<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------------
FORM 10-Q
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
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)
350 Glenborough Drive, Suite 100
Houston, Texas 77067
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(281) 872-3100
(Registrant's telephone number, including area code)
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___
Number of shares of common stock outstanding as of November 2, 2000: 55,957,681
================================================================================
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Dollars in thousands)
<TABLE>
<CAPTION>
(Unaudited)
September 30, December 31,
2000 1999
-------------- --------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and short-term investments................................... $ 27,716 $ 2,925
Accounts receivable-trade......................................... 173,225 98,794
Materials and supplies inventories................................ 6,650 5,517
Other current assets.............................................. 11,493 10,678
-------------- --------------
Total Current Assets.............................................. 219,084 117,914
-------------- --------------
Property, Plant and Equipment, at cost............................... 3,025,904 2,830,793
Less: accumulated depreciation,
depletion and amortization.............................. (1,707,763) (1,588,423)
-------------- --------------
1,318,141 1,242,370
-------------- --------------
Investment in unconsolidated subsidiary.............................. 54,237 15,625
Other Assets......................................................... 47,142 44,442
-------------- --------------
Total Assets...................................................... $ 1,638,604 $ 1,420,351
============== ==============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable-trade............................................ $ 163,584 $ 103,753
Other current liabilities......................................... 35,160 48,215
Income taxes-current.............................................. 19,448 2,503
-------------- --------------
Total Current Liabilities......................................... 218,192 154,471
-------------- --------------
Deferred Income Taxes................................................ 96,181 83,075
-------------- --------------
Other Deferred Credits and Noncurrent Liabilities.................... 58,809 53,877
-------------- --------------
Long-term Debt....................................................... 490,450 445,319
-------------- --------------
Shareholders' Equity:
Common stock...................................................... 196,130 195,231
Capital in excess of par value.................................... 367,517 360,983
Retained earnings................................................. 257,026 142,813
-------------- --------------
820,673 699,027
Less common stock in treasury at cost
(September 30, 2000, 2,911,300 shares and
December 31, 1999, 1,524,900 shares).............................. (45,701) (15,418)
-------------- --------------
Total Shareholders' Equity........................................ 774,972 683,609
-------------- --------------
Total Liabilities and Shareholders' Equity........................ $ 1,638,604 $ 1,420,351
============== ==============
</TABLE>
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
2
<PAGE>
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
----------------------------------------
2000 1999
------------ ------------
<S> <C> <C>
REVENUES:
Oil and gas sales and royalties...................................... $ 531,590 390,049
Gathering, marketing and processing.................................. 396,413 244,031
Other income......................................................... 11,300 17,895
------------ ------------
939,303 651,975
------------ ------------
COSTS AND EXPENSES:
Oil and gas operations............................................... 88,122 90,273
Oil and gas exploration.............................................. 44,718 31,402
Gathering, marketing and processing.................................. 386,598 232,947
Depreciation, depletion and amortization............................. 165,473 185,380
Selling, general and administrative.................................. 34,772 33,743
Interest............................................................. 28,255 37,867
Interest capitalized................................................. (3,942) (4,445)
------------ ------------
743,996 607,167
------------ ------------
INCOME BEFORE TAXES...................................................... 195,307 44,808
INCOME TAX PROVISION..................................................... 74,350(1) 16,876(1)
------------ ------------
NET INCOME............................................................... $ 120,957 $ 27,932
============ ============
BASIC EARNINGS PER SHARE................................................. $ 2.16(2) $ .49(2)
============ ============
DILUTED EARNINGS PER SHARE............................................... $ 2.13(2) $ .49(2)
============ ============
</TABLE>
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
3
<PAGE>
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended September 30,
-----------------------------------------
2000 1999
------------- -------------
<S> <C> <C>
REVENUES:
Oil and gas sales and royalties...................................... $ 211,478 $ 151,847
Gathering, marketing and processing.................................. 145,876 90,125
Other income......................................................... 3,578 13,501
------------- -------------
360,932 255,473
------------- -------------
COSTS AND EXPENSES:
Oil and gas operations............................................... 33,976 29,162
Oil and gas exploration.............................................. 17,469 14,200
Gathering, marketing and processing.................................. 142,831 87,975
Depreciation, depletion and amortization............................. 57,051 58,698
Selling, general and administrative.................................. 10,786 10,728
Interest............................................................. 9,295 12,144
Interest capitalized................................................. (1,456) (1,752)
------------- -------------
269,952 211,155
------------- -------------
INCOME BEFORE TAXES...................................................... 90,980 44,318
INCOME TAX PROVISION .................................................... 33,763 (1) 16,664 (1)
------------- -------------
NET INCOME ............................................................. $ 57,217 $ 27,654
============= =============
BASIC EARNINGS PER SHARE................................................ $ 1.02 (2) $ .49 (2)
============= =============
DILUTED EARNINGS PER SHARE.............................................. $ 1.01 (2) $ .48 (2)
============= =============
</TABLE>
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
4
<PAGE>
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
--------------------------------------
2000 1999
------------ ------------
<S> <C> <C>
Cash Flows from Operating Activities:
Net income............................................................ $ 120,957 $ 27,932
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............................ 165,473 185,380
Amortization of undeveloped lease costs, net........................ 8,514 7,059
Increase (decrease) in other deferred credits....................... 18,038 (16,195)
(Increase) decrease in other assets and other noncash items, net.... (4,679) (10,546)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable.......................... (74,431) 8,992
(Increase) decrease in other current assets and inventories......... (2,659) 39,945
Increase (decrease) in accounts payable............................. 59,831 (21,553)
Increase (decrease) in other current liabilities.................... 3,890 10,005
------------ ------------
Net Cash Provided by Operating Activities................................ 294,934 231,019
------------ ------------
Cash Flows From Investing Activities:
Capital expenditures................................................ (258,842) (72,720)
Investment in unconsolidated subsidiary............................. (38,612) (50,624)
Proceeds from sale of property, plant and equipment................. 11,906 19,782
------------ ------------
Net Cash Used in Investing Activities ................................... (285,548) (103,562)
------------ ------------
Cash Flows From Financing Activities:
Share repurchase.................................................... (30,283)
Exercise of stock options........................................... 7,433 825
Cash dividends...................................................... (6,745) (6,838)
Repayment of bank debt.............................................. (27,000) (75,000)
Proceeds from bank borrowings....................................... 72,000
------------ ------------
Net Cash Provided by (Used in) Financing Activities ..................... 15,405 (81,013)
------------ ------------
Increase (Decrease) in Cash and Short-term Cash Investments.............. 24,791 46,444
Cash and Short-term Cash Investments at Beginning of Period.............. 2,925 19,100
------------ ------------
Cash and Short-term Cash Investments at End of Period.................... $ 27,716 $ 65,544
============ ============
Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 20,154 $ 30,062
Income taxes ......................................................... $ 41,765 $ 12,000
</TABLE>
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
5
<PAGE>
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)
In the opinion of Noble Affiliates, Inc. (the "Company"), the
accompanying unaudited consolidated condensed financial statements contain all
adjustments, consisting only of necessary and normal recurring adjustments,
necessary to present fairly the Company's financial position as of September 30,
2000 and December 31, 1999 and the results of operations for the three month and
nine month periods ended September 30, 2000 and 1999, respectively, and the cash
flows for the nine month periods ended September 30, 2000 and 1999. These
consolidated condensed financial statements should be read in conjunction with
the consolidated financial statements and the notes thereto incorporated in the
Company's annual report on Form 10-K for the year ended December 31, 1999.
(1) INCOME TAX PROVISION (BENEFIT)
For the three months ended September 30:
<TABLE>
<CAPTION>
(IN THOUSANDS)
-----------------------------------
2000 1999
---------- ----------
<S> <C> <C>
Current.............................................. $ 33,622 $ 16,842
Deferred............................................. 141 (178)
---------- ----------
$ 33,763 $ 16,664
========== ==========
For the nine months ended September 30:
(IN THOUSANDS)
-----------------------------------
2000 1999
---------- ----------
Current.............................................. $ 61,727 $ 7,488
Deferred............................................. 12,623 9,388
---------- ----------
$ 74,350 $ 16,876
========== ==========
</TABLE>
(2) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic earnings per share of common stock was computed using the weighted
average number of shares of common stock outstanding during each period. The
diluted net income per share of common stock includes the effect of outstanding
stock options.
The following tables summarize the calculation of basic earnings per
share ("EPS") and the diluted EPS components required by Statement of Financial
Accounting Standards ("SFAS") No. 128, "Earnings per Share."
For the three months ended September 30:
<TABLE>
<CAPTION>
2000 1999
--------------------------- ---------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net income/shares $57,217 55,875 $27,654 57,003
-----------------------------------------------------------------------------------------------------
BASIC EPS $1.02 $.49
Net income/shares $57,217 55,875 $27,654 57,003
Effect of Dilutive Securities
-----------------------------
Stock options 830 500
Adjusted net income/shares $57,217 56,705 $27,654 57,503
-----------------------------------------------------------------------------------------------------
DILUTED EPS $1.01 $.48
-----------------------------------------------------------------------------------------------------
</TABLE>
6
<PAGE>
For the nine months ended September 30:
<TABLE>
<CAPTION>
2000 1999
--------------------------- ----------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net income/shares $120,957 56,008 $27,932 56,991
-----------------------------------------------------------------------------------------------------
BASIC EPS $2.16 $.49
Net income/shares $120,957 56,008 $27,932 56,991
Effect of Dilutive Securities
-----------------------------
Stock options 690 391
Adjusted net income/shares $120,957 56,698 $27,932 57,382
-----------------------------------------------------------------------------------------------------
DILUTED EPS $2.13 $.49
-----------------------------------------------------------------------------------------------------
</TABLE>
(3) TRADING AND HEDGING ACTIVITIES
The Company, through its subsidiaries, from time to time, uses various
hedging arrangements in connection with anticipated crude oil and natural gas
sales to minimize the impact of product price fluctuations. Such arrangements
include fixed price hedges, costless collars, and other contractual
arrangements. Although these hedging arrangements expose the Company to credit
risk, the Company monitors the creditworthiness of its counterparties, which
generally are major financial institutions, and believes that losses from
nonperformance are unlikely to occur. Hedging gains and losses related to the
Company's oil and gas production are recorded in oil and gas sales and
royalties. The swap component of the contracts discussed in the following
paragraphs was treated as a hedge for accounting purposes only.
The Company 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 $1,663,000 and
$2,920,000 recorded in other income for the three months and nine months ended
September 30, 2000, respectively.
The effect of these swap hedges was a $3.23 per BBL reduction in the
average crude oil price for the third quarter. For the nine months ended
September 30, 2000, the net effect of the swap hedges was a $2.73 per BBL
reduction in the average crude oil price. Premium swap hedges for October 2000
through December 2000, which average 7,000 BBLS per day, were not closed at
September 30, 2000.
In addition to the premium swap crude oil contracts, the Company entered
into crude oil costless collar hedges from January 1, 2000, to April 30, 2000,
for volumes of 2,000 BBLS per day. These costless collars had a floor price
7
<PAGE>
ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from
$25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the
Company to receive settlements from the counterparties in amounts, if any, by
which the monthly average settlement price for each NYMEX trading day during a
contract month was less than the floor price. If the monthly average settlement
price was above the applicable cap price, then the Company would have owed the
counterparties for the excess of the monthly average settlement price over the
applicable cap price. If the monthly average settlement price fell between the
applicable floor and cap price, then neither party had any liability to the
other party for that month. Payment, if any, was made monthly under each of the
contracts in an amount equal to the net amount due either party based on the
volumes per day multiplied by the difference between the NYMEX average price and
the cap price, if the NYMEX average price exceeded the cap price, or if the
NYMEX average price was less than the floor price, then the volumes per day
multiplied by the difference between the floor price and the NYMEX average
price.
There was no effect from these costless collar hedges during the third
quarter of 2000. For the nine months ended September 30, 2000, the net effect of
the costless collar hedges was a $.06 per BBL reduction in the average crude oil
price.
The Company had no natural gas or crude oil hedging contracts related to
its production for the nine months ended September 30, 1999. The Company had no
natural gas hedging contracts in 2000.
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 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 (such as purchasing a NYMEX futures
contract at the Henry Hub with an adjoining basis swap at a physical location)
thereby determining the margin and minimizing the risk of price volatility.
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.
As of September 30, 2000 the Company had no material market risk exposure
from NGM's derivative activity. During the third quarter of 2000, NGM had
hedging transactions with broker-dealers that represented approximately 948,000
MMBTU's of gas per day. Hedges for October 2000 through May 2006, which range
from 645 MMBTU's to 827,000 MMBTU's of gas per day for future physical
transactions, were not closed at September 30, 2000. During the third quarter of
1999, NGM had hedging transactions with broker-dealers that represented
approximately 624,000 MMBTU's of gas per day. For the nine months ended
September 30, 2000, NGM had hedging transactions that represented approximately
697,000 MMBTU's of gas per day, compared with 609,000 MMBTU's of gas per day for
the same period in 1999.
The Financial Accounting Standards Board ("FASB") issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" in June 1998. The
Statement establishes accounting and reporting standards requiring every
derivative instrument (including certain derivative instruments embedded in
other contracts) to be recorded in the balance sheet as either an asset or
liability measured at its fair value. The Statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met wherein gains and losses are reflected in
shareholders' equity until the hedged item is recognized. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
formally document, designate and assess the effectiveness of transactions that
receive hedge accounting.
Due to the issuance of SFAS No. 137, which deferred the effective date of
SFAS No. 133, the Company is required to adopt the statement for fiscal years
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998). The Company has not quantified the impact of adopting SFAS No. 133 but
plans on adopting the statement by January 1, 2001.
During 2000, the FASB issued SFAS No. 138 which amends the accounting and
reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS
8
<PAGE>
No. 133, according to its provisions and the issuance of SFAS No. 137. The
normal purchases and normal sales exception may be applied to contracts that
implicitly or explicitly permit net settlement and contracts that have a
market mechanism to facilitate net settlement. The Company has not quantified
the impact SFAS No. 138 will have upon the adoption of SFAS No. 133.
(4) METHANOL PLANT
The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company LDC ("AMCCO"), is a 50 percent owned joint venture that indirectly owns
90 percent of Atlantic Methanol Production Company LLC ("AMPCO"), which is
constructing a methanol plant in Equatorial Guinea. During 1999, AMCCO issued
$125 million senior secured notes due 2004 net to the Company's interest (which
are not included in the Company's balance sheet) to fund the remaining
construction payments. The plant construction started during 1998 and commercial
production is expected during the second quarter of 2001. The construction cost
of the turnkey contract is $325.5 million. Other associated expenditures
required to complete the project and produce marketable supplies of methanol are
projected to be $113.5 million. The total cost of the methanol project is
estimated to be $439.0 million including various contingencies and capitalized
interest, with the Company responsible for $219.5 million. Payments are due upon
the completion of specific phases of the construction. The Company has
construction contract phase payments totaling $4.8 million due in the fourth
quarter of 2000 and the remaining $9.5 million due in the first half of 2001.
(5) COMPANY STOCK REPURCHASE PLAN
On February 1, 2000 the Company's Board of Directors authorized a
repurchase of up to $50 million of the Company's common stock. As of September
30, 2000, the Company had completed 60.5 percent of the repurchase plan. The
repurchase of 1,386,400 shares at an average cost of $21.84 per share was funded
from the Company's current cash flow.
(6) RECLASSIFICATION TO CONFORM TO CURRENT YEAR PRESENTATION
Certain reclassifications have been made to the 1999 consolidated
financial statements to conform to the 2000 presentation.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report on Form 10-Q includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. All statements other
than statements of historical fact included in this Form 10-Q, including,
without limitation, statements contained under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" regarding anticipated
capital expenditures, projected timing of planned projects or activities, the
Company's financial position, 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 quarterly report on Form 10-Q and the other
documents of the Company filed with the Securities and Exchange Commission (the
"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.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities increased to $294.9 million in
the nine months ended September 30, 2000 from $231.0 million in the same period
of 1999. Cash and short-term investments increased from $2.9 million at December
31, 1999 to $27.7 million at September 30, 2000.
9
<PAGE>
During the first half of 2000, the Company borrowed $72.0 million on its
$300 million credit facility. During the third quarter of 2000, the Company
repaid $15.0 million. At December 31, 1999, there was no debt outstanding on the
$300 million credit facility. Long-term debt at September 30, 2000 was $490.5
million compared with $445.3 million at December 31, 1999.
The Company has expended approximately $297.5 million of its $426.0
million 2000 capital budget through September 30, 2000. The Company expects to
fund its remaining 2000 capital budget from cash flows from operations and
additional borrowings from the credit facilities as required. The Company
continues to evaluate possible strategic acquisitions and believes it is
positioned to access external sources of funding should it be necessary or
desirable in connection with an acquisition.
Through the recently formed Atlantic Methanol Production Company LLC
("AMPCO"), the Company is participating, with a 50 percent expense interest (45
percent ownership net of a five percent government carried interest), in a joint
venture with CMS Energy Corporation to construct a methanol plant on Bioko
Island in Equatorial Guinea. The plant will use the gas from Samedan's 34.8
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 approximately
$.25 per MMBTU.
On January 29, 1998, AMPCO awarded a contract to Raytheon Engineers and
Constructors to build the methanol plant. The turnkey plant construction cost is
$325.5 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 construction
contract stipulates that the first commercial production of methanol is expected
by the second quarter of 2001. Current marketing plans are to enter into
long-term contracts with methanol users in the United States and Europe.
The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company LDC ("AMCCO"), is a 50 percent owned joint venture that indirectly owns
90 percent of AMPCO. During 1999, AMCCO issued $125 million senior secured notes
due 2004 net to the Company's interest (which are not included in the Company's
balance sheet) to fund the remaining construction payments. The plant
construction started during 1998 and commercial production is expected during
the second quarter of 2001. The construction cost of the turnkey contract is
$325.5 million. Other associated expenditures required to complete the project
and produce marketable supplies of methanol are projected to be $113.5 million.
The total cost of the methanol project is estimated to be $439.0 million
including various contingencies and capitalized interest, with the Company
responsible for $219.5 million. Payments are due upon the completion of specific
phases of the construction. The Company has construction contract phase payments
totaling $4.8 million due in the fourth quarter of 2000 and the remaining $9.5
million due in the first half of 2001.
The Company follows the entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $18.4 million
at September 30, 2000 and $17.9 million at December 31, 1999. Estimated gas
imbalance liabilities were $14.5 million at September 30, 2000 and $12.0 million
at December 31, 1999. These imbalances are valued at the amount that is expected
to be paid to settle the imbalances for liabilities and for assets at the prices
prevalent on the day the imbalance was created. The settlement of the imbalances
can occur either over the life 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 settlement of gas imbalances will not have a material impact on its
liquidity.
RESULTS OF OPERATIONS
For the third quarter of 2000, the Company recorded net income of $57.2
million, or $1.02 per share, compared with net income of $27.7 million, or $.49
per share, for the third quarter of 1999. During the first nine months of 2000,
the Company recorded net income of $121.0 million, or $2.16 per share, compared
with $27.9 million, or $.49 per share, in the first nine months of 1999. The
increase resulted primarily from substantially higher product prices.
Gas sales for the Company, excluding third party sales by Noble Gas
Marketing, Inc. ("NGM"), a wholly owned subsidiary of the Company, increased 51
percent and 36 percent, respectively, for the three months and nine months ended
September 30, 2000, as compared with the same periods in 1999. The increase in
sales is due to an increase in the average gas price of 60 percent and 54
percent, respectively, for the three months and nine months ended September 30,
2000, compared with the same periods in 1999. This was offset by a gas
production volume decrease of six percent and 13 percent, respectively, for the
three months and nine months ended September 30, 2000, compared with the same
periods in 1999.
10
<PAGE>
Oil sales for the Company, excluding third party sales by Noble Trading,
Inc. ("NTI"), a wholly owned subsidiary of the Company, increased 18 percent
and 39 percent, respectively, for the three months and nine months ended
September 30, 2000, compared with the same periods in 1999. The increase in
sales was due to an increase in the average oil price of 34 percent and 68
percent, respectively, for the three months and nine months ended September 30,
2000, compared with the same periods of 1999. This was offset by an oil
production volume decrease of 12 percent and 17 percent, respectively, for the
three months and nine months ended September 30, 2000, compared with the same
periods in 1999.
NGM markets a majority of 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.
NTI markets a portion of the Company's oil as well as certain third party oil.
The Company records all of NGM's and NTI's sales as gathering, marketing and
processing revenues and expenses. All intercompany sales and expenses have been
eliminated.
For the third quarter of 2000, revenues and expenses from NGM and NTI
third party sales totaled $145.9 million and $142.8 million, respectively, for
a combined gross margin of $3.1 million. In comparison, for the third quarter
of 1999, NGM and NTI third party revenues and expenses of $90.1 million and
$88.0 million, respectively, resulted in a combined gross margin of $2.1
million. For the nine months ended September 30, 2000, combined NGM and NTI
revenues and expenses from third party sales totaled $396.4 million and $386.6
million, respectively, for a gross margin of $9.8 million. In comparison,
combined NGM and NTI third party revenues and expenses of $244.0 million and
$232.9 million, respectively, resulted in a gross margin of $11.1 million for
the same period in 1999.
The Company, through its subsidiaries, from time to time, uses various
hedging arrangements in connection with anticipated crude oil and natural gas
sales to minimize the impact of product price fluctuations. Such arrangements
include fixed price hedges, costless collars, and other contractual
arrangements. Although these hedging arrangements expose the Company to credit
risk, the Company monitors the creditworthiness of its counterparties, which
generally are major financial institutions, and believes that losses from
nonperformance are unlikely to occur. Hedging gains and losses related to the
Company's oil and gas production are recorded in oil and gas sales and
royalties. The swap component of the contracts discussed in the following
paragraphs was treated as a hedge for accounting purposes only.
The Company 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 $1,663,000
and $2,920,000 recorded in other income for the three months and nine months
ended September 30, 2000, respectively.
11
<PAGE>
The effect of these swap hedges was a $3.23 per BBL reduction in the
average crude oil price for the third quarter. For the nine months ended
September 30, 2000, the net effect of the swap hedges was a $2.73 per BBL
reduction in the average crude oil price. Premium swap hedges for October 2000
through December 2000, which average 7,000 BBLS per day, were not closed at
September 30, 2000.
In addition to the premium swap crude oil contracts, the Company entered
into crude oil costless collar hedges from January 1, 2000, to April 30, 2000,
for volumes of 2,000 BBLS per day. These costless collars had a floor price
ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from
$25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the
Company to receive settlements from the counterparties in amounts, if any, by
which the monthly average settlement price for each NYMEX trading day during a
contract month was less than the floor price. If the monthly average settlement
price was above the applicable cap price, then the Company would have owed the
counterparties for the excess of the monthly average settlement price over the
applicable cap price. If the monthly average settlement price fell between the
applicable floor and cap price, then neither party had any liability to the
other party for that month. Payment, if any, was made monthly under each of the
contracts in an amount equal to the net amount due either party based on the
volumes per day multiplied by the difference between the NYMEX average price
and the cap price, if the NYMEX average price exceeded the cap price, or if the
NYMEX average price was less than the floor price, then the volumes per day
multiplied by the difference between the floor price and the NYMEX average
price.
There was no effect from these costless collar hedges during the third
quarter of 2000. For the nine months ended September 30, 2000, the net effect
of the costless collar hedges was a $.06 per BBL reduction in the average crude
oil price.
The Company had no natural gas or crude oil hedging contracts related to
its production for the nine months ended September 30, 1999. The Company had no
natural gas hedges in 2000.
NGM, from time to time, employs hedging arrangements in connection with
its purchases and sales of production. While most of NGM's purchases are made
for an index-based price, NGM's customers often require prices that are either
fixed or related to NYMEX. In order to establish a fixed margin and mitigate
the risk of price volatility, NGM may convert a fixed or NYMEX sale to an
index-based sales price (such as purchasing a NYMEX futures contract at the
Henry Hub with an adjoining basis swap at a physical location). As of September
30, 2000 the Company had no material market risk exposure from NGM's derivative
activity. During the third quarter of 2000, NGM had hedging transactions with
broker-dealers that represented approximately 948,000 MMBTU's of gas per day.
Hedges for October 2000 through May 2006, which range from 645 MMBTU's to
827,000 MMBTU's of gas per day for future physical transactions, were not
closed at September 30, 2000. During the third quarter of 1999, NGM had hedging
transactions with broker-dealers that represented approximately 624,000 MMBTU's
of gas per day. For the nine months ended September 30, 2000, NGM had hedging
transactions that represented approximately 697,000 MMBTU's of gas per day,
compared with 609,000 MMBTU's of gas per day for the same period in 1999.
The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities" in June 1998. The Statement establishes
accounting and reporting standards requiring every derivative instrument
(including certain derivative instruments embedded in other contracts) to be
recorded in the balance sheet as either an asset or liability measured at its
fair value. The Statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met wherein gains and losses are reflected in shareholders' equity until
the hedged item is recognized. Special accounting for qualifying hedges allows
a derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally document, designate
and assess the effectiveness of transactions that receive hedge accounting.
Due to the issuance of SFAS No. 137, which deferred the effective date
of SFAS No. 133, the Company is required to adopt the statement for fiscal
years beginning after June 15, 2000. A company may also implement the statement
as of the beginning of any fiscal quarter after the statement's issuance (that
is, fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must
be applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before
January 1, 1998). The Company has not quantified the impact of adopting SFAS
No. 133 but plans on adopting the statement by January 1, 2001.
During 2000, the FASB issued SFAS No. 138 which amends the accounting
and reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS
12
<PAGE>
No. 133, according to its provisions and the issuance of SFAS No. 137. The
normal purchases and normal sales exception may be applied to contracts that
implicitly or explicitly permit net settlement and contracts that have a market
mechanism to facilitate net settlement. The Company has not quantified the
impact SFAS No. 138 will have upon the adoption of SFAS No. 133.
Certain selected oil and gas operating statistics follow:
<TABLE>
<CAPTION>
For the three months For the nine months
ended September 30, ended September 30,
------------------------- -----------------------
2000 1999 2000 1999
------------ --------- --------- -----------
<S> <C> <C> <C> <C>
Oil revenue (in thousands)............... $ 59,782 $ 50,765 $ 165,786 $ 119,374
Average daily oil production - BBLS...... 25,863 29,308 25,624 30,890
Average oil price per BBL................ $ 25.76 $ 19.16 $ 24.23 $ 14.45
Gas revenue (in thousands)............... $ 147,161 $ 97,727 $ 353,381 $ 260,694
Average daily gas production - MCF....... 401,084 428,051 401,857 462,304
Average gas price per MCF................ $ 4.07 $ 2.54 $ 3.28 $ 2.13
</TABLE>
BBLS - BARRELS
MCF - THOUSAND CUBIC FEET
Oil and gas exploration expense increased $3.3 million and $13.3
million, respectively, for the three months and nine months ended September 30,
2000, as compared with the same periods in 1999. These increases are
attributable to a $2.2 million and $8.9 million increase in dry hole expense
for the three months and nine months ended September 30, 2000 as compared with
the same periods in 1999. Seismic expense increased $2.2 million for the nine
months ended September 30, 2000, as compared with the same period in 1999.
Oil and gas operations expense increased $4.8 million and decreased $2.2
million, respectively, for the three months and nine months ended September 30,
2000, as compared with the same periods in 1999. The third quarter increase is
primarily due to increased lease operations expense of $4.2 million, of which
27 percent of the total lease operations was related to workover expenses. The
year to date decrease in lease operations expense compared with the same period
in 1999, is due to lower production volumes.
Depreciation, depletion and amortization ("DD&A") expense decreased
three percent and 11 percent, respectively, for the three months and nine
months ended September 30, 2000 compared with the same periods in 1999. The
unit rate of DD&A per barrel of oil equivalent ("BOE"), converting gas to oil
on the basis of 6 MCF per barrel, was $6.52 for the first nine months of 2000
compared with $6.29 for the same period of 1999. The unit rate of DD&A per BOE
was $6.69 for the three months ended September 30, 2000 compared with $6.34 for
the same period in 1999. The Company has recorded, through charges to DD&A, a
reserve for estimated future liabilities related to dismantlement and
reclamation costs for offshore facilities. This reserve is based on the best
estimates of Company engineers of such costs to be incurred in future years.
Interest expense decreased 23 percent and 25 percent for the three
months and nine months ended September 30, 2000, as compared with the same
periods in 1999. The decrease is attributable to a $179.8 million decrease in
long-term debt at September 30, 2000 compared with September 30, 1999.
FUTURE TRENDS
The Company expects the upward trend of oil and gas volumes reflected in
the third quarter to continue during the remainder of 2000, with increasing
volumes in 2001 and 2002. The 2001 volume increase would be primarily due to
the Alba field condensate production and gas feedstock for the methanol plant
in Equatorial Guinea along with domestic exploitation. The 2002 volume increase
would be primarily due to oil production in China and gas production from the
Amistad gas field in Ecuador.
The Company has set its 2000 exploration and development budget at
$497.5 million (composed of the capital budget and the exploration budget). In
addition, on November 1, 2000, the Company expended approximately $53.6 million
to increase its interest to approximately 47.0 percent from 40.0 percent in an
exploration agreement offshore Israel. Such expenditures are planned to be
funded through internally generated cash flows and borrowings from the
13
<PAGE>
$300 million credit facility to complete the methanol project. The Company
believes that it is well positioned to take advantage of strategic acquisitions
as they become available, through internally generated cash flows or borrowings.
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
affect the oil and gas industry. The Company can not predict the extent to
which its revenues will be affected by inflation, government regulation or
changing prices.
On February 1, 2000 the Company's Board of Directors authorized a
repurchase of up to $50 million of the Company's common stock. As of September
30, 2000, the Company had completed 60.5 percent of the repurchase plan. The
repurchase of 1,386,400 shares at an average cost of $21.84 per share was
funded from the Company's current cash flow.
YEAR 2000 ISSUE
The Year 2000 issue is a result of computer programs being written using
two digits rather than four to define the applicable year. Computer equipment,
software and devices with embedded technology that are time-sensitive may
recognize a date using "00" as the year 1900 rather than the year 2000. This
can result in a system failure or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices, or engage in similar normal business activities.
The Company took various initiatives intended to ensure that its computer
equipment and software would function properly with respect to dates in the
year 2000 and thereafter.
As of September 30, 2000, the Company has encountered no significant
Year 2000 problems.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
The Company is exposed to market risk in the normal course of its
business operations. Management believes that the Company is well positioned
with its mix of oil and gas reserves to take advantage of future price
increases that may occur. However, the uncertainty of oil and gas prices
continues to impact the domestic oil and gas industry. Due to the volatility of
oil and gas prices, the Company, from time to time, has used derivative hedging
and may do so in the future as a means of controlling its exposure to price
changes. The Company had no crude oil or natural gas hedges for its production
in 1999. The swap component of the contracts discussed in the following
paragraphs was treated as a hedge for accounting purposes only.
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.
14
<PAGE>
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 $1,663,000
and $2,920,000 recorded in other income for the three months and nine months
ended September 30, 2000, respectively.
The effect of these swap hedges was a $3.23 per BBL reduction in the
average crude oil price for the third quarter. For the nine months ended
September 30, 2000, the net effect of the swap hedges was a $2.73 per BBL
reduction in the average crude oil price. Premium swap hedges for October 2000
through December 2000, which average 7,000 BBLS per day, were not closed at
September 30, 2000.
There was no effect from these costless collar hedges during the third
quarter of 2000. For the nine months ended September 30, 2000, the net effect
of the costless collar hedges was a $.06 per BBL reduction in the average crude
oil price.
NGM, from time to time, employs hedging arrangements in connection with
its purchases and sales of production. While most of NGM's purchases are made
for an index-based price, NGM's customers often require prices that are either
fixed or related to NYMEX. In order to establish a fixed margin and mitigate
the risk of price volatility, NGM may convert a fixed or NYMEX sale to an
index-based sales price (such as purchasing a NYMEX futures contract at the
Henry Hub with an adjoining basis swap at a physical location ). As of
September 30, 2000, the Company had no material market risk exposure from NGM's
derivative activity.
The Company has a $300 million credit agreement that exposes the Company
to the risk of earnings or cash flow loss due to changes in market interest
rates. At September 30, 2000, the Company had $45 million outstanding on its
$300 million credit facility which has a maturity date of December 24, 2002.
The interest rate is based upon a Eurodollar rate plus a range of 17.5 to 50
basis points. All other Company long-term debt is fixed-rate and, therefore,
does not expose the Company to the risk of earnings or cash flow loss due to
changes in market interest rates.
On June 17, 1999, the Company entered into a new $100 million 364 day
credit agreement with certain commercial lending institutions. This agreement
is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon
the percentage of utilization. No amounts are outstanding under this credit
agreement as of September 30, 2000.
The Company does not invest in foreign currency derivatives. The U.S.
dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and the Company does not believe it is currently exposed to any material risk
of loss on this basis. Such gains or losses are included in other expense on
the income statement. However, certain sales transactions are concluded in
foreign currencies and the Company therefore is exposed to potential risk of
loss based on fluctuation in exchange rates from time to time.
15
<PAGE>
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The information required by this Item 6(a) is set forth in the Index to
Exhibits accompanying this quarterly report on Form 10-Q.
(b) The Company did not file any reports on Form 8-K during the three months
ended September 30, 2000.
16
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934 as
amended, the registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.
NOBLE AFFILIATES, INC.
(Registrant)
Date November 13, 2000 /s/ JAMES L. McELVANY
--------------------- -------------------------------------
JAMES L. McELVANY
Vice President-Finance and Treasurer
(Principal Financial Officer
and Authorized Signatory)
17
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Exhibit
--------- ---------------------------------------------------
27.1 Financial Data Schedule
