ITEM 1. BUSINESS.
Part I and Part II of this Annual Report on Form 10-K include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Annual Report on Form 10-K and the documents incorporated herein by reference regarding the Company's estimates of oil and gas reserves and the future net cash flows attributable thereto, anticipated capital expenditures, business strategy, plans and objectives of management of the Company for future operations and industry conditions, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from the Company's expectations ("Cautionary Statements") include without limitation future production levels, future prices and demand for oil and gas, results of future exploration and development activities, future operating and development costs, the effect of existing and future laws and governmental regulations (including those pertaining to the environment) and the political and economic climate of the United States and the foreign countries in which the Company operates from time to time, as discussed in this Annual Report on Form 10-K and the other documents of the Company filed with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements.
GENERAL
Noble Affiliates, Inc. is a Delaware corporation organized in 1969. The Registrant 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 are expressed in barrels ("BBLS"); and 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"), million British Thermal Units ("MMBTU"); or barrel of oil equivalent ("BOE") converting gas to oil at six thousand cubic feet of gas to one barrel of oil.
OIL AND GAS
The Company's wholly owned subsidiary, Samedan, has been engaged in the exploration, production and marketing of oil and gas since 1932. Samedan has exploration, exploitation and production operations in nine prominent areas: four domestic areas and five international areas. The domestic areas consist of: offshore in the Gulf of Mexico, the Gulf Coast (Texas and Louisiana), the Mid Continent (Oklahoma and Southern Kansas), and the Rocky Mountain division (Colorado, Montana, North Dakota, Wyoming and California). The international areas of operations include Argentina, China, Ecuador, Equatorial Guinea and the U.K. Sector of the North Sea. For more information regarding Samedan's oil and gas properties, see "Item 2.
ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Company is located at 110 West Broadway, Ardmore, Oklahoma 73401. The principal office of Samedan is in Ardmore, Oklahoma. Samedan also maintains offices in Oklahoma City, Houston, Denver, United Kingdom, China and Ecuador. Samedan maintains three separate offices in Houston for its international, offshore and onshore oil and gas operations. NGM's office is located in Houston, Texas and NTI's office is located in Ardmore, Oklahoma.
OIL AND GAS
Samedan, by itself or through various arrangements with others, investigates potential oil and gas properties, seeks to acquire exploration rights in areas of interest and conducts exploratory activities, including geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which it acquired such exploration rights. During 1997, Samedan drilled or participated in the drilling of 384 gross (210.6 net) wells, comprised of 38 gross (7.7 net) international wells and 346 gross (202.9 net) domestic wells. Additionally, Samedan completed 87 square miles of 3-D and 145 miles of 2-D seismic programs in the Amistad field, Ecuador and two 3-D seismic programs covering 140 blocks in the Gulf of Mexico. For more information regarding Samedan's oil and gas properties, see "Item 1. Business -- Oil and Gas" of this Form 10-K.
Gulf of Mexico. In the Gulf of Mexico during 1997, Samedan drilled or participated in the drilling of 72 gross wells, 24 exploratory wells (10.99 net) and 48 development wells (22.28 net) in federal and state waters offshore Texas and Louisiana. Of the 72 gross wells, 60 wells (27.50 net) were completed as productive and 12 wells (5.76 net) were abandoned as dry holes. Samedan acquired 24 federal and seven state leases, in the offshore Gulf of Mexico sales during 1997. The Company intends to remain active in these areas of the Gulf of Mexico.
During 1997, a platform drilling rig was utilized on Samedan's 100 percent owned Main Pass 306 E platform, drilling five wells which were being completed at year end. The wells are expected to deliver approximately 1,000 BBLS of oil per day when fully operational.
Six wells were drilled in Samedan's 50 percent owned Vermilion 279 field during 1997. The wells logged oil and gas pay ranging from 61 to 230 feet in multiple zones. The field was producing approximately 3,500 BBLS of oil and 50 MMCF of gas per day from eight wells at year end 1997. Two additional wells remain to be completed, and a third well was being drilled at year end 1997. During 1998, Samedan expects to drill three additional wells in the field.
Samedan drilled three wells in its East Cameron 331/332 field in which it owns a 70.4 percent interest. At year end 1997, the A-16 well reached its target depth encountering approximately 87 feet of oil and gas pay in five zones. The well is expected to be completed in 1998. During 1998, Samedan expects to drill one additional well in the field.
At the South Timbalier 195 field, owned 100 percent, Samedan drilled three wells. One well had been completed at year end 1997, and the remaining two wells are scheduled to be completed in early 1998. The wells are expected to deliver approximately 45 MMCF of gas per day when fully operational. At year end 1997, Samedan was preparing to drill one additional well, the A-7.
Samedan installed a 3.5 mile pipeline in the South Timbalier production area in December 1997. The pipeline will allow for the flow of more gas from the production area by reducing the pipeline pressure and increasing pipeline capacity.
Drilling and completion operations were underway at year end on Samedan's 50 percent owned Main Pass 261 lease. The field contains three wells; two of which are completed and awaiting production facilities. The third well was drilling at year end 1997. Two additional wells are projected to be drilled in 1998. Production facilities are expected to be operational in the second quarter of 1998. When fully operational, the field is projected to produce approximately 40 MMCF of gas and 1,000 BBLS of oil per day, net to Samedan's interest.
Samedan drilled a successful infill well in its Ship Shoal 315 field. The 100 percent owned A-1 Sidetrack well encountered approximately 62 feet of pay in two zones. At year end 1997, the well was producing approximately 1,100 BBLS of oil and 12 MMCF of gas per day.
Samedan made a gas discovery on its 67 percent owned South Timbalier 220 lease during 1997. The discovery well encountered approximately 229 feet of pay as determined by electric logs. Development plans include drilling an additional well and installing production facilities. Initial production of approximately 15 MMCF of gas and 150 BBLS of oil per day, net to Samedan's interest, is projected to begin in the third quarter of 1998.
Development is underway on Samedan's 25 percent owned East Cameron 371/381 field which was a gas discovery in 400 feet of water. Completion operations on the two wells drilled and production facilities are scheduled to be finished in the second quarter of 1998. Two additional wells are scheduled to be drilled in 1998. Production from the field is expected to be approximately 22 MMCF of gas and 200 BBLS of oil per day, net to Samedan's interest.
An oil discovery was made on Vermilion 379 which is 25 percent owned by Samedan and located in 325 feet of water. The discovery well was drilled to a measured depth of 6,253 feet and logged 60 feet of apparent pay in one zone. Development plans include drilling five additional wells and installing production facilities. Initial production is expected to commence in the second quarter of 1999.
At Viosca Knoll 864, Samedan participated with a 35 percent working interest in a discovery well which logged approximately 200 feet of oil pay in five zones. The well is located in approximately 1,460 feet of water and tested oil rates as high as 4,350 BBLS of oil per day. Evaluation of the estimated development costs and potential reservoir size were underway at year end 1997.
Gulf Coast. During 1997, a productive well was drilled in Samedan's 23.2 percent owned Kaplan field, Vermilion Parish, Louisiana. The well was completed in the Camerina sand at approximately 16,810 feet. At year end 1997, the well was producing approximately 20 MMCF of gas and 800 BBLS of condensate per day. During 1998, Samedan anticipates participating in the drilling of three additional wells in the field.
Samedan successfully recompleted the Glenn #3 well in the South Lake Arthur gas field, Vermilion Parish, Louisiana. The well was plugged back to the Miogyp sand at 16,735 feet and was flowing 13.7 MMCF of gas per day at year end 1997.
Samedan also has a deep gas prospect lying beneath the South Lake Arthur field which encompasses approximately 5,000 acres. In order to test the deep prospective zone Samedan expects to drill a 20,000 foot test well in 1998.
In South Texas, seven wells were drilled in Samedan's 100 percent owned Rincon field, located in Starr County. The wells were completed in the Rincon or Vicksburg sands. During 1998, five wells are expected to be drilled.
Mid Continent. Samedan is actively drilling wells in its multiple objective Washita Mountain Front play in Beckham County, Oklahoma. Samedan participated in drilling eight wells during the year and each encountered 30 to 250 feet of oil and gas pay in multiple zones, as determined from electric logs. Samedan owns approximately 40
percent in 26,000 gross acres in the prospect. During 1998, Samedan expects to participate in drilling 15 wells. Additionally, Samedan has a 45 percent participation interest in a 3-D seismic program covering 227 square miles within this area.
Rocky Mountain. Samedan drilled 100 wells in its Bowdoin gas field located in Phillips and Valley counties, Montana. The wells were completed in the field pay, but also encountered a new shallow pay zone in the Niobrara formation. Gas from the field is sold under a long-term contract in which the price escalates monthly through May 2007. At year end 1997, the price was $4.31 per MMBTU.
In Dawson County, Montana, Samedan kept a drilling rig engaged throughout 1997, drilling horizontal oil wells in its Deer Creek prospect. Seven wells were drilled in the field during 1997, including five wells that had multiple lateral well bores. The typical well in the field stabilizes production at approximately 100 BBLS of oil per day. Samedan owns a 75 percent working interest in the prospect and anticipates keeping a rig active throughout 1998.
Argentina. Throughout 1997, two drilling rigs were utilized for expanding infill drilling in the El Tordillo oil field. At year end 1997, a third rig was placed in service to accelerate the drilling program. Twenty-six wells were completed in the main field during the year and drilling to a prospective deeper horizon was in process at year end. Samedan owns 13.7 percent interest in the El Tordillo field which in 1997 produced an average of 2,800 BBLS of oil per day, net to Samedan's interest.
China. Samedan opened its Beijing, China office during 1997 to operate its existing exploration activities and seek additional opportunities. Samedan currently owns and operates the Cheng Dao Xi and Cheng Zi Kou concessions in the southern portion of Bo Hai Bay, China. Samedan also owns a one-third interest in the Laopu and Getuo concessions located in the northern portion of Bo Hai Bay. During 1997, Samedan drilled a dry hole on the Laopu concession.
Drilling plans for 1998 include three wells on the Cheng Dao Xi concession and one well on the Getuo concession. It is anticipated that a drilling rig will be available during the second quarter of 1998 and two of the Cheng Dao Xi wells will be drilled consecutively. If successful, Samedan intends to present a development plan to the Chinese government for the Cheng Dao Xi field during 1998.
Ecuador. In 1997, Samedan opened an office in Guayaquil, Ecuador to manage the activities of its 864,126 acre offshore concession. The concession includes the Amistad gas field which was discovered in 1970, but was never developed. Additionally, during the year Samedan completed an 87 square mile 3-D seismic program on the Amistad gas field and a 145 mile 2-D seismic program within the concession. Samedan's Ecuador staff is focused on developing a gas market for the Amistad field. The best prospect appears to be supplying fuel to electric power plants. Ecuador's existing plants currently burn imported diesel or bunker fuel. Samedan is negotiating with the government and power producers to determine a mutually beneficial price and deliverability arrangement.
Equatorial Guinea. Samedan will be participating, with a 35 percent expense interest, in a joint venture to construct a methanol plant in Equatorial Guinea. The plant is estimated to cost $317 million and is being designed to produce 2,500 metric tons of methanol per day, which equates to approximately 20,000 BBLS per day. The plant will use the gas from Samedan's 35 percent owned Alba field as feedstock. The plant is being designed to utilize approximately 115 MMCF of gas per day. The gas will be priced at $.25 per MMBTU. The construction contract stipulates that first commercial production of methanol should be achieved by January 2001. Current marketing plans are to enter into long-term contracts with methanol users in the United States and Europe.
As a result of developing an economic market for the Alba gas through the methanol plant, Samedan added 322.2 BCF of gas to its proved reserves in 1997. Based upon its cash flow projections from methanol sales with the $.25 per MMBTU wellhead price, Samedan expects to realize a blended value of approximately $3.83 per MCF for its gas production from the Alba field. Based upon reserve estimates, the Alba field can deliver sufficient gas for the
plant to operate for 30 years. In conjunction with the plant investment, the Alba field owners are evaluating a plan to drill additional wells, install a platform and construct a pipeline system. The plan includes evaluating gas reinjection which would accelerate condensate production. During 1997, the Alba field produced approximately 2,300 BBLS of condensate per day, net to Samedan's interest.
U.K. Sector of the North Sea. Production commenced from Samedan's 20 percent owned Windermere property in mid 1997. The field, located in the southern gas basin of the North Sea, was producing 13.1 MMCF of gas per day at year end, net to Samedan's interest.
Development operations are underway for Samedan's 25 percent owned Malory field which is also located in the southern gas basin of the North Sea. Samedan estimates the production will commence in the fourth quarter of 1998. Samedan's projected share of production will be approximately 7.5 MMCF per day. At year end 1997, Samedan was drilling an exploratory well on the Goldeneye prospect in the North Sea.
Oil and Gas Reserves and Standardized Measure. The following table summarizes the estimated proved oil and gas reserves of Samedan and the standardized measure of discounted future net cash flows attributed thereto, as of December 31, 1997, 1996 and 1995. Additional information is contained in "Item 8. Financial Statements and Supplementary Data--Supplemental Oil and Gas Information (Unaudited)" of this Form 10-K, and incorporated herein by reference.
Samedan has less than five percent of its oil and gas sales volumes committed to long-term supply contracts and has no similar agreements with foreign governments or authorities in which Samedan acts as producer as of year end 1997.
Since January 1, 1997, 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 (the "EIA"). Samedan files Form 23, including reserve and other information, with the EIA.
At January 30, 1998, Samedan was drilling 32 gross (15.9 net) exploratory wells, and 15 gross (6.6 net) development wells. These wells are located onshore in the United States in California, Colorado, Louisiana, North Dakota, Oklahoma, Texas, Wyoming, Offshore Gulf of Mexico and internationally in Argentina and the U.K. Sector of the North Sea. These wells have objectives ranging from approximately 3,700 to 18,000 feet. The estimated drilling cost to Samedan of these wells is approximately $42.7 million if all are dry and approximately $61 million if all are completed as producing wells.
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.
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 $.19 per BBL in 1997 and $2.35 per BBL in 1996 and includes an increase of $.16 per BBL in 1995 from hedging.
(3) Reflects a reduction per MCF of $.12 in 1997, $.33 in 1996 and $.004 in 1995 from hedging.
(4) Gas production is converted to oil BBL equivalents based on the average sales prices per BBL of oil and per MCF of gas. Net production amounts used in the calculation of average sales prices for purposes of computing the conversion ratio exclude royalties. Conversion ratios for 1997, 1996 and 1995 are set forth below:
OFFSHORE GULF OF MEXICO OPERATIONS as of December 31, 1997
[MAP]
SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (interests rounded to nearest whole percent)
*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, 1997, 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 lease 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 lease 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.
There are no material pending legal proceedings, other than ordinary routine litigation incidental to the business of the Registrant and its subsidiaries, to which the Registrant or any of its subsidiaries is a party or of which any of their property is the subject.
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 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 16, 1998, with respect to the executive officers of the Registrant.
(1) Robert Kelley has served as President and Chief Executive Officer of the Registrant since August 1, 1986, 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 also serves as President and Chief Executive Officer of Samedan, positions he has 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.
(2) George L. DeMare, Jr. was promoted to Senior Vice President and Onshore Division Manager of Samedan on January 1, 1998. Prior thereto, he had served as Vice President and Onshore Division Manager of Samedan since 1989. Mr. DeMare has been a member of the Operating Committee of Samedan since January 31, 1995.
(3) William D. Dickson was promoted to Senior Vice President-Finance and Treasurer on January 1, 1998. Prior thereto, he served as Vice President-Finance and Treasurer of the Company since October 1985. He has served as Vice President-Finance, Treasurer and Assistant Secretary of Samedan since 1984 and as a member of the Operating Committee of Samedan since February 9, 1994.
(4) Dan O. Dinges was promoted to Senior Vice President and Division General Manager, Offshore Division of Samedan on January 1, 1998. Prior thereto, he 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.
(5) W. A. Poillion was promoted to Senior Vice President-Production and Drilling of Samedan on January 1, 1998. Prior thereto, he served as Vice President-Production and Drilling and 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.
(6) Orville Walraven has served as Corporate Secretary of the Registrant since January 1, 1989. He was promoted to Senior Vice President-Land of Samedan on January 1, 1998. Prior thereto, he served as Vice President-Land of Samedan and as a member of the Operating Committee of Samedan since January 1, 1989.
(7) James C. Woodson was promoted to Senior Vice President-Exploration of Samedan on January 1, 1998. Prior thereto, he served as Vice President-Exploration since September 1, 1983. Mr. Woodson has been a member of the Operating Committee of Samedan since August 1, 1986.
The terms of office for the officers of the Registrant continue until their successors are chosen and qualified. No 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 Bank One N.A., Post Office Box 26848, Oklahoma City, Oklahoma 73125.
Stockholders' Profile. As of December 31, 1997, the number of holders of record of Common Stock was 1,512. The following chart indicates the common stockholders by category.
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.
SIGNIFICANT EVENTS IN 1997
o For eight straight years the Company recorded record levels of gas production. o For nine straight years the Company recorded record levels of oil production. o The Company expended $356.9 million on acquisition, exploration and development costs during 1997. o The Company added 34.6 million BBLS of oil and 557.4 BCF of gas to its reserve base in 1997 primarily through drilling. o During 1997, the Company sold non-strategic Canadian properties for $43.1 million.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW FROM OPERATIONS
Net cash provided by operating activities was $445.6 million for 1997, a 17 percent and 86.5 percent increase from the $380.9 million and $238.9 million in 1996 and 1995, respectively. Cash and short-term cash investments decreased to $55.1 million at December 31, 1997, from $94.8 million at year-end 1996.
During 1997, the Company utilized its beginning cash balance and cash flow from operations to fund its exploration and development expenditures, as well as to repay $203 million in long-term debt.
The Company's current ratio (current assets divided by current liabilities) was 1.19:1 at December 31, 1997, compared with 1.13:1 at December 31, 1996.
RESERVES ADDED AND COST OF FINDING
During 1997, the Company spent $356.9 million on acquisitions, exploration and development of oil and gas properties. Total proved gas reserves increased from 1.16 TCF at year-end 1996 to 1.48 TCF at year-end 1997, and total proved oil reserves increased from 115.7 million BBLS at year-end 1996 to 130.9 million BBLS at year-end 1997.
An accepted method of calculating cost of finding is to divide the Company's expenditures for oil and gas acquisition, exploration and development by the net BOE's added during the year. Using this method, the Company's cost of finding for 1997 was $2.80 per BOE.
A three year summary of cost of finding follows:
- ---------------------------- *Three year weighted average
FINANCING
Total long-term debt at December 31, 1997 was $645 million compared to $848 million (including current portion) at December 31, 1996, a decrease of 24 percent. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 44 percent at December 31, 1997, compared with 54 percent at December 31, 1996.
The $300 million credit agreement is a revolving credit facility with a group of banks with a final maturity of December 24, 2002. The interest rate charged, which is based upon a Eurodollar rate plus 22.5 basis points, was 5.9 percent at December 31, 1997. Financial covenants include maintenance of a cash flow multiple of at least four times interest cost and maintenance of a debt level which does not exceed 60 percent of the Company's shareholders' equity plus its debt.
The $800 million credit agreement was terminated on December 24, 1997, and the outstanding balance of $200 million was refinanced in the $300 million credit agreement. The weighted average interest rate on the borrowings during 1997 was 6.9 percent.
Total long-term debt outstanding at December 31, 1997, included $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, and $100 million of 7 1/4 % Senior Debentures Due 2097.
The only principal payment on long-term debt due during the next five years is the outstanding balance of the $300 million credit agreement on December 24, 2002.
On November 1, 1996, all of the Company's $230 million 4 1/4% Convertible Subordinated Notes Due 2003 were converted into 6,275,510 shares of common stock.
OTHER
The Company follows an entitlements method of accounting for its gas imbalances. The Company's estimated gas imbalance receivables were $18.5 million and $19.3 million at December 31, 1997 and 1996, respectively, and estimated gas imbalance liabilities were $21.6 million and $21.7 million at December 31, 1997 and 1996, respectively. These imbalances are valued at the amount that is expected to be received or paid to settle the imbalances. The settlement of the imbalances can occur either during, or at the end of, the life of a well on a volume basis or by cash settlement. The Company does not expect that a significant portion of the settlements will occur in any one year. Thus, the Company believes the periodic settlement of gas imbalances will have little impact on its liquidity.
The Company has sold a number of non-strategic oil and gas properties over the past three years, recognizing pretax gains of approximately $15.9 million, $1.9 million and $3.6 million for 1997, 1996 and 1995, respectively. Total amounts of oil and gas reserves associated with these dispositions during the last three years were 6.6 million BBLS of oil and 89.3 BCF of gas. In 1997, the Company sold its Canadian operations for $43.1 million, with estimated reserves sold of 2.6 million BBLS of oil and 23.1 BCF of gas. The Company believes the disposition of non-strategic properties furthers the goal of concentrating its efforts on its strategic properties.
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.
In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation." The Company adopted the disclosure requirements of SFAS No. 123 during 1996 and has presented in the footnotes to its financial statements pro forma disclosure as if the provisions of SFAS No. 123 had been adopted for all years reported within the Company's financial statements.
The Financial Accounting Standards Board issued SFAS No. 128 "Earnings per Share," SFAS No. 129 "Disclosure of Information about Capital Structure," SFAS No. 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosure about Segments of an Enterprise and Related Information," in the first half of 1997. SFAS No. 128 and No. 129 are effective for the Company's financial statements in both interim and annual periods ending after December 15, 1997. SFAS No. 130 and No. 131 are effective for 1998. The Company adopted disclosure requirements of SFAS No. 128 and No. 129 in 1997 and has presented disclosure as if the provisions of SFAS No. 128 and No. 129 had been adopted for all years reported within the Company's financial statements.
RESULTS OF OPERATIONS
The Company's consolidated financial statements for the year ended December 31, 1997, include a full year of EDC operations as a wholly owned subsidiary of Samedan. The consolidated financial statements for the year ended December 31, 1996, include five months of consolidated operations. EDC was acquired by the Company on July 31, 1996.
NET INCOME AND REVENUES
1997 VERSUS 1996. Net income for 1997 was $99.3 million, or $1.75 per share, compared with $83.9 million, or $1.63 per share in 1996. The increase in net income was achieved through record gas production, substantially higher gas prices and the sale of non-strategic properties. Total revenues were $1,116.6 million in 1997 and $887.2 million in 1996.
Oil and gas revenues were $761.1 million in 1997, an increase of $156.5 million, or 26 percent, over 1996. The Company received an average oil price for 1997 of $17.86 per BBL, a two percent decrease from the average 1996 price of $18.28 per BBL. The average gas price increased 14 percent in 1997 to $2.48 per MCF from the 1996 average of $2.17 per MCF.
Gathering, marketing and processing revenues were $329.9 million, an increase of 21 percent from the $273.7 million in 1996. The increase reflects an increase in marketed volumes for each of NTI and NGM, both wholly owned subsidiaries of the Company.
Other income in 1997 was $25.6 million, compared with $8.9 million in 1996. Other income in 1997 included non-recurring income of $14.1 million resulting from the Company's sale of its Canadian operations, with estimated reserves sold of 2.6 million BBLS of oil and 23.1 BCF of gas. The proceeds of $43.1 million received from the sale of the Canadian properties were used to reduce the Company's debt existing under its credit agreement.
1996 VERSUS 1995. Net income for 1996 was $83.9 million, or $1.63 per share, compared with $4.1 million, or $.08 per share in 1995. The increase in net income was achieved through increased oil and gas production and substantially higher oil and gas prices. Total revenues were $887.2 million in 1996 and $487.0 million in 1995.
Oil and gas revenues were $604.6 million in 1996, an increase of $276.5 million, or 84 percent, over 1995. The Company received an average oil price for 1996 of $18.28 per BBL, a nine percent increase from the average 1995 price of $16.78 per BBL. The average gas price increased 26 percent in 1996 to $2.17 per MCF from the 1995 average of $1.72 per MCF. The increase in gas price was due primarily to higher demand and lower levels of gas storage than in the previous year.
Gathering, marketing and processing revenues were $273.7 million, an increase of 143 percent from the $112.7 million in 1995. The increase reflects a full year of operations for NTI and NGM.
Other income in 1996 was $8.9 million, compared with $46.2 million in 1995. Other income in 1995 included non-recurring income of $39.0 million resulting from the settlement of a Columbia Gas Transmission Corporation bankruptcy claim with Samedan.
NATURAL GAS INFORMATION
A three-year summary of gas-related information follows:
- -------------------- *The average price reflects a reduction per MCF of $.12 in 1997, $.33 in 1996 and $.004 in 1995 from hedging.
1997 VERSUS 1996. Gas sales for 1997 increased 37 percent to $499.4 million from $365.4 million in 1996. Average daily production in 1997 increased 20 percent to 565.4 MMCF from 469.4 MMCF in 1996.
The average gas price in 1997 increased 14 percent to $2.48 per MCF from $2.17 per MCF in 1996. During 1997, the Company's average gas prices ranged from a low of $1.80 in April to a high of $3.35 in January.
International sales accounted for three percent of 1997 gas sales compared with two percent in 1996. Average daily gas production outside of the United States was 20,873 MCF in 1997 and 5,757 MCF in 1996.
1996 VERSUS 1995. Gas sales for 1996 increased 118 percent to $365.4 million from $167.4 million in 1995. Average daily production in 1996 increased 72 percent to 469.4 MMCF from 272.2 MMCF in 1995.
The average gas price in 1996 increased 26 percent to $2.17 per MCF from $1.72 per MCF in 1995. During 1996, the Company's average gas prices ranged from a low of $1.82 in April and October to a high of $3.15 in December.
CRUDE OIL INFORMATION
A three-year summary of oil-related information follows:
- -------------------- *The average price reflects a reduction of $.19 per BBL in 1997 and $2.35 per BBL in 1996 and includes an increase of $.16 per BBL in 1995 from hedging.
1997 VERSUS 1996. Oil sales for 1997 increased eight percent to $243.6 million from $225.2 million in 1996. Average daily production in 1997 increased 11 percent to 38,345 BBLS from 34,520 BBLS in 1996.
The average oil price for 1997 was $17.86 per BBL, a two percent decrease from the 1996 average of $18.28 per BBL. The Company's 1997 average oil prices ranged from a low of $15.74 per BBL in December to a high of $21.92 per BBL in January.
International sales accounted for 19 percent of 1997 oil sales compared with 20 percent in 1996. Average daily oil production outside the United States was 8,250 BBLS in 1997 and 6,230 BBLS in 1996.
1996 VERSUS 1995. Oil sales for 1996 increased 47 percent to $225.2 million from $153.5 million in 1995. Average daily production in 1996 increased 35 percent to 34,520 BBLS from 25,617 BBLS in 1995.
The average oil price for 1996 was $18.28 per BBL, a nine percent increase from the 1995 average of $16.78 per BBL. The Company's 1996 average oil prices ranged from a low of $17.11 per BBL in January to a high of $19.74 per BBL in September.
International sales accounted for 20 percent of 1996 oil sales compared with 15 percent in 1995. Average daily oil production outside the United States was 6,230 BBLS in 1996 and 3,777 BBLS in 1995.
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 of its production 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 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.
During 1997, the Company had natural gas hedging contracts that ranged from 20 percent to 32 percent of its average daily natural gas production. Natural gas hedges were in the price range of $1.88 to $3.30 per MMBTU. The net effect of these 1997 hedges was a $.12 per MCF reduction in the average natural gas price realized by the Company. At December 31, 1997, the Company had no natural gas hedging contracts.
During 1997, the Company had crude oil hedging contracts that ranged from 19 percent to 50 percent of its average daily oil production. Crude oil hedges were in the price range of $16.81 to $24.35 per BBL. The net effect of these 1997 hedges was a $.19 per BBL reduction in the average crude oil price realized by the Company. At December 31, 1997, the Company had no crude oil hedging contracts.
During 1996, the Company had natural gas hedging contracts that ranged from 39 percent to 86 percent of its average daily natural gas production. Natural gas hedges were in the price range of $1.60 to $3.59 per MMBTU. The net effect of these 1996 hedges was a $.33 per MCF reduction in the average natural gas price. At December 31, 1996, the Company was a party to natural gas hedging contracts to hedge approximately 21 percent of its estimated 1997 average daily natural gas production at an average price per MMBTU of $2.20.
During 1996, the Company had crude oil hedging contracts that ranged from 48 percent to 55 percent of its average daily oil production for January through July and 62 percent to 100 percent of its average daily oil production for August through December. Crude oil hedges were in the price range of $16.50 to $24.27 per BBL. The net effect of these 1996 hedges was a $2.35 per BBL reduction in the average crude oil price. At December 31, 1996, the Company was a party to crude oil hedging contracts to hedge approximately 26 percent of its estimated 1997 annual crude oil production at an average price per BBL of $20.48.
During 1995, Samedan had natural gas hedging contracts for November and December to hedge from 20 percent to 46 percent of its average daily natural gas production. For May to December 1995, Samedan had hedged approximately 20 percent of its daily crude oil production. Natural gas hedges were in the range of $1.60 to $1.96 per MMBTU and crude oil hedges were in the range of $18.56 to $20.27 per BBL. The net effect of these 1995 hedges was a $.004 per MCF reduction in the average natural gas price and a $.16 per BBL increase in the average crude oil price realized by the Company.
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 1997, NGM had hedging transactions with broker-dealers that ranged from 317,693 MMBTU's to 768,599 MMBTU's of gas per day.
At December 31, 1997, NGM had in place hedges ranging from approximately 645 MMBTU's to 29,279 MMBTU's of gas per day for January 1998 to March 1999 for future physical transactions. At December 31, 1996, NGM had in place hedges ranging from approximately 7,475 MMBTU's to 551,126 MMBTU's of gas per day for January 1997 to March 1998 for future physical transactions. During 1995, NGM had hedging transactions with large financial institutions that averaged approximately 126,000 MMBTU's of gas per day at prices linked to certain indices. 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.
COSTS AND EXPENSES
1997 VERSUS 1996. Oil and gas exploration expense increased in 1997 by $36.8 million from 1996 to $86.7 million. The increase resulted primarily from a $14.1 million increase in dry hole expense and a full year of EDC foreign exploration costs for 1997.
Oil and gas operations expense in 1997 increased $34.7 million from 1996 to $160.8 million. Lease operating expense increased $35 million in 1997 due to higher oil and gas production and a full year's ownership of EDC properties. Production taxes increased $1.8 million in 1997 due to higher production levels and gas prices.
In 1997, depreciation, depletion and amortization ("DD&A") expense increased $67 million over 1996 due to the higher production levels and a full year of production from the EDC properties. The unit rate of DD&A expense per BOE, converting gas to oil on a 6:1 basis, was $6.33 for 1997, compared with $5.66 for 1996.
The Company provides for the cost of future liabilities related to restoration and dismantlement costs for offshore facilities. This provision is based on the Company's best estimate of such costs to be incurred in future years based on information from the Company's engineers. These estimated costs are provided through charging DD&A expense using a ratio of production divided by reserves multiplied by the estimated costs to dismantle and restore. The Company has provided $59.5 million for such future restoration and dismantlement costs which are classified in accumulated DD&A on the balance sheet at December 31, 1997. Total estimated future dismantlement and restoration costs of $143.9 million are included in future production and development costs for purposes of estimating the future net revenues relating to the Company's proved reserves.
1996 VERSUS 1995. Oil and gas exploration expense increased in 1996 by $16.6 million from 1995 to $49.9 million. The increase resulted primarily from a $15.2 million increase in dry hole expense for 1996.
Oil and gas operations expense in 1996 increased $44.3 million from 1995 to $126 million. Lease operating expense increased $37.7 million in 1996 due to higher oil and gas production from a greater number of properties and the acquisition of EDC. Production taxes increased $6.7 million in 1996 due to higher production levels and oil and gas prices.
In 1996, DD&A expense increased $32.7 million over 1995 due to the record production levels and the EDC acquisition. The unit rate of DD&A expense per BOE, converting gas to oil on a 6:1 basis, was $5.66 for 1996, compared with $7.75 for 1995. The 1995 rate included $59.5 million of additional impairment for the writedown of certain long-lived assets in accordance with provisions of SFAS No. 121.
The Company has provided $51.6 million for future liabilities related to dismantlement and restoration costs which are classified in accumulated DD&A on the balance sheet at December 31, 1996. Total estimated future dismantlement and restoration costs of $130.2 million are included in future production and development costs for purposes of estimating the future net revenues relating to the Company's proved reserves.
In 1996, Selling, General and Administrative ("SG&A") expense increased $15.1 million over 1995 to $51.6 million. Administrative costs increased $11.1 million in 1996 due to the acquisition of EDC and the hiring of additional personnel to oversee increased operations. The Company estimates that approximately 32 percent of the EDC increase is due to non-recurring costs.
INTEREST EXPENSE
1997 VERSUS 1996. During 1997, interest expense increased $14.5 million from 1996 to $53 million. This increase was due primarily to the indebtedness of the Company incurred in the financing of the acquisition of EDC. During 1996, the interest on the EDC acquisition reflects five months costs compared to twelve months of interest during 1997.
1996 VERSUS 1995. In 1996, interest expense increased $16.6 million from 1995 to $38.5 million. This increase was due primarily to the financing of the EDC acquisition offset in part by the conversion into common stock on November 1, 1996, of the $230,000,000 4 1/4% Convertible Subordinated Notes Due 2003.
MARKETING SUBSIDIARIES
NGM markets the Company's natural gas, as well as certain third-party gas. NGM sells gas directly to end-users, gas marketers, industrial users, interstate and intrastate pipelines, and local distribution companies. The Company records all of NGM's non-affiliated sales as gathering, marketing and processing revenues. All intercompany sales and expenses have been eliminated.
NTI markets a portion of the Company's oil, as well as certain third-party oil. The Company records all of NTI's non-affiliated sales as gathering, marketing and processing revenues. All intercompany sales and expenses have been eliminated.
During 1997, NGM recorded $228.4 million in gathering, marketing and processing revenues and $218.8 million in gathering, marketing and processing expenses, generating a gross margin of $9.6 million for the year. In 1996, NGM recorded $197.4 million in gathering, marketing and processing revenues and $184.6 million in gathering, marketing and processing expenses, generating a gross margin of $12.8 million for the year. In 1995, NGM recorded $104.6 million in gathering, marketing and processing revenues and $100.6 million in gathering, marketing and processing expenses, generating a gross margin of $4.0 million for the year.
During 1997, NTI recorded $101.5 million in gathering, marketing and processing revenues and $95.0 million in gathering, marketing and processing expenses, generating a gross margin of $6.5 million for the year. In 1996, NTI recorded $76.3 million in gathering, marketing and processing revenues and $68.9 million in gathering, marketing and processing expenses, generating a gross margin of $7.4 million for the year. In 1995, NTI began marketing a portion of the Company's oil as well as certain third-party oil and recorded $8.1 million in gathering, marketing and processing revenues and $7.3 million in gathering, marketing and processing expenses, generating a gross margin of $791,000 for the year.
FUTURE TRENDS
The Company expects higher production volumes in 1998 compared to 1997. The increase in volume is expected primarily due to the production associated with oil and gas properties acquired from New England Energy Incorporated, effective January 1, 1998, as well as certain new oil and gas properties expected to commence
production during the year. Revenue, however, may also be impacted by commodity prices which are expected to remain volatile during 1998.
The Company has set its 1998 capital budget at approximately $400 million, exclusive of producing property acquisitions. The capital budget includes the expected 1998 expenditures for the first phase of construction for the Equatorial Guinea methanol plant and exploration, exploitation and development expenditures. The Company expects to fund the 1998 capital budget through its cash flow from operations. The Company will fund the New England Energy Incorporated property acquisition through short-term borrowings under its current $300 million credit agreement.
Samedan has from time to time settled various claims against parties which failed to fulfill their contractual obligation to Samedan to purchase gas at fixed prices greater than market or pursuant to take-or-pay provisions. The Company's policy, which is consistent with general industry practice, is that amounts received in such settlements ("settlement payments") do not represent payment for gas produced and, therefore, are not subject to royalty payments. Property owners, including governmental authorities and private parties, have in recent years asserted claims against Samedan and other oil and gas companies for royalties on settlement payments.
Samedan participated, in a joint effort with other energy companies and the Independent Petroleum Association of America ("IPAA"), in a test case which challenged the determination by the U.S. Minerals Management Service ("MMS") that royalties were payable to the government on certain settlement payments received by Samedan (and the other plaintiffs). The District Court for the District of Columbia (the "D.C. District Court") entered a judgment against Samedan in the amount of $20,000. In August 1996, the Court of Appeals for the District of Columbia Circuit reversed the judgment against Samedan. In subsequent proceedings in the D.C. District Court consistent with the appellate court decision, on July 25, 1997, the court enjoined the MMS from taking action to collect from Samedan royalties on non-recoupable settlement payments (the "MMS Injunction"). The MMS has until April 14, 1998 to appeal the MMS Injunction.
Notwithstanding the ultimate outcome with respect to the MMS Injunction, Samedan may be the subject of future legal actions by property owners claiming royalties on other settlement payments received by Samedan. There can be no assurance that Samedan will prevail in any such action. The Company is unable to estimate the possible amount of loss, if any, associated with this contingency.
Management believes that the Company is well positioned with its balanced reserves of oil and gas 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 hedging and may do so in the future as a means of controlling its exposure to price changes. The Company cannot predict the extent to which its operations will be impacted by inflation, government regulation or changing prices. Market risk is a new disclosure that the Company is required to report through quantitative and qualitative disclosures. The required disclosures are presented in the financial statements and footnotes. For more information concerning market risk, see "Item 8. Financial Statements and Supplementary Data--Supplemental Oil and Gas Information (Unaudited)" in this Form 10-K.
The Company is currently in the process of updating its computer software programs and operating systems so that these systems will properly utilize dates beyond December 31, 1999. The Company does not expect the cost to modify its information systems to be material to its financial condition or results of operations. The Company does not anticipate any material disruptions in its operations as a result of its year 2000 compliance plan.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Under the general instructions, the Registrant's disclosures about market risk pursuant to this item should be made in the Registrant's Form 10-K for the year ending December 31, 1998.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1997 and 1996, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Noble Affiliates, Inc. and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma January 30, 1998
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, 1997.
NOBLE AFFILIATES, INC. Noble Gas Marketing, Inc. Noble Gas Pipeline, Inc. Noble Trading, Inc. NPM, Inc. Samedan Oil Corporation Samedan Oil of Canada, Inc. Samedan of North Africa, Inc. Samedan LPG Samedan Methanol Samedan Pipe Line Corporation Samedan Royalty Corporation Samedan of Tunisia, Inc. Energy Development Corporation ("EDC") Brabant Petroleum Limited EDC Argentina, Inc. EDC Australia, Ltd. EDC China, Inc. EDC Ecuador Ltd. EDC HIPS, Inc. EDC Portugal Ltd. EDC Senegal Ltd. Gasdel Pipeline System Incorporated HGC, Inc. Producers Service, Inc.
NATURE OF OPERATIONS
The Company is principally 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 with production in Argentina, Equatorial Guinea and the U.K. Sector of the North Sea. 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 functional currency for each of the Company's international operations with the exception of Canada. The functional currency for Canada is the Canadian dollar which has been translated into U.S. dollars for the financial statements. Translation gains or losses were not material in any of the periods presented.
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 $59.5 million for such future costs classified with accumulated DD&A in the balance sheet. The total estimated future dismantlement and restoration costs of $143.9 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.
Undeveloped oil and gas properties, which are individually significant, 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.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
The Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 128 "Earnings per Share" in February 1997. The Company adopted disclosure requirements of SFAS No. 128 during 1997 and restated all previously presented financial statements in conformity with SFAS No. 128. 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 and the dilutive effect of the convertible subordinated notes, which were converted on November 1, 1996.
The following table summarizes the calculation of basic earnings per share ("EPS") and diluted EPS as of December 31:
(1) In 1995, the 4 1/4% Convertible Subordinated Notes were anti-dilutive and were converted on November 1, 1996.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the acquisition or construction of significant oil and gas properties.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term cash investments include cash on hand and investments purchased with original maturities of three months or less.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan and EDC have a gas sales contract 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 as cost of sales in gathering, marketing and processing costs, the amount paid to Samedan, EDC and third parties. 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 $21.6 million and $21.7 million for 1997 and 1996, 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 $19.3 million for 1997 and 1996, 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 of its production 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 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.
During 1997, the Company had natural gas hedging contracts that ranged from 20 percent to 32 percent of its average daily natural gas production. Natural gas hedges were in the price range of $1.88 to $3.30 per million British Thermal Units ("MMBTU"). The net effect of these 1997 hedges was a $.12 per thousand cubic feet ("MCF") reduction in the average natural gas price realized by the Company. At December 31, 1997, the Company had no natural gas hedging contracts.
During 1997, the Company had crude oil hedging contracts that ranged from 19 percent to 50 percent of its average daily oil production. Crude oil hedges were in the price range of $16.81 to $24.35 per barrel ("BBL"). The net effect of these 1997 hedges was a $.19 per BBL reduction in the average crude oil price realized by the Company. At December 31, 1997, the Company had no crude oil hedging contracts.
During 1996, the Company had natural gas hedging contracts that ranged from 39 percent to 86 percent of its average daily natural gas production. Natural gas hedges were in the price range of $1.60 to $3.59 per MMBTU. The net effect of these 1996 hedges was a $.33 per MCF reduction in the average natural gas price. At December 31, 1996, the Company was a party to natural gas hedging contracts to hedge approximately 21 percent of its estimated 1997 average daily natural gas production at an average price per MMBTU of $2.20.
During 1996, the Company had crude oil hedging contracts that ranged from 48 percent to 55 percent of its average daily oil production for January through July and 62 percent to 100 percent of its average daily oil production for August through December. Crude oil hedges were in the price range of $16.50 to $24.27 per BBL. The net effect of these 1996 hedges was a $2.35 per BBL reduction in the average crude oil price. At December 31, 1996, the Company was a party to crude oil hedging contracts to hedge approximately 26 percent of its estimated 1997 annual crude oil production at an average price per BBL of $20.48.
During 1995, Samedan had natural gas hedging contracts for November and December to hedge from 20 percent to 46 percent of its average daily natural gas production. For May to December 1995, Samedan had hedged approximately 20 percent of its daily crude oil production. Natural gas hedges were in the range of $1.60 to $1.96 per MMBTU and crude oil hedges were in the range of $18.56 to $20.27 per BBL. The net effect of these 1995 hedges was a $.004 per MCF reduction in the average natural gas price and a $.16 per BBL increase in the average crude oil price realized by the Company.
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 New York Mercantile Exchange ("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 1997, NGM had hedging transactions with broker-dealers that ranged from 317,693 MMBTU's to 768,599 MMBTU's of gas per day.
At December 31, 1997, NGM had in place hedges ranging from approximately 645 MMBTU's to 29,279 MMBTU's of gas per day for January 1998 to March 1999 for future physical transactions. At December 31, 1996, NGM had in place hedges ranging from approximately 7,475 MMBTU's to 551,126 MMBTU's of gas per day for January 1997 to March 1998 for future physical transactions. During 1995, NGM had hedging transactions with large financial institutions that averaged approximately 126,000 MMBTU's of gas per day at prices linked to certain indices. 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.
RECLASSIFICATION
Certain reclassifications have been made to the 1996 and 1995 consolidated financial statements to conform to the 1997 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
In December 1997, the Financial Accounting Standards Board issued SFAS No. 130 "Reporting Comprehensive Income" and SFAS No. 131 "Disclosures About Segments of an Enterprise and Related Information." The Company plans on adopting both SFAS No. 130 and No. 131 in 1998. The Company anticipates there will be no material impact associated with the adoption of these standards.
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 CASH 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 the 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:
Total long-term debt at December 31, 1997, was $645 million compared to $848 million (including current portion) at December 31, 1996, a decrease of 24 percent. The ratio of debt to book capital (defined as the Company's debt plus its equity) was 44 percent at December 31, 1997, compared with 54 percent at December 31, 1996.
The $300 million credit agreement is a revolving credit facility with a group of banks with a final maturity of December 24, 2002. The interest rate charged, which is based upon a Eurodollar rate plus 22.5 basis points, was 5.9 percent at December 31, 1997. Financial covenants include maintenance of a cash flow multiple of at least four times interest cost and maintenance of a debt level which does not exceed 60 percent of the Company's shareholders' equity plus its debt.
The $800 million credit agreement was terminated on December 24, 1997, and the outstanding balance of $200 million was refinanced in the $300 million credit agreement. The weighted average interest rate on the borrowings during 1997 was 6.9 percent.
Total long-term debt outstanding at December 31, 1997, included $100 million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, and $100 million of 7 1/4 % Senior Debentures Due 2097.
The only principal payment on long-term debt due during the next five years is the outstanding balance of the $300 million credit agreement on December 24, 2002.
On November 1, 1996, all of the Company's $230 million 4 1/4% Convertible Subordinated Notes Due 2003 were converted into 6,275,510 shares of common stock.
NOTE 4 - INCOME TAXES
The components of income from operations before income taxes for each year are as follows:
The income tax provisions relating to operations for each year consist of the following:
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 at December 31, 1997 and 1996. The tax effects of temporary differences which gave rise to deferred tax assets and liabilities as of December 31 were:
A valuation allowance of $3.9 million for 1996 related to the Company's foreign operations was established for the portion of the deferred tax assets which management believed unlikely to have a tax benefit realized. The valuation allowance for 1996 was related to Canada and was written off in 1997 due to the sale of the Company's Canadian assets.
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, under which no compensation cost has been recognized in the accompanying financial statements.
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 1992 Plan's adoption, 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 1997, with a vote of the shareholders, to increase the maximum number of shares of common stock that may be issued under the 1992 Plan to 4,000,000 shares. At December 31, 1997, the Company had reserved 3,735,166 shares of common stock for issuance, including 1,850,282 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, 1997, the Company had reserved 433,000 shares of common stock for issuance, including 274,000 shares available for grant under its 1988 Plan.
Stock options outstanding under the plans mentioned above and two previously terminated plans are presented for the periods indicated.
The following schedule shows the Company's net income and net income per share for each of the years ended December 31, had compensation costs been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation."
The SFAS No. 123 method of accounting is not required to be applied to options granted prior to 1995. The pro forma information presented above 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 1997, 1996 and 1995, respectively:
The weighted average fair value of options granted using the Black-Scholes option model for 1997, 1996 and 1995, respectively:
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.
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN
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 principally of equity securities and fixed income investments.
The periodic pension expense included the following components for the years ended December 31:
The funded status of the Company's pension plans at December 31 was as follows:
The Company's assumptions as of December 31 in determining the pension cost and liability for the three years were as follows:
EMPLOYEE SAVINGS PLAN
The Company has an employee savings plan ("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. Plan contributions of $1,369,000, $1,053,000 and $895,000 for 1997, 1996 and 1995, respectively, were charged to expense.
OTHER EMPLOYEE PLANS
The Company sponsors other plans for the benefit of its employees and retirees. These plans include health care and life insurance benefits. The accumulated postretirement benefit obligation of these plans was computed using an assumed discount rate of 7.25, 7.75 and 7.25 percent in 1997, 1996 and 1995, respectively. The health care cost trend rate was assumed to be nine percent for 1997, declining by one percent for three successive years to six percent in 2000 and 2001, decreasing to five percent for 2002 and remaining at that rate thereafter.
If the health care cost trend rate was increased one percent for all future years, the accumulated postretirement benefit obligation as of December 31, 1997, would have increased approximately $352,000. The effect of this change on the aggregate of service and interest cost for 1997 would have been an increase of approximately $55,000.
Net postretirement benefit cost included the following components for the years ended December 31:
The plan's postretirement benefit obligation at December 31 was as follows:
NOTE 7 - EDC ACQUISITION
On July 31, 1996, Samedan acquired all the outstanding shares of common stock of EDC for $768 million. The acquisition has been accounted for using the purchase method of accounting. Accordingly, the purchase price has been allocated to EDC's assets and liabilities based on fair values at the date of the acquisition.
The operating results of EDC have been included in the Consolidated Statement of Operations from the date of the acquisition. The pro forma information includes adjustments for interest expense that would have been incurred to finance the acquisition, additional depreciation, depletion and amortization based on the fair value of EDC's property, plant and equipment and expected savings from the termination of certain EDC employees and facilities consolidation.
The following information has been prepared assuming the acquisition had taken place at the beginning of 1996 and 1995:
The pro forma information presented above is based on several assumptions and should not be viewed as indicative of the operations of the Company in future periods.
NOTE 8 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful accounts at December 31 of the following:
Other current assets at December 31 include the following:
Other current liabilities at December 31 include the following:
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 9 - IMPAIRMENT OF LONG-LIVED ASSETS
In March 1995, the Financial Accounting Standards Board issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The Company adopted SFAS No. 121 during the fourth quarter of 1995.
The assets impaired under SFAS No. 121 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 was charged to DD&A expense. The Company recognized a $59.5 million SFAS No. 121 impairment for 1995. This impairment included $3.2 million in Tunisia, $4.1 million in Canada, $18.4 million onshore U.S., and $33.8 million offshore Gulf of Mexico properties.
The Company recorded no asset impairment under SFAS No. 121 for its properties during 1997 and 1996.
SUPPLEMENTAL OIL AND GAS INFORMATION (Unaudited)
PROVED OIL AND GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers and set forth the changes in estimated quantities of proved oil and gas reserves of the Company during each of the three years presented.
(1) The December 31, 1997, proved reserves for the Company's international operations are detailed as follows:
Proved Reserves. Proved reserves are estimated quantities of crude oil, natural gas and natural gas 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.
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 cannot 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 DEVELOPED OIL AND GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers and set forth the changes in estimated quantities of proved developed oil and gas reserves of the Company presented as of the beginning of each year.
Proved Developed Reserves. Proved developed reserves are proved reserves which are expected to be recovered through existing wells with existing equipment and operating methods.
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
Costs incurred in connection with the Company's oil and gas acquisition, exploration and development activities during the year 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:
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.
*Includes $59.5 million of additional DD&A as a result of adoption of SFAS No. 121.
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, 1997, 1996 and 1995 as required by Financial Accounting Standards Board's Statement of Financial Accounting Standards 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.
The future net cash inflows for 1997 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. and Item 2. "Business--Oil and Gas" of this Form 10-K.
Future cash inflows are computed 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 trading and hedging contracts if any. The year-end weighted average oil price utilized in the computation of future cash inflows was approximately $16.22 per BBL.
West Texas intermediate crude oil price in mid February 1998 was approximately $2.72 per BBL lower than year-end 1997. 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 $74 million.
The year-end weighted average gas price utilized in the computation of future cash inflows was approximately $2.55 per MCF. Natural gas index prices at Henry Hub have decreased approximately $.33 per MCF in mid February 1998 compared with the year-end index. 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 $83 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 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, 1997, the Company had estimated gas imbalance receivables of $18.5 million and estimated liabilities of $21.6 million; at year-end 1996, $19.3 million in receivables and $21.7 million in liabilities; and at year-end 1995, $12.3 million in receivables and $11.4 million in liabilities. Neither the gas imbalance receivables nor liabilities have been included in the standardized measure of discounted future net cash flows as of each of the three years ended December 31, 1997, 1996 and 1995.
Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company's proved oil and gas reserves at year end are shown below.
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 1997 and 1996 are as follows:
(1) During the fourth quarter of 1997 and 1996, DD&A expense increased $5.5 million and $.8 million, respectively, relating to the cumulative effect of oil and gas reserve revisions on the DD&A provision for the preceding three quarters.
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 1998 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 1998 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 1998 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 and Benefits Committee 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 1998 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 1998 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: 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) No report on Form 8-K was filed by the Registrant during the quarter ended December 31, 1997.
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 16, 1998 By: /s/ William D. Dickson ---------------------------- William D. Dickson, Senior 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.
INDEX TO EXHIBITS
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* Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
** Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Senior Vice President - Finance and Treasurer, Noble Affiliates, Inc., Post Office Box 1967, Ardmore, Oklahoma 73402.