 Senior Secured Notes and $125 million of 8.95% Series A-2 Senior Secured Notes ("Series A-2 Notes") due 2004, which are not included in the Company's balance sheet. The Company has guaranteed the payment of interest on the Series A-2 Notes. In addition, the Company established a new series of preferred stock, Series B Mandatory Convertible Preferred Stock, par value $1.00 per share (the "Series B Preferred"). The Company issued, in a private placement pursuant to Section 4(2) of the Securities Act, 125,000 shares of the Series B Preferred to Noble Share Trust, which is a Delaware statutory business trust, in exchange for all of the beneficial ownership interests in Noble Share Trust. Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit of the holders of the Series A-2 Notes. The following are summarized financial statements for AMCCO as of December 31:
CONSOLIDATED BALANCE SHEET ATLANTIC METHANOL CAPITAL COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited)
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that can not be precisely measured, and estimates of engineers other than Samedan's might differ materially from the estimates set forth herein. 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.
PROVED GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers and sets forth the changes in estimated quantities of proved gas reserves of the Company during each of the three years presented.
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PROVED OIL RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers and sets forth the changes in estimated quantities of proved oil reserves of the Company during each of the three years presented.
PROVED RESERVES. Proved reserves are estimated quantities of crude oil, natural gas, natural gas liquids and condensate liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
PROVED DEVELOPED RESERVES. Proved developed reserves are proved reserves which are expected to be recovered through existing wells with existing equipment and operating methods.
OIL AND GAS OPERATIONS (Unaudited)
Aggregate results of operations for each period ended December 31, in connection with the Company's oil and gas producing activities are shown below. Amounts are presented in accordance with SFAS No. 19, and may not agree with amounts determined using traditional industry definitions.
*Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121.
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities for each of the years are shown below. Amounts are presented in accordance with SFAS No. 19, and may not agree with amounts determined using traditional industry definitions.
AGGREGATE CAPITALIZED COSTS (Unaudited)
Aggregate capitalized costs relating to the Company's oil and gas producing activities, and related accumulated DD&A, as of December 31 are shown below:
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (Unaudited)
The following information is based on the Company's best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2000, 1999 and 1998 in accordance with SFAS No. 69. The Standard requires the use of a 10 percent discount rate. This information is not the fair market value nor does it represent the expected present value of future cash flows of the Company's proved oil and gas reserves.
Construction of AMPCO's Equatorial Guinea methanol plant is scheduled to be completed in the second quarter of 2001. The future net cash inflows for 1998, 1999 and 2000 do not include cash flows relating to the Company's anticipated future methanol sales. For more information regarding Samedan's methanol plant, see Item 1. "Business--Unconsolidated Subsidiary" and Item 2. "Properties--Oil and Gas" of this Form 10-K.
Future cash inflows are estimated by applying year-end prices of oil and gas relating to the Company's proved reserves to the year-end quantities of those reserves, with consideration given to the effect of existing hedging contracts, if any.
The year-end NYMEX West Texas intermediate crude oil price utilized in the computation of future cash inflows was $26.83 per BBL, which was adjusted by differentials applied on a property-by-property basis to yield a weighted average price of $24.27 per BBL. The West Texas intermediate crude oil price, as of February 28, 2001, was $27.38 per BBL, an increase of $.55 per BBL compared to year-end 2000. The Company estimates that a $1.00 per BBL change in the average oil price from the year-end price would change discounted future net cash flows before income taxes by approximately $76 million.
The year-end Henry Hub natural gas price utilized in the computation of future cash inflows was $10.53 per MCF, which was adjusted by differentials applied on a property-by-property basis to yield a weighted average price of $9.14 per MCF. As of February 28, 2001, natural gas index prices at Henry Hub had decreased approximately $5.36 per MCF to $5.17 per MCF compared with the year-end price. The Company estimates that a $.10 per MCF change in the average gas price from the year-end price would change discounted future net cash flows before income taxes by approximately $45 million.
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the Company's proved oil and gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to the Company's proved oil and gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations relating to the Company's proved oil and gas reserves.
At December 31, 2000, the Company had estimated gas imbalance receivables of $18.5 million and estimated gas imbalance liabilities of $14.2 million; at year-end 1999, $17.9 million in receivables and $12.0 million in liabilities; and at year-end 1998, $19.1 million in receivables and $14.8 million in liabilities. Neither the gas imbalance receivables nor gas imbalance liabilities have been included in the standardized measure of discounted future net cash flows as of each of the three years ended December 31, 2000, 1999 and 1998.
SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited)
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves, as required by Financial Accounting Standards Board's SFAS No. 69, at year end are shown below.
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 2000 and 1999 is as follows:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The section entitled "Election of Directors" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to the directors of the Registrant and is incorporated herein by reference. Certain information with respect to the executive officers of the Registrant is set forth under the caption "Executive Officers of the Registrant" in Part I of this report.
The section entitled "Section 16(a) Beneficial Ownership Reporting Compliance" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, and is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The section entitled "Executive Compensation" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to the compensation of management of the Registrant, and except for the report of the Compensation, Benefits and Stock Option Committee of the Board of Directors and the information therein under "Executive Compensation--Performance Graph" is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The sections entitled "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Directors and Executive Officers" in the Registrant's proxy statement for the 2001 annual meeting of stockholders set forth certain information with respect to the ownership of the Registrant's common stock and are incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The section entitled "Certain Transactions" in the Registrant's proxy statement for the 2001 annual meeting of stockholders sets forth certain information with respect to certain relationships and related transactions, and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
(1) Financial Statements and Financial Statement Schedules and Supplementary Data: These documents are listed in the Index to Consolidated Financial Statements in Item 8 hereof.
(2) Exhibits: The exhibits required to be filed by this Item 14 are set forth in the Index to Exhibits accompanying this report.
(b) The Registrant made no filings on Form 8-K during 2000.
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.
NOBLE AFFILIATES, INC.
Date: March 12, 2001 By: /s/ James L. McElvany ----------------------------------------- James L. McElvany, Vice President-Finance and Treasurer
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 and on the dates indicated.
DIRECTORS
ROBERT KELLEY CHAIRMAN OF THE BOARD, NOBLE AFFILIATES, INC.
CHARLES D. DAVIDSON PRESIDENT AND CHIEF EXECUTIVE OFFICER, NOBLE AFFILIATES, INC.
ALAN A. BAKER CONSULTANT AND FORMER CHAIRMAN AND CHIEF EXECUTIVE OFFICER, HALLIBURTON ENERGY SERVICES
MICHAEL A. CAWLEY TRUSTEE, PRESIDENT AND CHIEF EXECUTIVE OFFICER, THE SAMUEL ROBERTS NOBLE FOUNDATION, INC.
EDWARD F. COX PARTNER, LAW FIRM OF PATTERSON, BELKNAP, WEBB AND TYLER
THOMAS E. HASSEN MANAGING DIRECTOR, CO-HEAD GLOBAL ENERGY RESOURCES GROUP, CREDIT SUISSE FIRST BOSTON CORPORATION
DALE P. JONES CONSULTANT AND FORMER VICE CHAIRMAN AND PRESIDENT, HALLIBURTON COMPANY
HAROLD F. KLEINMAN OF COUNSEL, LAW FIRM OF THOMPSON & KNIGHT L.L.P.
T. DON STACY FORMER CHAIRMAN AND PRESIDENT, AMOCO EURASIA PETROLEUM CO.
DIRECTORS EMERITI
GEORGE J. MCLEOD JOHN F. SNODGRASS JACK D. WILKES
EXECUTIVE OFFICERS
ROBERT KELLEY CHAIRMAN OF THE BOARD, NOBLE AFFILIATES, INC.
CHARLES D. DAVIDSON PRESIDENT AND CHIEF EXECUTIVE OFFICER, NOBLE AFFILIATES, INC.
ALAN R. BULLINGTON VICE PRESIDENT AND GENERAL MANAGER, INTERNATIONAL DIVISION OF SAMEDAN OIL CORPORATION
ROBERT K. BURLESON PRESIDENT, NOBLE GAS MARKETING, INC.
DAN O. DINGES SENIOR VICE PRESIDENT AND GENERAL MANAGER, OFFSHORE DIVISION OF SAMEDAN OIL CORPORATION
ALBERT D. HOPPE SENIOR VICE PRESIDENT, GENERAL COUNSEL, AND SECRETARY, NOBLE AFFILIATES, INC.
JAMES L. MCELVANY VICE PRESIDENT, CHIEF FINANCIAL OFFICER, TREASURER, AND ASSISTANT SECRETARY, NOBLE AFFILIATES, INC.
RICHARD A. PENEGUY, JR. VICE PRESIDENT AND GENERAL MANAGER, ONSHORE DIVISION OF SAMEDAN OIL CORPORATION
W. A. POILLION SENIOR VICE PRESIDENT-PRODUCTION AND DRILLING, SAMEDAN OIL CORPORATION
KENNETH P. WILEY VICE PRESIDENT-INFORMATION SYSTEMS, NOBLE AFFILIATES, INC.
CORPORATE AND SUBSIDIARY OFFICES NOBLE AFFILIATES, INC.
CORPORATE HEADQUARTERS 350 GLENBOROUGH DRIVE SUITE 100 HOUSTON, TEXAS 77067 (281) 872-3100
INVESTOR RELATIONS WILLIAM R. MCKOWN III ASSISTANT TREASURER (281) 872-3100 INVESTOR_RELATIONS@SAMEDAN.COM WWW.NOBLEAFF.COM
SUBSIDIARY HEADQUARTERS
SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 100 HOUSTON, TEXAS 77067
NOBLE GAS MARKETING, INC. 350 GLENBOROUGH DRIVE SUITE 180 HOUSTON, TEXAS 77067
NOBLE TRADING, INC. 110 WEST BROADWAY POST OFFICE BOX 909 ARDMORE, OKLAHOMA 73402
OPERATIONAL OFFICES
DOMESTIC OFFSHORE SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 240 HOUSTON, TEXAS 77067
DOMESTIC ONSHORE SAMEDAN OIL CORPORATION 12600 NORTHBOROUGH DRIVE SUITE 250 HOUSTON, TEXAS 77067
INTERNATIONAL SAMEDAN OIL CORPORATION 350 GLENBOROUGH DRIVE SUITE 300 HOUSTON, TEXAS 77067
INDEPENDENT PUBLIC ACCOUNTANTS ARTHUR ANDERSEN LLP OKLAHOMA CITY, OKLAHOMA
TRANSFER AGENT AND REGISTRAR FIRST CHICAGO TRUST COMPANY OF NEW YORK A DIVISION OF EQUISERVE POST OFFICE BOX 2500 JERSEY CITY, NEW JERSEY 07303 (800) 317-4445 WWW.EQUISERVE.COM HEARING IMPAIRED (201) 222-4955
COMMON STOCK LISTED NEW YORK STOCK EXCHANGE SYMBOL - NBL
- ------------------------------------------------------------------------------- ANNUAL MEETING The Annual Meeting of Stockholders of Noble Affiliates, will be held on Tuesday, April 24, 2001, 9:30 a.m. at the Wyndham Greenspoint Hotel located at 12400 Greenspoint Drive in Houston, Texas. All stockholders are cordially invited to attend.
FORM 10-K The Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Securities and Exchange Commission, is included in this report. Additional copies are available without charge upon request by writing to the Chief Financial Officer, Noble Affiliates, Inc., 350 Glenborough Drive, Suite 100, Houston, Texas 77067, via the Company's Internet website: http://www.nobleaff.com, or via the Securities and Excange Commission's Internet website: http://www.sec.gov. - -------------------------------------------------------------------------------