<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-------------------
FORM 10-K/A
(Amendment No. 1)
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 0-7062
NOBLE AFFILIATES, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-0785597
(State of incorporation) (I.R.S. employer identification number)
110 West Broadway
Ardmore, Oklahoma 73401
(Address of principal executive offices) (Zip Code)
(Registrant's telephone number, including area code)
(580) 223-4110
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- -----------------
Common Stock, $3.33-1/3 par value New York Stock Exchange, Inc.
Preferred Stock Purchase Rights New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [ X ] No[ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
Aggregate market value of Common Stock held by nonaffiliates as of February 14,
2000: $1,089,000,000.
Number of shares of Common Stock outstanding as of February 14, 2000: 56,328,163
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2000 Annual
Meeting of Stockholders to be held on April 25, 2000, which will be filed with
the Securities and Exchange Commission within 120 days after December 31, 1999,
are incorporated by reference into Part III.
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<PAGE> 2
Item 8 of Noble Affiliates, Inc.'s Annual Report on Form 10-K for the
fiscal year ended December 31, 1999 (the "1999 Form 10-K") is hereby amended.
Such item is set forth herein in its entirety, as amended.
Item 8 is hereby amended to reflect the correction of the headings on
certain tables contained on pages 54, 55 and 56 of the 1999 Form 10-K, in order
to change the year of such headings from 1999 to 1998 and 1997, where
appropriate and as shown herein.
<PAGE> 3
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Report of Independent Public Accountants................................................................ 34
Consolidated Balance Sheet as of December 31, 1999 and 1998............................................. 35
Consolidated Statement of Operations for each of the three years in the period ended
December 31, 1999..................................................................................... 36
Consolidated Statement of Cash Flows for each of the three years in the period ended
December 31, 1999..................................................................................... 37
Consolidated Statement of Shareholders' Equity for each of the three years in the period ended
December 31, 1999..................................................................................... 38
Notes to Consolidated Financial Statements.............................................................. 39
Supplemental Oil and Gas Information (Unaudited)........................................................ 52
Interim Financial Information (Unaudited)............................................................... 58
</TABLE>
All financial statement schedules have been omitted because the required
information is not present or is not present in amounts sufficient to require
submission of the schedule or because the information required is included in
the financial statements, including the notes thereto.
33
<PAGE> 4
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,
1999 and 1998, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Noble Affiliates, Inc. and
subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 28, 2000
34
<PAGE> 5
CONSOLIDATED BALANCE SHEET NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
December 31,
------------------------------
(in thousands, except share amounts) 1999 1998
------------- -------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and short-term cash investments $ 2,925 $ 19,100
Accounts receivable - trade 98,794 106,513
Materials and supplies inventories 5,517 3,006
Other current assets 40,678 59,670
------------- -------------
Total current assets 147,914 188,289
------------- -------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 2,786,848 2,873,076
Other 43,945 42,841
------------- -------------
2,830,793 2,915,917
Accumulated depreciation, depletion and amortization (1,588,423) (1,486,250)
------------- -------------
Total property, plant and equipment, net 1,242,370 1,429,667
------------- -------------
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY 15,625 25,061
------------- -------------
OTHER ASSETS 44,442 43,063
------------- -------------
TOTAL ASSETS $ 1,450,351 $ 1,686,080
------------- -------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 103,753 $ 108,538
Other current liabilities 48,215 28,815
Income taxes - current 32,503 1,813
------------- -------------
Total current liabilities 184,471 139,166
------------- -------------
DEFERRED INCOME TAXES 83,075 106,823
------------- -------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 53,877 52,868
------------- -------------
LONG-TERM DEBT 445,319 745,143
------------- -------------
SHAREHOLDERS' EQUITY:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
58,569,963 and 58,505,908 shares issued in 1999 and 1998, respectively 195,231 195,018
Capital in excess of par value 360,983 360,008
Retained earnings 142,813 102,472
------------- -------------
699,027 657,498
Less common stock in treasury, at cost (1999 and 1998, 1,524,900 shares) (15,418) (15,418)
------------- -------------
Total shareholders' equity 683,609 642,080
------------- -------------
TOTAL LIABILITIES AND EQUITY $ 1,450,351 $ 1,686,080
------------- -------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
35
<PAGE> 6
CONSOLIDATED STATEMENT OF OPERATIONS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------------------------
(in thousands, except per share amounts) 1999 1998 1997
----------- ----------- -----------
REVENUES:
<S> <C> <C> <C>
Oil and gas sales and royalties $ 548,733 $ 609,164 $ 761,145
Gathering, marketing and processing 338,046 284,407 329,868
Other income 23,063 18,045 25,610
----------- ----------- -----------
Total Revenue 909,842 911,616 1,116,623
----------- ----------- -----------
COSTS AND EXPENSES:
Oil and gas exploration 46,784 110,158 86,698
Oil and gas operations 116,698 149,030 160,765
Gathering, marketing and processing 323,314 270,826 313,807
Depreciation, depletion and amortization 254,515 313,191 300,354
Impairment of operating assets 223,251
Selling, general and administrative 47,859 48,110 50,545
Interest 48,935 50,511 53,008
Interest capitalized (5,894) (6,753) (6,239)
----------- ----------- -----------
Total Expenses 832,211 1,158,324 958,938
----------- ----------- -----------
INCOME (LOSS) BEFORE TAXES 77,631 (246,708) 157,685
----------- ----------- -----------
INCOME TAX PROVISION (BENEFIT):
Current 24,508 (19,679) 25,569
Deferred 3,662 (63,004) 32,838
----------- ----------- -----------
Total Tax Provision (Benefit) 28,170 (82,683) 58,407
----------- ----------- -----------
NET INCOME (LOSS) $ 49,461 $ (164,025) $ 99,278
----------- ----------- -----------
BASIC EARNINGS (LOSS) PER SHARE $ .87 $ (2.88) $ 1.75
----------- ----------- -----------
DILUTED EARNINGS (LOSS) PER SHARE $ .86 $ (2.88) $ 1.73
----------- ----------- -----------
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 57,005 56,955 56,872
Diluted 57,349 56,955 57,421
----------- ----------- -----------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
36
<PAGE> 7
CONSOLIDATED STATEMENT OF CASH FLOWS NOBLE AFFILIATES, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------------
(in thousands) 1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 49,461 $ (164,025) $ 99,278
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 254,515 313,191 300,354
Impairment of operating assets 223,251
Amortization of undeveloped leasehold costs, net 9,645 7,953 8,146
(Gain) loss on disposal of assets (12,079) 15,434 (11,007)
Noncurrent deferred income taxes (23,749) (37,260) 35,650
(Income) loss from unconsolidated subsidiary 37
Increase (decrease) in other deferred credits 1,011 (3,558) 5,822
(Increase) decrease in other (1,296) 12,709 1,684
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable 7,719 56,154 43,484
(Increase) decrease in other current assets 16,571 (44,423) (25,053)
Increase (decrease) in accounts payable (4,785) (55,025) (29,845)
Increase (decrease) in other current liabilities 26,845 (126) 17,058
------------ ------------ ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 323,895 324,275 445,571
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (122,920) (431,716) (326,958)
Investment in unconsolidated subsidiary (51,962) (25,061)
Proceeds from the transfer of our interest
to unconsolidated subsidiary 61,987
Proceeds from sale of property, plant and equipment 58,137 3,412 54,543
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (54,758) (453,365) (272,415)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 1,189 2,228 2,744
Cash dividends paid (9,120) (9,113) (9,100)
Repayment of bank debt (300,000) (549,000)
Repayment of notes payable - unconsolidated subsidiary (38,101)
Proceeds from notes payable - unconsolidated subsidiary 60,720
Proceeds from issuance of long-term debt 100,000 342,507
------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (285,312) 93,115 (212,849)
------------ ------------ ------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS (16,175) (35,975) (39,693)
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 19,100 55,075 94,768
------------ ------------ ------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 2,925 $ 19,100 $ 55,075
------------ ------------ ------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 44,845 $ 43,368 $ 46,140
Income taxes $ 30,000 $ 4,276 $ 32,415
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
37
<PAGE> 8
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Capital in Treasury
Common Stock Excess of Stock at Retained
(in thousands, except shares issued) Shares Issued Amount Par Value Cost Earnings
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1997 58,321,297 $ 194,402 $ 355,651 $ (15,418) $ 185,432
Net Income 99,278
Exercise of stock options 102,141 341 2,403
Cash dividends ($.16 per share) (9,100)
------------ ------------- ------------- ------------- -------------
DECEMBER 31, 1997 58,423,438 $ 194,743 $ 358,054 $ (15,418) $ 275,610
------------ ------------- ------------- ------------- -------------
Net Loss (164,025)
Exercise of stock options 82,470 275 1,954
Cash dividends ($.16 per share) (9,113)
------------ ------------- ------------- ------------- -------------
DECEMBER 31, 1998 58,505,908 $ 195,018 $ 360,008 $ (15,418) $ 102,472
------------ ------------- ------------- ------------- -------------
Net Income 49,461
Exercise of stock options 64,055 213 975
Cash dividends ($.16 per share) (9,120)
------------ ------------- ------------- ------------- -------------
DECEMBER 31, 1999 58,569,963 $ 195,231 $ 360,983 $ (15,418) $ 142,813
------------ ------------- ------------- ------------- -------------
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
38
<PAGE> 9
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,
1999.
NOBLE AFFILIATES, INC.
Noble Gas Marketing, Inc.
Noble Gas Pipeline, Inc.
Noble Trading, Inc.
NPM, Inc.
Samedan Oil Corporation
Samedan of North Africa, Inc.
Samedan International
Samedan Transfer Sub
Samedan, Mediterranean Sea
Samedan Power .
Samedan Pipe Line Corporation
Samedan Royalty Corporation
Samedan of Tunisia, Inc.
Energy Development Corporation ("EDC")
EDC Argentina, Inc.
EDC Australia, Ltd.
EDC China, Inc.
EDC Denmark, Inc.
EDC Ecuador Ltd.
EDC (Europe) Limited
EDC HIPS, Inc.
EDC Portugal Ltd.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
NATURE OF OPERATIONS
The Company is an independent energy company engaged through its subsidiaries in
the exploration, development, production and marketing of oil and gas. Samedan
operates throughout the major basins in the United States, including the Gulf of
Mexico, as well as international operations in Argentina, China, Ecuador,
Equatorial Guinea, the Mediterranean, the North Sea and the United Kingdom. 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.
39
<PAGE> 10
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and are included in other expense on the income statement.
INVENTORIES
Materials and supplies inventories, consisting principally of tubular goods and
production equipment, are stated at the lower of cost or market, with cost being
determined by the first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for its oil and gas properties under the successful efforts
method of accounting. Under this method, costs to acquire mineral interests in
oil and gas properties, to drill and equip exploratory wells that find proved
reserves and to drill and equip development wells are capitalized. Capitalized
costs of producing oil and gas properties are amortized to operations by the
unit-of-production method based on proved developed oil and gas reserves on a
property by property basis as estimated by Company engineers. Estimated future
restoration and abandonment costs are recorded by charges to depreciation,
depletion and amortization ("DD&A") expense over the productive lives of the
related properties. The Company has provided $83.0 million for such future costs
classified with accumulated DD&A in the December 31, 1999, balance sheet. The
total estimated future dismantlement and restoration costs of $123.1 million are
included in future production and development costs for purposes of estimating
the future net revenues relating to the Company's proved reserves. Upon sale or
retirement of depreciable or depletable property, the cost and related
accumulated DD&A are eliminated from the accounts and the resulting gain or loss
is recognized.
Individually significant undeveloped oil and gas properties are periodically
assessed for impairment of value and a loss is recognized at the time of
impairment by providing an impairment allowance. Other undeveloped properties
are amortized on a composite method based on the Company's experience of
successful drilling and average holding period. Geological and geophysical
costs, delay rentals and costs to drill exploratory wells which do not find
proved reserves are expensed. Repairs and maintenance are charged to expense as
incurred.
Developed oil and gas properties and other long-lived assets are periodically
assessed to determine if circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company performs this review of recoverability
by estimating future cash flows. If the sum of the expected future cash flows is
less than the carrying amount of the asset, an impairment is recognized based on
the discounted amount of such cash flows.
INCOME TAXES
The Company files a consolidated federal income tax return. Deferred income
taxes are provided for temporary differences between the financial reporting and
tax bases of the Company's assets and liabilities.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the development and
construction of significant properties or projects.
40
<PAGE> 11
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term investments include
cash on hand and investments purchased with original maturities of three months
or less.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The diluted
net income per share of common stock includes the effect of outstanding stock
options. The following table summarizes the calculation of basic earnings per
share ("EPS") and diluted EPS components required by SFAS No. 128, as of
December 31:
<TABLE>
<CAPTION>
1999 1998(1) 1997
--------------------------- ------------------------- ---------------------------
(in thousands Income Shares Income Shares Income Shares
except per share amounts) (Numerator) (Denominator) (Numerator) (Denominator) (Numerator) (Denominator)
----------- ------------- ----------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Net income/shares $49,461 57,005 $(164,025) 56,955 $99,278 56,872
BASIC EPS $.87 $(2.88) $1.75
Net income/shares $49,461 57,005 $(164,025) 56,955 $99,278 56,872
Effect of Diluted Securities
Stock options 344 549
Adjusted net income
and shares $49,461 57,349 $(164,025) 56,955 $99,278 57,421
DILUTED EPS $.86 $(2.88) $1.73
</TABLE>
(1) In 1998, the diluted EPS is antidilutive as a result of the net
operating loss; therefore, the basic EPS and diluted EPS are the same.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan and EDC have gas sales contracts with NGM, whereby Samedan and EDC are
paid an index price for all gas sold to NGM. NGM records sales, including
hedging transactions, as gathering, marketing and processing revenues. NGM
records 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 $12.0 million and $14.8 million for
1999 and 1998, 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 $17.9 million and $19.1 million for 1999 and
1998, 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.
41
<PAGE> 12
TRADING AND HEDGING ACTIVITIES
The Company, through its subsidiaries, from time to time, uses various hedging
arrangements in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such arrangements include
fixed price hedges, costless collars, and other contractual arrangements.
Although these hedging arrangements expose the Company to credit risk, the
Company monitors the creditworthiness of its counterparties, which generally are
major financial institutions, and believes that losses from nonperformance are
unlikely to occur. Hedging gains and losses related to the Company's oil and gas
production are recorded in oil and gas sales and royalties. The swap component
of the contracts discussed in the following paragraphs was treated as a hedge
for accounting purposes only. There was no payment obligation in 1999.
The Company has entered into three crude oil premium swap contracts related to
its production for calendar year 2000. Two of the contracts provide for payments
based on daily NYMEX settlement prices. These contracts relate to 2,500 BBLS per
day and 2,000 BBLS per day and have trigger prices of $21.73 per BBL and $22.45
per BBL, respectively, and both have knockout prices of $17.00 per BBL. These
two contracts entitle the Company to receive settlements from the counterparties
in amounts, if any, by which the settlement price for each NYMEX trading day is
less than the trigger price, provided the NYMEX price is also greater than the
$17.00 per BBL knockout price. If a daily settlement price is $17.00 per BBL or
less, then neither party will have any liability to the other for that day. If a
daily settlement price is above the applicable trigger price, then the Company
will owe the counterparty for the excess of the settlement price over the
trigger price for that day. Payment is made monthly under each of these
contracts, in an amount equal to the net amount due to either party based on the
sum of the daily amounts determined as described in this paragraph for that
month.
The third contract relates to 2,500 BBLS per day and provides for payments based
on monthly average NYMEX settlement prices. The contract entitles the Company to
receive monthly settlements from the counterparty in an amount, if any, by which
the arithmetic average of the daily NYMEX settlement prices for the month is
less than the trigger price, which is $21.73 per BBL, multiplied by the number
of days in the month, provided such average NYMEX price is also greater than the
$17.00 per BBL knockout price. If the average NYMEX settlement price for the
month is $17.00 per BBL or less, then neither party will have any liability to
the other for that month. If the average NYMEX settlement price for the month is
above the trigger price, then the Company will pay the counterparty an amount
equal to the excess of the average settlement price over the trigger price,
multiplied by the number of days in the month.
The Company has treated the swap component of these contracts as a hedge (for
accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20
per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $2,990,000
recorded in other income for the year ended December 31, 1999.
In addition to the premium swap crude oil hedging contracts, the Company has
entered into crude oil costless collar hedges from January 1, 2000, to April 30,
2000, for volumes of 2,000 BBLS per day. These costless collars have a floor
price ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from
$25.83 per BBL to $27.31 per BBL. These costless collar contracts entitle the
Company to receive settlements from the counterparties in amounts, if any, by
which the monthly average settlement price for each NYMEX trading day during a
contract month is less than the floor price. If the monthly average settlement
price is above the applicable cap price, then the Company will owe the
counterparties for the excess of the monthly average settlement price over the
applicable cap price. If the monthly average settlement price falls between the
applicable floor and cap price, then neither party will have any liability to
the other party for that month. Payment, if any, is made monthly under each of
the contracts in an amount equal to the net amount due either party based on the
volumes per day multiplied by the difference between the NYMEX average price and
the cap, if the NYMEX average price exceeds the cap price, or if the NYMEX
average price is less than the floor price, then the volumes per day multiplied
by the difference between the floor price and the NYMEX average price.
42
<PAGE> 13
During 1999 and 1998, the Company had no oil or gas hedging transactions for its
production.
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 per MMBTU 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 for its production.
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 per BBL 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 for its production.
In addition to the hedging arrangements pertaining to the Company's production
as described above, Noble Gas Marketing, Inc. ("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 1999, NGM had
hedging transactions with broker-dealers that ranged from 146,000 MMBTU's to
815,000 MMBTU's of gas per day. At December 31, 1999, NGM had in place hedges
ranging from approximately 10,000 MMBTU's to 776,000 MMBTU's of gas per day for
January 2000 to March 2001 for future physical transactions.
In 1998, NGM had hedging transactions with broker-dealers that ranged from
508,811 MMBTU's to 1,061,536 MMBTU's of gas per day. 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. NGM records hedging gains or losses relating to
fixed term sales as gathering, marketing and processing revenues in the periods
in which the related contract is completed.
SELF-INSURANCE
The Company self-insures the medical and dental coverage provided to certain of
its employees, certain workers' compensation and the first $200,000 of its
general liability coverage.
A provision for self-insured claims is recorded when sufficient information is
available to reasonably estimate the amount of the loss.
UNCONSOLIDATED SUBSIDIARY
The Company has one unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that indirectly owns 90 percent of
Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol
plant in Equatorial Guinea. AMCCO is accounted for using the equity method
within the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. The
plant construction started during 1998 and is scheduled to be completed during
the second quarter of 2001. The Company's net equity investment in the
unconsolidated subsidiary was $15.6 million at December 31, 1999.
RECLASSIFICATION
Certain reclassifications have been made to the 1997 and 1998 consolidated
financial statements to conform to the 1999 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities" in June 1998. The Statement establishes
43
<PAGE> 14
accounting and reporting standards requiring every derivative instrument
(including certain derivative instruments embedded in other contracts) to be
recorded in the balance sheet as either an asset or liability measured at its
fair value. The Statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met wherein gains and losses are reflected in stockholder equity until the
hedged item is recognized. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally document, designate
and assess the effectiveness of transactions that receive hedge accounting.
Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS
No. 133, the Company is required to adopt the statement for fiscal year
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998). The Company has not quantified the impact of adopting SFAS No. 133 but
plans on adopting the statement by January 1, 2001.
NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments pursuant to the requirements of SFAS No.
107, "Disclosures about Fair Value of Financial Instruments."
CASH AND SHORT-TERM INVESTMENTS
The carrying amount approximates fair value due to the short maturity of the
instruments.
OIL AND GAS PRICE HEDGE AGREEMENTS
The fair value of oil and gas price hedges is the estimated amount the Company
would receive or pay to terminate the hedge agreements at the reporting date
taking into account creditworthiness of the hedging parties.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered to
the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's financial
instruments as of December 31, for each of the years are as follows:
<TABLE>
<CAPTION>
1999 1998
---------------------------- ---------------------------
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
- -------------- ---------- ---------- ----------- -----------
<S> <C> <C> <C> <C>
Cash and short-term investments $ 2,925 $ 2,925 $ 19,100 $ 19,100
Long-term debt (including current portion) $ 445,319 $ 407,500 $ 745,143 $ 760,750
Oil hedge agreements $ $ (7,879) $ $
</TABLE>
44
<PAGE> 15
NOTE 3 - DEBT
A summary of debt at December 31 follows:
<TABLE>
<CAPTION>
(in thousands) 1999 1998
- -------------- ---------- ----------
<S> <C> <C>
$300 million Credit Agreement $ $ 300,000
7 1/4% Notes Due 2023 100,000 100,000
8% Senior Notes Due 2027 250,000 250,000
7 1/4% Senior Debentures Due 2097 100,000 100,000
---------- ----------
Outstanding debt 450,000 750,000
---------- ----------
Less: unamortized discount 4,681 4,857
---------- ----------
Long-term debt $ 445,319 $ 745,143
---------- ----------
</TABLE>
The Company's total long-term debt, net of unamortized discount, at December 31,
1999, was $445 million compared to $745 million at December 31, 1998. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 39
percent at December 31, 1999, compared with 54 percent at December 31, 1998.
The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due
2023, $250 million of 8% Senior Notes Due 2027, and $100 million of 7 1/4%
Senior Debentures Due 2097. There is no principal payment due on long term debt
during the next five years.
The Company has a $300 million credit facility which exposes the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. At
December 31, 1999, there was no borrowing against the credit facility which has
a maturity date of December 24, 2002. The interest rate is based upon a
Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1998, the
Company had $300 million outstanding on this facility which was repaid during
1999.
On June 17, 1999, the Company entered into a new $100 million 364 day credit
agreement with certain commercial lending institutions. There is no balance
outstanding on this agreement which is based upon a Eurodollar rate plus 37.5 to
87.5 basis points depending upon the percentage of utilization.
On November 11, 1999, the Company announced that AMCCO had sold $125 million
principal amount of its senior secured notes due 2004, without registration
rights, in a private offering to institutional investors. Donaldson, Lufkin and
Jenrette was the placement agent for the offering. Approximately $63 million of
the proceeds, minus transaction expenses, were used to fund a portion of the
Company's obligations to pay the costs of construction of the methanol plant and
related facilities in Equatorial Guinea. The remainder of the proceeds was used
by AMCCO to acquire from the Company, at book value, its subsidiary that held
the Company's ownership interest in the methanol plant project. The Company has
guaranteed payment of interest on the notes and provided certain other credit
support. In addition, the Company established a new series of preferred stock,
Series B Mandatory Convertible Preferred Stock, par value $1.00 per share (the
"Series B Preferred"). The Company issued, in a private placement pursuant to
Section 4(2) of the Securities Act, 125,000 shares of the Series B Preferred to
Noble Share Trust, which is a Delaware statutory business trust, in exchange for
all of the beneficial ownership interests in Noble Share Trust. Noble Share
Trust holds the 125,000 shares of Series B Preferred for the benefit of the
holders of the Series A-2 Notes.
On December 31, 1999, the Company had $23 million outstanding on its note
payable with AMCCO, an unconsolidated subsidiary. The note payable will be
repaid by the second quarter of 2000 and has an interest rate of 8.95 percent.
The note payable is included in other current liabilities.
45
<PAGE> 16
NOTE 4 - INCOME TAXES
The following table details the difference between the federal statutory tax
rate and the effective tax rate for the years ended December 31:
<TABLE>
<CAPTION>
(amounts expressed in percentages) 1999 1998 1997
- ---------------------------------- ------ ------ -----
<S> <C> <C> <C>
Statutory rate (benefit) 35.0 (35.0) 35.0
Effect of:
Percentage depletion (.1)
State taxes (.2)
Foreign taxes 1.8 .4 .8
Losses from international operations 1.3 .9 1.4
Other, net (1.8) .4 (.1)
------ ------ -----
Effective rate 36.3 (33.5) 37.0
------ ------ -----
</TABLE>
The net current deferred tax asset (liability) in the following table is
classified as Other Current Assets in the Consolidated Balance Sheet. The tax
effects of temporary differences which gave rise to deferred tax assets and
liabilities as of December 31 were:
<TABLE>
<CAPTION>
(in thousands) 1999 1998
- -------------- ----------- -----------
<S> <C> <C>
U.S. and State Current Deferred Tax Assets:
Accrued expenses $ 525 $ 1,684
Deferred income 36 1,386
Minimum tax 17,939
Allowance for doubtful accounts 284 304
Net operating loss carryforward 6,710
Other 14 436
----------- -----------
Net current deferred tax asset 859 28,459
----------- -----------
U.S. and State Non-current Deferred Tax Liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (84,969) (104,691)
Accrued expenses 8,041 6,449
Deferred income 2,748 3,306
Allowance for doubtful accounts 4,865 3,930
Income tax accruals 9,244 10,465
Other 2,552 2,448
----------- -----------
Net non-current deferred liability (57,519) (78,093)
----------- -----------
U.S. and state net deferred tax liability (56,660) (49,634)
----------- -----------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations (25,556) (28,730)
----------- -----------
Deferred tax liability (25,556) (28,730)
----------- -----------
Total net deferred tax liability $ (82,216) $ (78,364)
----------- -----------
</TABLE>
The components of income from operations before income taxes for each year are
as follows:
<TABLE>
<CAPTION>
(in thousands) 1999 1998 1997
- -------------- --------- --------- ---------
<S> <C> <C> <C>
Domestic $ 83,439 $(225,692) $ 159,535
Foreign (5,808) (21,016) (1,850)
--------- --------- ---------
$ 77,631 $(246,708) $ 157,685
--------- --------- ---------
</TABLE>
46
<PAGE> 17
The income tax provisions (benefit) relating to operations for each year consist
of the following:
<TABLE>
<CAPTION>
(in thousands) 1999 1998 1997
- -------------- ----------- ----------- -----------
<S> <C> <C> <C>
U.S. current $ 18,962 $ (20,842) $ 22,146
U.S. deferred 7,151 (62,366) 34,344
State current 313 236 587
State deferred (313) (1,080) (622)
Foreign current 5,232 927 2,836
Foreign deferred (3,175) 442 (884)
----------- ----------- -----------
$ 28,170 $ (82,683) $ 58,407
----------- ----------- -----------
</TABLE>
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 adoption of the 1992 Plan, stock options have been issued at the
market price on the date of grant. The earliest the granted options may be
exercised is over a three year period at the rate of 33 1/3% each year
commencing on the first anniversary of the grant date. The options expire ten
years from the grant date. The 1992 Plan was amended in 1997, by a vote of the
shareholders, to increase the maximum number of shares of common stock that may
be issued under the 1992 Plan to 4,000,000 shares. At December 31, 1999, the
Company had reserved 3,789,180 shares of common stock for issuance, including
487,945 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,
1999, the Company had reserved 419,000 shares of common stock for issuance,
including 195,500 shares available for grant, under its 1988 Plan.
The Company adopted a stockholder rights plan on August 27, 1997, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers and other abusive takeover tactics to gain control of the Company
without paying all stockholders a fair price. The rights plan was not adopted in
response to any specific takeover proposal. Under the rights plan, the Company
declared a dividend of one right ("Right") on each share of Noble Affiliates,
Inc. common stock. Each Right will entitle the holder to purchase one
one-hundredth of a share of a new Series A Junior Participating Preferred Stock,
par value $1.00 per share, at an exercise price of $150.00. The Rights are not
currently exercisable and will become exercisable only in the event a person or
group acquires beneficial ownership of 15 percent or more of Noble Affiliates,
Inc. common stock. The dividend distribution was made on September 8, 1997, to
stockholders of record at the close of business on that date. The Rights will
expire on September 8, 2007.
47
<PAGE> 18
Stock options outstanding under the plans mentioned above and two previously
terminated plans are presented for the periods indicated.
<TABLE>
<CAPTION>
Number Option
of Shares Price Range
----------- --------------
<S> <C> <C>
OUTSTANDING DECEMBER 31, 1996 1,602,098 $ 10.63-$40.38
----------- --------------
Granted 707,307 $ 39.63-$39.88
Exercised (102,141) $ 10.63-$40.38
Canceled (1,929) $ 24.25-$27.25
----------- --------------
OUTSTANDING DECEMBER 31, 1997 2,205,335 $ 11.63-$40.38
----------- --------------
Granted 722,604 $ 35.94-$37.75
Exercised (82,470) $ 11.63-$40.38
Canceled (28,227) $ 24.25-$40.38
----------- --------------
OUTSTANDING DECEMBER 31, 1998 2,817,242 $ 13.38-$40.38
----------- --------------
Granted 810,895 $ 20.06-$27,50
Exercised (64,055) $ 13.38-$24.25
Canceled (85,812) $ 20.06-$40.38
----------- --------------
OUTSTANDING DECEMBER 31, 1999 3,478,270 $ 13.50-$40.38
----------- --------------
EXERCISABLE AT DECEMBER 31, 1999 2,207,545 $ 13.50-$40.38
----------- --------------
</TABLE>
The SFAS No. 123 method of accounting is based on several assumptions and should
not be viewed as indicative of the operations of the Company in future periods.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 1999, 1998 and 1997, respectively as follows:
<TABLE>
<CAPTION>
(amounts expressed in percentages) 1999 1998 1997
- ---------------------------------- -------- -------- -------
<S> <C> <C> <C>
Interest rate 5.50 5.75 6.03
Dividend yield .40 .40 .40
Expected volatility 42.95 32.66 32.97
Expected life 8.80 9.74 7.00
</TABLE>
The weighted average fair value of options granted using the Black-Scholes
option pricing model for 1999, 1998 and 1997, respectively is as follows:
<TABLE>
<CAPTION>
(amounts expressed in dollars) 1999 1998 1997
- ------------------------------ -------- -------- -------
<S> <C> <C> <C>
Black-Scholes model weighted average fair value
option price $10.01 $19.02 $18.28
</TABLE>
The Company applies APB Opinion No. 25 in accounting for its fixed price stock
options. Accordingly, no compensation cost for options has been recognized in
the financial statements. The chart below sets forth the Company's net income
and earnings per share for each of the years ended December 31, as reported and
on a pro forma basis as if the compensation cost of stock options had been
determined consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation."
<TABLE>
<CAPTION>
(in thousands except per share amounts) 1999 1998 1997
- --------------------------------------- ------- ---------- --------
<S> <C> <C> <C>
Net Income:
As Reported $49,461 $ (164,025) $ 99,278
Pro Forma $41,176 $ (171,741) $ 95,591
Basic Earnings Per Share:
As Reported $ .87 $ (2.88) $ 1.75
Pro Forma $ .72 $ (3.02) $ 1.68
Diluted Earnings Per Share:
As Reported $ .86 $ (2.88) $ 1.73
Pro Forma $ .72 $ (3.02) $ 1.66
</TABLE>
48
<PAGE> 19
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a non-contributory defined benefit pension plan covering
substantially all of its domestic employees. The benefits are based on an
employee's years of service and average earnings for the 60 consecutive calendar
months of highest compensation. The Company also has an unfunded restoration
plan to ensure payments of amounts for which employees are entitled under the
provisions of the pension plan, but which are subject to limitations imposed by
federal tax laws. The Company's funding policy has been to make annual
contributions equal to the actuarially computed liability to the extent such
amounts are deductible for income tax purposes. Plan assets consist of equity
securities and fixed income investments.
The Company sponsors other plans for the benefit of its employees and retirees.
These plans include health care and life insurance benefits. The following table
reflects the required SFAS No. 132, "Employers' Disclosures About Pension and
Other Postretirement Benefits," disclosures at December 31:
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
--------------------------- --------------------------
(in thousands) 1999 1998 1999 1998
- -------------- --------- --------- -------- --------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 82,823 $ 62,487 $ 3,187 $ 2,384
Service cost 3,802 3,811 294 268
Interest cost 4,720 4,704 188 185
Plan participants' contributions 38 22
Amendments 489 (363)
Actuarial (gain) loss (24,294) 14,059 (533) 358
Benefit paid (2,857) (2,727) (72) (30)
--------- --------- -------- --------
Benefit obligation at year end $ 64,194 $ 82,823 $ 2,739 $ 3,187
--------- --------- -------- --------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 60,559 $ 55,611 $ $
Actual return on plan assets 1,083 7,322
Employer contribution 383 351 72 30
Benefit paid (2,857) (2,725) (72) (30)
--------- --------- -------- --------
Fair value of plan at end of year $ 59,168 $ 60,559 $ $
--------- --------- -------- --------
Fund status $ (5,026) $ (22,264) $ (2,738) $ (3,187)
Unrecognized net actuarial loss (gain) (18,989) 2,157 222 790
Unrecognized prior service cost 3,035 3,327 (334)
Unrecognized net transition obligation (assets) 1,239 1,263
--------- --------- -------- --------
Prepaid (accrued) benefit costs $ (19,741) $ (15,517) $ (2,850) $ (2,397)
--------- --------- -------- --------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 3,802 $ 3,811 $ 294 $ 268
Interest cost 4,720 4,704 188 185
Expected return on plan assets (4,264) (3,908)
Transition (assets) obligation recognition 24 24
Amortization of prior service cost 291 291 (30)
Recognized net actuarial loss 35 286 34 23
--------- --------- -------- --------
Net periodic benefit cost $ 4,608 $ 5,208 $ 486 $ 476
--------- --------- -------- --------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31,
Discount rate 8.00% 6.75% 8.00% 6.75%
Expected return on plan assets 8.50% 8.50%
Rate of compensation increase 5.50% 5.50% 5.50% 5.50%
</TABLE>
49
<PAGE> 20
The following table reflects the aggregate pension obligation components
required by SFAS No. 132 for the defined benefit pension plan and the
restoration benefit plan, which are aggregated in the previous tables, at
December 31:
<TABLE>
<CAPTION>
Defined Benefit Restoration
Pension Plan Benefit Plan
------------------- --------------------
(in thousands) 1999 1998 1999 1998
- ------------- -------- -------- -------- --------
<S> <C> <C> <C> <C>
AGGREGATED PENSION BENEFITS
Aggregate fair value of plan assets $59,168 $60,559 $ $
Aggregate accumulated benefit obligation 56,092 68,283 8,102 14,540
------- ------- ------- --------
Fund status of net periodic
benefit assets (obligation) $ 3,076 $(7,724) $(8,102) $(14,540)
------- ------- ------- --------
</TABLE>
Assumed health care cost trend rates have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following results:
<TABLE>
<CAPTION>
1-Percentage- 1-Percentage-
(in thousands) Point increase Point decrease
- -------------- -------------- --------------
<S> <C> <C>
Total service and interest cost components $ 544 $ 429
Total postretirement benefit obligation $3,048 $2,474
</TABLE>
EMPLOYEE SAVINGS PLAN ("ESP")
The Company has an ESP which is a defined contribution plan. Participation in
the ESP is voluntary and all regular employees of the Company are eligible to
participate. The Company may match up to 100 percent of the participant's
contribution not to exceed six percent of the employee's base compensation. The
following table indicates the Company's contribution for the years ended
December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998 1997
- -------------- ------ ------ ------
<S> <C> <C> <C>
Employers' plan contribution $1,823 $1,938 $1,369
</TABLE>
NOTE 7 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful accounts at
December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998
- -------------- ------ ------
<S> <C> <C>
Allowance for doubtful accounts $1,237 $1,146
</TABLE>
Other current assets include the following at December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998
- -------------- ------- -------
<S> <C> <C>
Deferred tax asset $ 859 $28,459
Prepaid federal income taxes $30,000 $ 4,276
</TABLE>
Other current liabilities include the following at December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998
- -------------- ------- -------
<S> <C> <C>
Gas imbalance liabilities $ 2,604 $ 4,761
Note payable unconsolidated subsidiary $23,245 $
Accrued interest payable $10,897 $12,251
Louisiana workers compensation $ 4,751 $ 4,345
</TABLE>
Oil and gas operations expense included the following for the years ended
December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998 1997
- -------------- --------- --------- ---------
<S> <C> <C> <C>
Lease operating expense $ 112,997 $ 142,673 $ 151,712
Production taxes 6,679 8,436 11,947
Other (2,978) (2,079) (2,894)
--------- --------- ---------
Total operations expense $ 116,698 $ 149,030 $ 160,765
--------- --------- ---------
</TABLE>
50
<PAGE> 21
Oil and gas exploration expense included the following for the years ended
December 31:
<TABLE>
<CAPTION>
(in thousands) 1999 1998 1997
- -------------- -------- -------- --------
<S> <C> <C> <C>
Dry hole expense $19,204 $ 57,736 $46,902
Undeveloped lease amortization 9,645 7,953 8,146
Abandoned assets 2,483 15,325 4,923
Seismic 7,797 15,754 19,095
Other 7,655 13,390 7,632
------- -------- -------
Total exploration expense $46,784 $110,158 $86,698
------- -------- -------
</TABLE>
During the past three years, there was no purchaser that accounted for more than
ten percent of total oil and gas sales and royalties.
NOTE 8 - IMPAIRMENT OF LONG-LIVED ASSETS
The Company follows SFAS No. 121 and any assets impaired are oil and gas
properties maintained under the successful efforts method of accounting. The
excess of the net book value over the projected discounted future net revenue of
the impaired properties is charged to "Impairment of Operating Assets." The
Company recorded no asset impairments under SFAS No. 121 during 1999 or 1997. In
December 1998, the Company recorded a $223.3 million pre-tax charge for the
write-down under SFAS No. 121 of properties due to downward reserve revisions.
51
<PAGE> 22
SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves. Oil and gas reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that 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 GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved gas reserves of the
Company during each of the three years presented.
<TABLE>
<CAPTION>
Natural Gas and Casinghead Gas (MMCF)
---------------------------------------------------------------------------------------
United Other Equatorial United
PROVED RESERVES AS OF: States Int'l Guinea Ecuador Argentina Kingdom Total
- --------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1999 873,222 321,642 5,386 39,056 1,239,306
Revisions of previous estimates (15,700) 63,478 482 (2,392) 45,868
Extensions, discoveries and
other additions 87,293 87,500 192 174,985
Production (150,871) (1,018) (647) (10,404) (162,940)
Sale of minerals in place (34,165) (34,165)
Purchase of minerals in place 2 2
- ----------------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
DECEMBER 31, 1999 759,781 384,102 87,500 5,221 26,452 1,263,056
- ----------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
PROVED RESERVES AS OF:
- --------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
JANUARY 1, 1998 1,107,158 322,205 5,565 47,287 1,482,215
Revisions of previous estimates (155,314) 396 27 (1,030) (155,921)
Extensions, discoveries and
other additions 71,061 71,061
Production (196,220) (959) (206) (7,201) (204,586)
Sale of minerals in place (2,232) (2,232)
Purchase of minerals in place 48,769 48,769
- ----------------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
DECEMBER 31, 1998 873,222 321,642 5,386 39,056 1,239,306
- ----------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
PROVED RESERVES AS OF:
- --------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
JANUARY 1, 1997 1,079,607 26,601 5,676 44,366 1,156,250
Revisions of previous estimates (1,228) (2,554) 545 (5) 904 (2,338)
Extensions, discoveries and
other additions 226,546 322,205 7,025 555,776
Production (195,085) (1,892) (545) (106) (5,008) (202,636)
Sale of minerals in place (6,934) (22,299) (29,233)
Purchase of minerals in place 4,252 144 4,396
- ----------------------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
DECEMBER 31, 1997 1,107,158 322,205 5,565 47,287 1,482,215
- ----------------- --------- ---------- ---------- ---------- ---------- ---------- ----------
PROVED DEVELOPED GAS RESERVES AS OF:
- ------------------------------------
January 1, 2000 703,166 11,687 5,221 26,452 746,526
January 1, 1999 818,787 12,862 5,386 39,056 876,091
January 1, 1998 1,022,192 13,425 5,565 47,287 1,088,469
January 1, 1997 1,010,837 26,601 5,676 17,981 1,061,095
</TABLE>
52
<PAGE> 23
PROVED OIL RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved oil reserves of the
Company during each of the three years presented.
<TABLE>
<CAPTION>
Crude Oil and Condensate (BBLS in thousands)
------------------------------------------------------------------------------
United Other Equatorial United
PROVED RESERVES AS OF: States Int'l Guinea Argentina Kingdom Total
- ---------------------- -------- -------- ---------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1999 77,306 22,001 11,128 6,146 116,581
Revisions of previous estimates (1,394) 9,617 (24) (57) 8,142
Extensions, discoveries and
other additions 3,687 9,768 354 13,809
Production (8,952) (934) (819) (657) (11,362)
Sale of minerals in place (5,125) (5,125)
Purchase of minerals in place 1 1
-------- -------- -------- -------- -------- --------
DECEMBER 31, 1999 65,523 9,768 30,684 10,285 5,786 122,046
-------- -------- -------- -------- -------- --------
PROVED RESERVES AS OF:
- ----------------------
JANUARY 1, 1998 89,065 22,766 11,997 7,035 130,863
Revisions of previous estimates (5,935) 166 16 (129) (5,882)
Extensions, discoveries and
other additions 4,802 35 4,837
Production (11,540) (931) (885) (795) (14,151)
Sale of minerals in place (155) (155)
Purchase of minerals in place 1,069 1,069
-------- -------- -------- -------- -------- --------
DECEMBER 31, 1998 77,306 22,001 11,128 6,146 116,581
-------- -------- -------- -------- -------- --------
PROVED RESERVES AS OF:
- ----------------------
JANUARY 1, 1997 82,317 3,435 8,276 13,007 8,712 115,747
Revisions of previous estimates 1,516 1,676 117 (133) (795) 2,381
Extensions, discoveries and
other additions 16,501 (1) 15,212 31,712
Production (11,450) (426) (839) (877) (882) (14,474)
Sale of minerals in place (184) (4,797) (4,981)
Purchase of minerals in place 365 113 478
-------- -------- -------- -------- -------- --------
DECEMBER 31, 1997 89,065 22,766 11,997 7,035 130,863
-------- -------- -------- -------- -------- --------
PROVED DEVELOPED OIL RESERVES AS OF:
- ------------------------------------
January 1, 2000 60,618 9,768 14,743 10,285 3,986 99,400
January 1, 1999 72,949 11,425 11,128 4,346 99,848
January 1, 1998 82,713 12,191 11,997 5,234 112,135
January 1, 1997 78,564 3,322 6,956 13,007 6,049 107,898
</TABLE>
- ------------------
Proved Reserves. Proved reserves are estimated quantities of crude oil, natural
gas, natural gas liquids and condensate liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
Proved Developed Reserves. Proved developed reserves are proved reserves which
are expected to be recovered through existing wells with existing equipment and
operating methods.
53
<PAGE> 24
OIL AND GAS OPERATIONS (Unaudited)
Aggregate results of operations for each period ended December 31, in connection
with the Company's oil and gas producing activities are shown below. Amounts are
presented in accordance with SFAS No. 19, and may not agree with amounts
determined using traditional industry definitions.
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1999 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- --------- --------- ---------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues $ 493,718 $ $ 16,036 $ $ 14,302 $ 24,677 $ 548,733
Production costs 125,803 3,183 4,640 7,106 140,732
Exploration expenses 45,461 2,779 196 130 542 4,270 53,378
DD&A and valuation provision 231,157 849 3,212 16 6,401 19,687 261,322
--------- --------- ---------- --------- --------- --------- ---------
Income (loss) 91,297 (3,628) 9,445 (146) 2,719 (6,386) 93,301
Income tax expense (benefit) 31,646 (1,094) 4,428 1,651 (733) 35,898
--------- --------- ---------- --------- --------- --------- ---------
Result of operations from
producing activities (excluding
corporate overhead and interest
costs) $ 59,651 $ (2,534) $ 5,017 $ (146) $ 1,068 $ (5,653) $ 57,403
--------- --------- ---------- --------- --------- --------- ---------
</TABLE>
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1998 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- --------- --------- ---------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues $ 564,771 $ $ 10,282 $ $ 9,105 $ 25,006 $ 609,164
Production costs 154,594 2,962 6,274 9,044 172,874
Exploration expenses 90,614 9,987 658 87 5,828 107,174
DD&A and valuation provision 513,725 46 2,998 6,083 13,869 536,721*
--------- --------- ---------- --------- --------- --------- ---------
Income (loss) (194,162) (10,033) 3,664 (3,339) (3,735) (207,605)
Income tax expense (benefit) (68,764) (2,489) 1,786 (1,822) (794) (72,083)
--------- --------- ---------- --------- --------- --------- ---------
Result of operations from
producing activities (excluding
corporate overhead and interest
costs) $(125,398) $ (7,544) $ 1,878 $ $ (1,517) $ (2,941) $(135,522)
--------- --------- ---------- --------- --------- --------- ---------
</TABLE>
*Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121.
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1997 States Int'l Guinea Ecuador Argentina Kingdom Total
- ----------------------------------- -------- -------- ---------- ---------- --------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues $696,882 $ 9,944 $ 14,824 $ $ 14,777 $ 24,718 $761,145
Production costs 164,441 4,778 3,600 5,555 8,220 186,594
Exploration expenses 56,177 12,345 3,464 804 7,942 80,732
DD&A and valuation provision 280,862 2,642 1,889 5,037 12,399 302,829
-------- -------- -------- ---------- -------- -------- --------
Income (loss) 195,402 (9,821) 5,871 3,381 (3,843) 190,990
Income tax expense (benefit) 67,934 (4,470) 4,654 2,680 (3,047) 67,751
-------- -------- -------- ---------- -------- -------- --------
Result of operations from
producing activities (excluding
corporate overhead and interest
costs) $127,468 $ (5,351) $ 1,217 $ $ 701 $ (796) $123,239
-------- -------- -------- ---------- -------- -------- --------
</TABLE>
54
<PAGE> 25
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities for each of the years are shown below.
Amounts are presented in accordance with SFAS No. 19, and may not agree with
amounts determined using traditional industry definitions.
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1999 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 69 $ $ $ $ $ $ 69
Unproved 7,280 620 7,900
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total $ 7,349 $ 620 $ $ $ $ $ 7,969
---------- ---------- ---------- ---------- ---------- ---------- ----------
Exploration costs $ 43,999 $ 7,382 $ 123 $ 130 $ 340 $ 3,229 $ 55,203
---------- ---------- ---------- ---------- ---------- ---------- ----------
Development costs $ 48,042 $ 1,012 $ 1,748 $ 2,569 $ 3,851 $ 4,972 $ 62,194
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1998 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 48,444 $ $ $ $ $ $ 48,444
Unproved 36,760 500 311 37,571
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total $ 85,204 $ 500 $ $ $ $ 311 $ 86,015
---------- ---------- ---------- ---------- ---------- ---------- ----------
Exploration costs $ 132,958 $ 9,663 $ 465 $ $ 473 $ 5,328 $ 148,887
---------- ---------- ---------- ---------- ---------- ---------- ----------
Development costs $ 242,838 $ 10,251 $ 10,977 $ $ 7,918 $ 9,761 $ 281,745
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
(in thousands)
- --------------
United Other Equatorial United
DECEMBER 31, 1997 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Property acquisition costs
Proved $ 3,884 $ 28 $ $ $ $ $ 3,912
Unproved 16,668 3,178 19,846
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total $ 20,552 $ 3,206 $ $ $ $ $ 23,758
---------- ---------- ---------- ---------- ---------- ---------- ----------
Exploration costs $ 81,141 $ 14,528 $ 9,907 $ $ $ 11,588 $ 117,164
---------- ---------- ---------- ---------- ---------- ---------- ----------
Development costs $ 201,788 $ 1,538 $ 2,871 $ $ 5,558 $ 4,213 $ 215,968
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
AGGREGATE CAPITALIZED COSTS (Unaudited)
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 are shown below:
<TABLE>
<CAPTION>
1999 1998
--------------------------------------------- ---------------------------------------------
(in thousands) U. S. Int'l TOTAL U. S. Int'l TOTAL
- ------------------------------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Unproved oil and gas properties $ 79,823 $ 13,288 $ 93,111 $ 86,844 $ 15,302 $ 102,146
Proved oil and gas properties 2,389,937 303,800 2,693,737 2,507,767 263,163 2,770,930
----------- ----------- ----------- ----------- ----------- -----------
2,469,760 317,088 2,786,848 2,594,611 278,465 2,873,076
Accumulated DD&A (1,471,889) (88,154) (1,560,043) (1,401,218) (59,357) (1,460,575)
----------- ----------- ----------- ----------- ----------- -----------
Net capitalized costs $ 997,871 $ 228,934 $ 1,226,805 $ 1,193,393 $ 219,108 $ 1,412,501
----------- ----------- ----------- ----------- ----------- -----------
</TABLE>
55
<PAGE> 26
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, 1999, 1998 and 1997 in accordance with SFAS No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not
the fair market value nor does it represent the expected present value of future
cash flows of the Company's proved oil and gas reserves.
<TABLE>
<CAPTION>
United Other Equatorial United
DECEMBER 31, 1999 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
(in millions of dollars)
Future cash inflows $ 3,565 $ 220 $ 779 $ 320 $ 243 $ 181 $ 5,308
Future production and
development costs 1,566 105 189 73 102 85 2,120
Future income tax expenses 376 22 111 46 27 18 600
---------- ---------- ---------- ---------- ---------- ---------- ----------
Future net cash flows 1,623 93 479 201 114 78 2,588
10% annual discount for
estimated timing of cash flows 686 39 203 85 49 33 1,095
---------- ---------- ---------- ---------- ---------- ---------- ----------
Standardized measure of
discounted future net
cash flows $ 937 $ 54 $ 276 $ 116 $ 65 $ 45 $ 1,493
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
United Other Equatorial United
DECEMBER 31, 1998 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
(in millions of dollars)
Future cash inflows $ 2,647 $ $ 301 $ $ 96 $ 113 $ 3,157
Future production and
development costs 1,146 140 30 62 1,378
Future income tax expenses 182 19 8 6 215
---------- ---------- ---------- ---------- ---------- ---------- ----------
Future net cash flows 1,319 142 58 45 1,564
10% annual discount for
estimated timing of cash flows 490 53 22 17 582
---------- ---------- ---------- ---------- ---------- ---------- ----------
Standardized measure of
discounted future net
cash flows $ 829 $ $ 89 $ $ 36 $ 28 $ 982
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
<TABLE>
<CAPTION>
United Other Equatorial United
DECEMBER 31, 1997 States Int'l Guinea Ecuador Argentina Kingdom Total
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
(in millions of dollars)
Future cash inflows $ 4,330 $ $ 498 $ $ 196 $ 259 $ 5,283
Future production and
development costs 2,040 148 121 61 2,370
Future income tax expenses 612 93 20 53 778
---------- ---------- ---------- ---------- ---------- ---------- ----------
Future net cash flows 1,678 257 55 145 2,135
10% annual discount for
estimated timing of cash flows 615 95 20 53 783
---------- ---------- ---------- ---------- ---------- ---------- ----------
Standardized measure of
discounted future net
cash flows $ 1,063 $ $ 162 $ $ 35 $ 92 $ 1,352
---------- ---------- ---------- ---------- ---------- ---------- ----------
</TABLE>
Construction of AMPCO's Equatorial Guinea methanol plant is scheduled to be
completed in the second quarter of 2001. The future net cash inflows for 1998
and 1999 do not include cash flows relating to the Company's anticipated future
methanol sales. For more information regarding Samedan's methanol plant, see
Item 1. "Business--Unconsolidated Subsidiary" and Item 2. "Properties--Oil and
Gas" of this Form 10-K.
56
<PAGE> 27
Future cash inflows are estimated by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves, with consideration given to the effect of existing hedging contracts,
if any.
The year-end weighted average oil market price utilized in the computation of
future cash inflows was approximately $23.62 per BBL. West Texas intermediate
crude oil price in mid February was approximately $27.25 per BBL, an increase of
$3.63 per BBL compared to year-end 1999. 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 $67
million.
The year-end weighted average gas market price utilized in the computation of
future cash inflows was approximately $2.15 per MCF. Natural gas index prices at
Henry Hub have increased approximately $.41 per MCF to $2.56 per MCF in mid
February compared with the year-end price. The Company estimates that a $.10 per
MCF change in the average gas price from the year-end price would change
discounted future net cash flows before income taxes by approximately $68
million.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the estimated future pretax net cash flows relating to
the Company's proved oil and gas reserves, less the tax bases of the properties
involved. The future income tax expenses give effect to tax credits and
allowances, but do not reflect the impact of general and administrative costs
and exploration expenses of ongoing operations relating to the Company's proved
oil and gas reserves.
At December 31, 1999, the Company had estimated gas imbalance receivables of
$17.9 million and estimated gas imbalance liabilities of $12.0 million; at
year-end 1998, $19.1 million in receivables and $14.8 million in liabilities;
and at year-end 1997, $18.5 million in receivables and $21.6 million in
liabilities. Neither the gas imbalance receivables nor gas imbalance liabilities
have been included in the standardized measure of discounted future net cash
flows as of each of the three years ended December 31, 1999, 1998 and 1997.
57
<PAGE> 28
SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited)
Principal changes in the aggregate standardized measure of discounted future net
cash flows attributable to the Company's proved oil and gas reserves, as
required by Financial Accounting Standards Board's SFAS No. 69, at year end are
shown below.
<TABLE>
<CAPTION>
(in millions of dollars) 1999 1998 1997
- ------------------------------------------ ------- ------- -------
<S> <C> <C> <C>
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 982 $ 1,352 $ 2,222
Extensions, discoveries and improved
recovery, less related costs 410 39 501
Revisions of previous quantity estimates 89 (132) 13
Changes in estimated future
development costs (202) (17) (15)
Purchases (sales) of minerals in place (58) 46 (45)
Net changes in prices and production costs 673 (443) (1,259)
Accretion of discount 102 189 310
Sales of oil and gas produced, net of
production costs (425) (454) (594)
Development costs incurred during
the period 21 127 38
Net change in income taxes (317) 503 332
Change in timing of estimated future
production, and other 218 (228) (151)
------- ------- -------
Standardized measure of discounted
future net cash flows at the end
of the year $ 1,493 $ 982 $ 1,352
- ------------------------------------------ ------- ------- -------
</TABLE>
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 1999 and 1998 is
as follows:
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------
(in thousands except per share amounts) Mar. 31, June 30, Sept. 30, Dec. 31,(1)
- --------------------------------------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
1999
Revenues $ 175,865 $ 216,245 $ 241,971 $ 252,698
Gross profit from operations $ 128 $ 22,959 $ 41,453 $ 38,087
Net income $ (8,901) $ 9,179 $ 27,654 $ 21,529
Basic earnings per share $ (.16) $ .16 $ .49 $ .38
Diluted earnings per share $ (.16) $ .16 $ .48 $ .38
1998
Revenues $ 246,535 $ 237,392 $ 205,803 $ 203,841
Gross profit (loss) from operations $ 31,838 $ 27,326 $ (25,616) $ (235,922)
Net income $ 13,718 $ 12,135 $ (25,150) $ (164,728)
Basic earnings per share $ .24 $ .21 $ (.44) $ (2.89)
Diluted earnings per share $ .24 $ .21 $ (.44) $ (2.89)
</TABLE>
(1) During the fourth quarters of 1999 and 1998, DD&A expense increased $7.6
million and $9.8 million, respectively, relating to the cumulative effect
of oil and gas reserve revisions on the DD&A provision for the preceding
three quarters.
58
<PAGE> 29
SIGNATURES
Pursuant to the requirements of Section 27 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Amendment No. 1 to be signed on
its behalf by the undersigned, thereunto duly authorized.
NOBLE AFFILIATES, INC.
Date: March 27, 2000 By: /s/ James L. McElvany
---------------------------------------------
James L. McElvany,
Vice President-Finance and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Amendment No. 1 has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Capacity in which signed Date
- --------- ------------------------ ----
<S> <C> <C>
/s/ Robert Kelley Chairman of the Board, President, March 27, 2000
- ------------------------------------ Chief Executive Officer and
Robert Kelley Director (Principal Executive
Officer)
/s/ James L. McElvany Vice President-Finance and Treasurer March 27, 2000
- ------------------------------------ (Principal Financial and Accounting
James L. McElvany Officer)
/s/ Alan A. Baker Director March 27, 2000
- ------------------------------------
Alan A. Baker
/s/ Michael A. Cawley Director March 27, 2000
- ------------------------------------
Michael A. Cawley
/s/ Edward F. Cox Director March 27, 2000
- ------------------
Edward F. Cox
/s/ Thomas E. Hassen Director March 27, 2000
- ------------------------------------
Thomas E. Hassen
/s/ Dale P. Jones Director March 27, 2000
- ------------------------------------
Dale P. Jones
/s/ Harold F. Kleinman Director March 27, 2000
- ------------------------------------
Harold F. Kleinman
/s/ T. Don Stacy Director March 27, 2000
- ------------------------------------
T. Don Stacy
</TABLE>
60
<PAGE> 30
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------ ----------
<S> <C> <C>
3.1 -- Certificate of Incorporation, as amended, of the Registrant as
currently in effect (filed as Exhibit 3.2 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1987
and incorporated herein by reference).
3.2 -- Certificate of Designations of Series A Junior Participating
Preferred Stock of the Registrant dated August 27, 1997 (filed
Exhibit A of Exhibit 4.1 to the Registrant's Registration
Statement on Form 8-A filed on August 28, 1997 and incorporated
herein by reference).
3.3 -- Composite copy of Bylaws of the Registrant as currently in effect
(filed as Exhibit 3.4 to the Registrants' Annual Report on Form
10-K for the year ended December 31, 1997 and incorporated herein
by reference).
3.4 -- Certificate of Designations of Series B Mandatorily Convertible
Preferred Stock of the Registrant dated November 9, 1999.
4.1 -- Indenture dated as of October 14, 1993 between the Registrant and
U.S. Trust Company of Texas, N.A., as Trustee, relating to the
Registrant's 7 1/4% Notes Due 2023, including form of the
Registrant's 7 1/4% Notes Due 2023 (filed as Exhibit 4.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1993 and incorporated herein by reference).
4.2 -- Indenture relating to Senior Debt Securities dated as of April 1,
1997 between the Registrant and U.S. Trust Company of Texas,
N.A., as Trustee (filed as Exhibit 4.1 to the Registrant's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1997 and incorporated herein by reference).
4.3 -- First Indenture Supplement relating to $250 million of the
Registrant's 8% Senior Notes Due 2027 dated as of April 1, 1997
between the Registrant and U.S. Trust Company of Texas, N.A., as
Trustee (filed as Exhibit 4.2 to the Registrant's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1997 and
incorporated herein by reference).
4.4 -- Second Indenture Supplement, between the Company and U.S. Trust
Company of Texas, N.A. as trustee, relating to $100 million of
the Registrant's 7 1/4% Senior Debentures Due 2097 dated as of
August 1, 1997 (filed as Exhibit 4.1 to the Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1997
and incorporated herein by reference).
4.5 -- Rights Agreement, dated as of August 27, 1997, between the
Registrant and Liberty Bank and Trust Company of Oklahoma City,
N.A., as Right's Agent (filed as Exhibit 4.1 to the Registrant's
Registration Statement on Form 8-A filed on August 28, 1997 and
incorporated herein by reference).
4.6 -- Amendment No. 1 to Rights Agreement dated as of December 8, 1998,
between the Registrant and Bank One Trust Company, as successor
Rights Agent to Liberty Bank and Trust Company of Oklahoma City,
N.A. (filed as Exhibit 4.2 to the Registrant's Registration
Statement on Form 8-A/A (Amendment No. 1) filed on December 14,
1998 and incorporated herein by reference).
10.1* -- Samedan Oil Corporation Bonus Plan, as amended and restated on
September 24, 1996 (filed as Exhibit 10.1 to the Registrant's
Annual Report on Form 10-K for the fiscal year ended December 31,
1996 and incorporated herein by reference).
10.2* -- Restoration of Retirement Income Plan for certain participants in
the Noble Affiliates Retirement Plan dated September 21, 1994,
effective as of May 19, 1994 (filed as Exhibit 10.5 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994 and incorporated herein by reference).
10.3 * -- Noble Affiliates Thrift Restoration Plan dated May 9, 1994 (filed
as Exhibit 10.6 to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994 and incorporated
herein by reference).
</TABLE>
61
<PAGE> 31
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------ ----------
<S> <C> <C>
10.4* -- Noble Affiliates Restoration Trust dated September 21, 1994,
effective as of October 1, 1994 (filed as Exhibit 10.7 to the
Registrant's Annual Report on Form 10-K for the fiscal year ended
December 31, 1994 and incorporated herein by reference).
10.5* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock
Plan, as amended and restated, dated November 2, 1992 (filed as
Exhibit 4.1 to the Registrant's Registration Statement on Form
S-8 (Registration No. 33-54084) and incorporated herein by
reference).
10.6* -- 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1 to
the Registrant's Registration Statement on Form S-8 (Registration
No. 2-81590) and incorporated herein by reference).
10.7* -- Amendment No. 1 to the 1982 Stock Option Plan of the Registrant
(filed as Exhibit 4.2 to the Registrant's Registration Statement
on Form S-8 (Registration No. 2-81590) and incorporated herein by
reference).
10.8* -- Amendment No. 2 to the 1982 Stock Option Plan of the Registrant
(filed as Exhibit 10.11 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1995 and incorporated herein
by reference).
10.9* -- 1988 Nonqualified Stock Option Plan for Non-Employee Directors of
the Registrant, as amended and restated, effective as of January
30, 1996 (filed as Exhibit 10.13 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1996 and
incorporated herein by reference).
10.10* -- Form of Indemnity Agreement entered into between the Registrant
and each of the Registrant's directors and bylaw officers (filed
as Exhibit 10.18 to the Registrant's Annual Report of Form 10-K
for the year ended December 31, 1995 and incorporated herein by
reference).
10.11 -- Guaranty of the Registrant dated October 28, 1982, guaranteeing
certain obligations of Samedan (filed as Exhibit 10.12 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1993 and incorporated herein by reference).
10.12 -- Stock Purchase Agreement dated as of July 1, 1996, between
Samedan Oil Corporation and Enterprise Diversified Holdings
Incorporated (filed as Exhibit 2.1 to the Registrant's Current
Report on Form 8-K (Date of Event: July 31, 1996) dated August 13,
1996 and incorporated herein by reference).
10.13* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock
Plan, as amended and restated on December 10, 1996, subject to
the approval of stockholders (filed as Exhibit 10.21 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1996 and incorporated herein by reference).
10.14 -- Amended and Restated Credit Agreement dated as of December 24,
1997 among the Registrant, as borrower, and Union Bank of
Switzerland, Houston agency, as the agent for the lender, and
NationsBank of Texas, N.A. and Texas Commerce Bank National
Association, as managing agents, and Bank of Montreal, CIBC Inc.,
The First National Bank of Chicago, Royal Bank of Canada, and
Societe Generale, Southwest agency, as co-agents, and certain
commercial lending institutions, as lenders (filed as Exhibit
10.20 to the Registrant's Annual Report on Form 10-K for the
fiscal year ended December 31, 1997 and incorporated herein by
reference).
</TABLE>
62
<PAGE> 32
<TABLE>
<CAPTION>
Exhibit
Number Exhibit **
- ------ ----------
<S> <C> <C>
10.15 -- Noble Preferred Stock Remarketing and Registration Rights
Agreement dated as of November 10, 1999 by and among the
Registrant, Noble Share Trust, The Chase Manhattan Bank, and
Donaldson, Lufkin & Jenrette Securities Corporation.
21 -- Subsidiaries
23 -- Consent of Arthur Andersen LLP.
23.1*** -- Consent of Arthur Andersen LLP.
27 -- Financial Data Schedule.
* 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 Vice
President-Finance and Treasurer, Noble Affiliates, Inc., Post
Office Box 1967, Ardmore, Oklahoma 73402.
*** Filed herewith
</TABLE>
63
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated January 28, 2000, included on page 32 of the Company's 1999
Form10-K/A, into the previously filed registration statements on Form S-3 (File
Nos.333-18929 and 333-82953) and on Form S-8 (File Nos. 333-39299, 2-64600,
2-81590, 33-32692, 2-66654 and 33-54084).
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
March 27, 2000
