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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, 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)
(580) 223-4110
(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 October 21, 1999: 57,045,513
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Dollars in thousands)
(Unaudited)
September 30, December 31,
1999 1998
------------------ ----------------
ASSETS
Current Assets:
Cash and short-term investments................................... $ 65,544 $ 19,100
Accounts receivable-trade......................................... 97,521 106,513
Materials and supplies inventories................................ 5,808 3,006
Other current assets.............................................. 24,709 59,670
------------- -----------
Total Current Assets.............................................. 193,582 188,289
------------- -----------
Property, Plant and Equipment........................................ 2,897,122 2,915,917
Less: accumulated depreciation,
depletion and amortization.............................. (1,597,561) (1,486,250)
------------- -----------
1,299,561 1,429,667
------------- -----------
Investment in Unconsolidated Subsidiary.............................. 75,685 25,061
Other Assets......................................................... 44,283 43,063
------------- -----------
Total Assets...................................................... $ 1,613,111 $ 1,686,080
------------- -----------
------------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable-trade............................................ $ 86,985 $ 108,538
Other current liabilities......................................... 31,204 28,815
Income taxes-current.............................................. 17,153 1,813
------------- -----------
Total Current Liabilities......................................... 135,342 139,166
------------- -----------
Deferred Income Taxes................................................ 90,757 106,823
------------- -----------
Other Deferred Credits and Noncurrent Liabilities.................... 52,738 52,868
------------- -----------
Long-term Debt....................................................... 670,275 745,143
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Shareholders' Equity:
Common stock...................................................... 195,200 195,018
Capital in excess of par value.................................... 360,650 360,008
Retained earnings................................................. 123,566 102,472
------------- -----------
679,416 657,498
Less common stock in treasury
(at cost, 1,524,900 shares)....................................... (15,418) (15,418)
------------- ------------
Total Shareholders' Equity........................................ 663,999 642,080
------------- -----------
Total Liabilities and Shareholders' Equity........................ $ 1,613,111 $ 1,686,080
------------- -----------
------------- -----------
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
2
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
Nine Months Ended September 30,
----------------------------------------
1999 1998
------------ ----------
REVENUES:
Oil and gas sales and royalties...................................... $ 390,049 $ 470,543
Gathering, marketing and processing.................................. 244,031 219,188
Other income......................................................... 17,895 18,119
------------ ------------
651,975 707,850
------------ ------------
COSTS AND EXPENSES:
Oil and gas operations............................................... 90,273 114,241
Oil and gas exploration.............................................. 31,402 82,317
Gathering, marketing and processing.................................. 232,947 210,565
Depreciation, depletion and amortization............................. 185,380 228,802
Selling, general and administrative.................................. 33,743 38,476
Interest............................................................. 37,867 37,451
Interest capitalized................................................. (4,445) (5,118)
------------ ------------
607,167 706,734
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INCOME BEFORE TAXES...................................................... 44,808 1,116
INCOME TAX PROVISION..................................................... 16,876(1) 413(1)
------------ ------------
NET INCOME............................................................... $ 27,932 $ 703
------------ ------------
------------ ------------
BASIC EARNINGS PER SHARE................................................. $ .49(2) $ .01(2)
------------ ------------
------------ ------------
DILUTED EARNINGS PER SHARE............................................... $ .49(2) $ .01(2)
------------ ------------
------------ ------------
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
3
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended September 30,
-----------------------------------------
1999 1998
------------- ----------
REVENUES:
Oil and gas sales and royalties...................................... $ 151,847 $ 142,322
Gathering, marketing and processing.................................. 90,125 69,402
Other income......................................................... 13,501 587
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255,473 212,311
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COSTS AND EXPENSES:
Oil and gas operations............................................... 29,162 38,504
Oil and gas exploration.............................................. 14,200 41,575
Gathering, marketing and processing.................................. 87,975 66,072
Depreciation, depletion and amortization............................. 58,698 83,590
Selling, general and administrative.................................. 10,728 12,626
Interest............................................................. 12,144 12,999
Interest capitalized................................................. (1,752) (2,006)
------------ ------------
211,155 253,360
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INCOME (LOSS) BEFORE TAXES............................................... 44,318 (41,049)
INCOME TAX PROVISION (BENEFIT)........................................... 16,664(1) (15,899)(1)
------------ ------------
NET INCOME (LOSS)....................................................... $ 27,654 $ (25,150)
------------ ------------
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BASIC EARNINGS (LOSS) PER SHARE......................................... $ .49(2) $ (.44)(2)
------------ ------------
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DILUTED EARNINGS (LOSS) PER SHARE....................................... $ .48(2) $ (.44)(2)
------------ ------------
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SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
4
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Nine Months Ended September 30,
----------------------------------------
1999 1998
------------ -------------
Cash Flows from Operating Activities:
Net income............................................................ $ 27,932 $ 703
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............................ 185,380 228,802
Amortization of undeveloped lease costs, net........................ 7,059 2,415
Increase (decrease) in other deferred credits....................... (16,195) (6,381)
(Increase) decrease in other assets and other noncash items, net.... (10,546) 27,606
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable.......................... 8,992 12,627
(Increase) decrease in other current assets and inventories......... 32,221 1,629
Increase (decrease) in accounts payable............................. (21,553) 26,635
Increase (decrease) in other current liabilities.................... 17,729 3,969
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Net Cash Provided by Operating Activities................................ 231,019 298,005
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Cash Flows From Investing Activities:
Capital expenditures.................................................. (72,720) (416,297)
Investment in unconsolidated subsidiary............................... (50,624)
Proceeds from sale of property, plant and equipment................... 19,782 3,076
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Net Cash Used in Investing Activities ................................... (103,562) (413,221)
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Cash Flows From Financing Activities:
Exercise of stock options............................................ 825 2,045
Cash dividends....................................................... (6,838) (6,833)
Repayment of bank debt............................................... (75,000)
Proceeds from bank borrowings........................................ 85,000
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Net Cash Provided by (Used in) Financing Activities ..................... (81,013) 80,212
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Increase (Decrease) in Cash and Short-term Cash Investments.............. 46,444 (35,004)
Cash and Short-term Cash Investments at Beginning of Period.............. 19,100 55,075
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Cash and Short-term Cash Investments at End of Period.................... $ 65,544 $ 20,071
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Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 30,062 $ 27,423
Income taxes ......................................................... $ 12,000 $ 4,276
SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.
5
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, 1999 and the results of operations for the three month and
nine month periods ended September 30, 1999 and 1998, respectively, and the
cash flows for the nine month periods ended September 30, 1999 and 1998.
These consolidated condensed financial statements should be read in
conjunction with the consolidated financial statements and the notes thereto
included in the Company's annual report on Form 10-K for the year ended
December 31, 1998.
(1) INCOME TAX PROVISION (BENEFIT)
For the nine months ended September 30:
(In thousands)
-----------------------------------
1999 1998
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Current........................................................... $ 7,488 $ (1,454)
Deferred.......................................................... 9,388 1,867
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$ 16,876 $ 413
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For the three months ended September 30:
(In thousands)
-----------------------------------
1999 1998
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Current........................................................... $ 16,842 $ (6,751)
Deferred.......................................................... (178) (9,148)
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$ 16,664 $(15,899)
---------- -----------
---------- -----------
(2) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic earnings 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 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 quarter ending September 30:
1999 1998
--------------------------- ----------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- -------------------------------------------------------------------------------------------------------------------
Net income/shares $27,654 57,003 $(25,150) 56,970
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BASIC EPS $.49 $(.44)
Net income/shares $27,654 57,003 $(25,150) 56,970
Effect of Dilutive Securities
- -----------------------------
Stock options 500
Adjusted net income/shares $27,654 57,503 $(25,150) 56,970
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DILUTED EPS $.48 $(.44)
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6
For the nine months ending September 30:
1999 1998
--------------------------- ----------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- -------------------------------------------------------------------------------------------------------------------
Net income/shares $27,932 56,991 $703 56,947
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BASIC EPS $.49 $.01
Net income/shares $27,932 56,991 $703 56,947
Effect of Dilutive Securities
- -----------------------------
Stock options 391 427
Adjusted net income/shares $27,932 57,382 $703 57,374
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DILUTED EPS $.49 $.01
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(3) TRADING AND HEDGING ACTIVITIES
The Company, through its subsidiaries, from time to time, uses various
hedging arrangements in connection with anticipated sales of its crude oil and
natural gas production to minimize the impact of product price fluctuations.
Such arrangements include fixed price hedges, costless collars, swaps, options
and other contractual arrangements.
Hedging gains and losses, as applicable, related to the Company's oil and
gas production are recorded in oil and gas sales and royalties. The Company had
no natural gas or crude oil hedging contracts related to its production for the
three and nine months ended September 30, 1999 and 1998.
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 barrels per day and 2,000 barrels per day and have trigger prices of
$21.73 and $22.45, respectively, and both have floor prices of $17.00. 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 floor price. If a daily settlement price is $17.00 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 barrels 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, multiplied by the
number of days in the month, provided such average NYMEX price is also greater
than the $17.00 floor price. If the average NYMEX settlement price for the month
is $17.00 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 accounted for the swap component of these contracts as a
hedge, at swap prices ranging from $19.40 to $20.20, 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 $1,043,000 recorded in other income, for the
three months ended September 30, 1999.
In addition to the hedging arrangements pertaining to the Company's
production as described above, Noble Gas Marketing ("NGM"), a wholly owned
subsidiary of the Company, 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.
7
During the third quarter of 1999, NGM had hedging transactions with
broker-dealers that represented approximately 624,000 MMBTU's of gas per day.
Hedges for October 1999 through March 2001, which range from 9,000 MMBTU's to
698,000 MMBTU's of gas per day for future physical transactions, were not closed
at September 30, 1999. During the third quarter of 1998, NGM had hedging
transactions with broker-dealers that represented approximately 725,000 MMBTU's
of gas per day. For the nine months ended September 30, 1999, NGM had hedging
transactions that represented approximately 609,000 MMBTU's of gas per day,
compared to 720,000 MMBTU's of gas per day for the same period in 1998.
NGM records hedging gains or losses relating to fixed term sales as
gathering, marketing and processing revenues in the periods in which the related
hedged volumes are sold.
In December 1998 the Emerging Issues Task Force ("EITF") released their
consensus on EITF 98-10 "Accounting for Energy Trading and Risk Management
Activities." This statement requires that contracts for the purchase and sale of
energy commodities which are entered into for the purpose of speculating on
market movements or otherwise generating gains from market price differences be
recorded at their market value, as of the balance sheet date, with any
corresponding gains or losses recorded as income from operations. The effect of
adopting this statement was not material.
The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities", in June 1998. The Statement establishes
accounting and reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other contracts) 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. 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.
SFAS No. 133 cannot be applied retroactively. 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). In June 1999 the FASB issued SFAS No. 137 which deferred the effective
date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In addition,
SFAS No. 137 modified the dates derivative and hybrid contracts will be required
to be accounted for under SFAS No. 133 to December 31, 1998 (and at the
company's election before January 1, 1999). The Company plans to adopt this
statement as of January 1, 2001 and estimates there will be no material
financial impact as a result of adoption of SFAS No. 133.
(4) METHANOL PLANT
Samedan, through an unconsolidated subsidiary, Atlantic Methanol
Production Company (the "Project Company "), is participating, with a 45 percent
ownership interest and a 50 percent expense interest, in a joint venture with
CMS Energy Corporation to construct a methanol plant on Bioko Island in
Equatorial Guinea. The government of Equatorial Guinea has a 10 percent carried
interest in the Project Company. 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 120 MMCF of gas per day. The gas sold by Samedan to the Project
Company will be priced at $.25 per MMBTU.
On January 29, 1998, the Project Company awarded a contract to Raytheon
Engineers and Constructors to build the methanol plant. The turnkey plant
construction cost is $322.5 million, which is a $9 million increase over the
original contract due to job change orders, and the plant is being designed to
produce 2,500 metric tons of methanol per day, which equates to approximately
20,000 BBLS per day. The total cost of the project is estimated to be
approximately $400 million. The construction contract provides for liquidated
damages in the event the plant is not completed by March 2001. Current marketing
plans are to enter into long-term contracts with large methanol users in the
United States, Europe and South America.
The Company has funded its share of the construction costs related to the
methanol plant through capital contributions to the Project Company, using cash
flow from current operations. As of September 30, 1999, the Company had made
capital contributions to the Project Company totaling approximately $75.5
million. In November 1999, the Company participated in the formation of Atlantic
Methanol Capital Company ("AMCCO") to hold its ownership interest in the Project
Company. On November 10, 1999, the Company sold and contributed its indirect
ownership interest in the Project Company to AMCCO in exchange for approximately
$61.5 million and a
8
50% ownership interest in AMCCO. On that date, AMCCO completed the sale, in
separate private offerings, of two series of senior secured notes due 2004, each
series in the aggregate principal amount of $125 million. AMCCO used the
proceeds of one of these offerings to pay the purchase price for the Company's
interest in the Project Company and to make capital contributions in the
aggregate amount of approximately $63.5 million, net of transaction expenses, to
the subsidiary it acquired from the Company, for use in connection with the
construction of the plant.
One series of AMCCO's senior secured notes due 2004 is secured by a
pledge or assignment by AMCCO to the trustee under the indenture for the notes
of, among other things, (a) 60% of the indirect ownership interest in the
Project Company transferred by the Company to AMCCO and (b) a contractual right
to require a public offering of a series of mandatorily convertible preferred
stock of the Company, under certain circumstances, to generate proceeds
sufficient to repay such notes. The shares of the Company's preferred stock
subject to this arrangement are being held in trust until used for that purpose
or until the notes are otherwise repaid. The Company has also guaranteed AMCCO's
payment of interest on this series of notes.
The Company owns 50% of AMCCO and, accordingly, AMCCO and its
subsidiaries, including the Project Company, are treated as unconsolidated
subsidiaries of the Company and are recorded on the balance sheet as "Investment
in Unconsolidated Subsidiary". The Company is evaluating alternative methods for
funding the balance of its obligation related to the construction project.
(5) FINANCIAL INSTRUMENTS
On June 17, 1999, the Company entered into a new $100 million 364 day
credit agreement with certain commercial lending institutions. The agreement was
made to help fund the Company's methanol plant construction project in
Equatorial Guinea. 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.
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 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 decreased to $231.0 million in
the nine months ended September 30, 1999 from $298.0 million in the same period
of 1998. Cash and short-term investments increased from $19.1 million at
December 31, 1998 to $65.5 million at September 30, 1999. Such increases in cash
are primarily the result of an increase in oil and gas commodity prices during
the third quarter 1999.
Long-term debt decreased $74.9 million from $745.1 million at December
31, 1998 to $670.3 million at September 30, 1999. At year end 1998, the Company
had $300 million outstanding on its $300 million credit facility. During the
third quarter of 1999, $50 million was repaid under this credit facility.
9
On June 17, 1999, the Company entered into a new $100 million 364 day
credit agreement with certain commercial lending institutions. The agreement was
made to help fund the Company's methanol plant construction project in
Equatorial Guinea. There is no balance outstanding under this agreement, which
provides for interest on borrowings at a rate based upon a Eurodollar rate plus
37.5 to 87.5 basis points depending upon the percentage of utilization.
The Company has expended approximately $123.3 million of its $234.3
million 1999 capital budget through September 30, 1999. The Company expects to
fund its remaining 1999 capital budget from cash flows from operations. 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.
Samedan, through an unconsolidated subsidiary, Atlantic Methanol
Production Company (the "Project Company"), is participating, with a 45 percent
ownership interest and a 50 percent expense interest, in a joint venture with
CMS Energy Corporation to construct a methanol plant on Bioko Island in
Equatorial Guinea. The government of Equatorial Guinea has a 10 percent carried
interest in the Project Company. 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 120 MMCF of gas per day. The gas sold by Samedan to the Project
Company will be priced at $.25 per MMBTU.
On January 29, 1998, the Project Company awarded a contract to Raytheon
Engineers and Constructors to build the methanol plant. The turnkey plant
construction cost is $322.5 million, which is a $9 million increase over the
original contract due to job change orders, and the plant 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 provides for liquidated damages
in the event the plant is not completed by March, 2001. Current marketing plans
are to enter into long-term contracts with large methanol users in the United
States, Europe and South America.
On March 23, 1999, AMPCO Marketing LLC, an unconsolidated subsidiary in
which Samedan has a 50 percent ownership interest, entered into a contract with
Mitsui OSK Lines, Ltd., to construct and charter two 52,400 cubic meter cargo
tank capacity methanol transport vessels for the term of approximately 15 years.
These vessels will be used to transport methanol from the plant to markets.
The Company has funded its share of the construction costs related to the
methanol plant through capital contributions to the Project Company, using cash
flow from current operations. On November 10, 1999, the Company sold and
transferred its ownership interest in the Project Company to Atlantic Methanol
Capital Company ("AMCCO"), an unconsolidated subsidiary in which the Company
owns a 50% interest. AMCCO completed two securities offerings in November 1999
and contributed approximately $63.5 million of the proceeds, net of transaction
expenses, to the subsidiary it acquired from the Company, for use in connection
with the construction of the methanol plant. See Note 4 to the Financial
Statements. The Company is evaluating alternative methods for funding the
balance of its obligation related to the construction project, which may
include, for example, capital contributions by the Company to AMCCO, using cash
from operations or other sources, or financing transactions engaged in by AMCCO
or its subsidiaries, including the Project Company.
The Company's current ratio (current assets divided by current
liabilities) was 1.43 at September 30, 1999 compared with 1.35 at December 31,
1998.
The Company follows an entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $18.6 million
at September 30, 1999 and $19.1 million at December 31, 1998. Estimated gas
imbalance liabilities were $13.6 million at September 30, 1999 and $14.8 million
at December 31, 1998. These imbalances are valued at the amount which is
expected to be received or paid to settle the imbalances. 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 1999, the Company recorded net income of $27.7
million, or $.49 per share, compared to a net loss of $25.2 million, or $.44 per
share, in the third quarter of 1998. During the first nine months
10
of 1999, the Company recorded net income of $27.9 million, or $.49 per share,
compared to net income of $.7 million, or $.01 per share, in the first nine
months of 1998.
Gas sales for the Company, excluding third party sales by Noble Gas
Marketing ("NGM"), a wholly owned subsidiary of the Company, decreased four
percent and 23 percent, respectively, for the three months and nine months ended
September 30, 1999, as compared with the same periods in 1998. The decrease in
sales for the third quarter and year-to-date are primarily due to a 20 percent
and 19 percent decrease, respectively, in the average daily production, compared
to the same periods in 1998. The decreased production is offset by a 20 percent
increase in the average natural gas price for the three months ended September
30, 1999, as compared to the same period in 1998. The year-to-date gas price is
down four percent compared with the same period in 1998.
Oil sales for the Company, excluding third party sales by Noble Trading,
Inc. ("NTI"), a wholly owned subsidiary of the Company, increased 35 percent for
the three months and decreased three percent for the nine months ended September
30, 1999, as compared with the same periods in 1998. For the three months and
nine months ended September 30, 1999, the average oil price increased 71 percent
and 19 percent, respectively, as compared to the same periods in 1998. Average
daily production decreased 22 percent and 18 percent, respectively, for the
three months and nine months ended September 30, 1999 as compared with the same
periods in 1998.
NGM markets most 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 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 1999, revenues and expenses from combined NGM
and NTI third party sales totaled $90.1 million and $88.0 million, respectively,
for a gross margin of $2.1 million. In comparison, combined NGM and NTI third
party sales and expenses of $69.4 million and $66.1 million, respectively,
resulted in a gross margin of $3.3 million for the third quarter of 1998. For
the nine months ended September 30, 1999, combined NGM and NTI revenues and
expenses from third party sales totaled $244.0 million and $232.9 million,
respectively, for a gross margin of $11.1 million. In comparison, combined NGM
and NTI third party sales and expenses of $219.2 million and $210.6 million,
respectively, resulted in a gross margin of $8.6 million for the same period in
1998.
The Company, from time to time, uses various hedging arrangements in
connection with anticipated crude oil and natural gas sales of its own
production and third party production purchased and sold by NGM to minimize the
impact of product price fluctuations. Such arrangements include fixed price
hedges, costless collars and other contractual arrangements. Although these
hedging arrangements expose the Company to credit risk, the Company monitors the
creditworthiness of its counterparties, which generally are major institutions,
and believes that losses from nonperformance are unlikely to occur.
The Company had no natural gas or crude oil hedging contracts related to
its production for the three and nine months ended September 30, 1999 and 1998.
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 barrels per day and 2,000 barrels per day and have trigger prices of
$21.73 and $22.45, respectively, and both have floor prices of $17.00. 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 floor price. If a daily settlement price is $17.00 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 barrels 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, multiplied by the number of days in the month, provided such average
NYMEX price is also greater than the $17.00 floor price. If the average NYMEX
settlement price for the month is $17.00 or less, then neither party will
have any liability to the other for that month. If the average NYMEX
11
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 accounted for the swap component of these contracts as a
hedge, at swap prices ranging from $19.40 to $20.20, 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 $1,043,000 recorded in other income, for the
three months ended September 30, 1999.
In December 1998 the Emerging Issues Task Force ("EITF") released their
consensus on EITF 98-10 "Accounting for Energy Trading and Risk Management
Activities." This statement requires that contracts for the purchase and sale of
energy commodities which are entered into for the purpose of speculating on
market movements or otherwise generating gains from market price differences be
recorded at their market value, as of the balance sheet date, with any
corresponding gains or losses recorded as income from operations. The effect of
adopting this statement was not material.
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.
NGM, from time to time, employs hedging arrangements in connection with
its purchases and sales of production. While most of NGM's purchases are made
for an index-based price, NGM's customers often require prices that are either
fixed or related to NYMEX. In order to establish a fixed margin and mitigate the
risk of price volatility, NGM may convert a fixed or NYMEX sale to an
index-based sales price (such as by purchasing an index-based futures contract
obligating NGM for delivery of production). Due to the size of such transactions
and certain restraints imposed by contract and by Company guidelines, as of
September 30, 1999 the Company had no material market risk exposure from NGM's
hedging activity. During the third quarter of 1999, NGM had hedging transactions
with broker-dealers that represented approximately 624,000 MMBTU's of gas per
day. Hedges for October 1999 through March 2001, which range from 9,000 MMBTU's
to 698,000 MMBTU's of gas per day for future physical transactions, were not
closed at September 30, 1999. During the third quarter of 1998, NGM had hedging
transactions with broker-dealers that represented approximately 725,000 MMBTU's
of gas per day. For the nine months ended September 30, 1999, NGM had hedging
transactions that represented approximately 609,000 MMBTU's of gas per day,
compared to 720,000 MMBTU's of gas per day for the same period in 1998.
Certain selected oil and gas operating statistics follow:
For the three months For the nine months
ended September 30, ended September 30,
------------------------- --------------------------
1999 1998 1999 1998
------------ ------------ ----------- -------------
Oil revenues (in thousands).............. $ 50,765 $ 37,704 $ 119,374 $ 122,869
Average daily oil production - BBLS...... 29,308 37,382 30,890 37,866
Average oil price per BBL................ $ 19.16 $ 11.21 $ 14.45 $ 12.19
Gas revenue (in thousands)............... $ 97,727 $ 102,009 $ 260,694 $ 337,550
Average daily gas production - MCF....... 428,051 534,433 462,304 568,414
Average gas price per MCF................ $ 2.54 $ 2.11 $ 2.13 $ 2.22
BBLS - BARRELS
MCF - THOUSAND CUBIC FEET
Oil and gas exploration expense decreased $27.4 million and $50.9
million, respectively, for the three months and nine months ended September 30,
1999, as compared to the same periods in 1998. These decreases are primarily
attributable to decreases of $9.9 million and $12.9 million, respectively, in
abandoned assets expense, plus decreases of $19.4 million and $33.4 million,
respectively, in dry hole expense, compared with the same periods in 1998. Also,
seismic expense decreased $6.9 million, for the nine months ended September 30,
1999, compared to the same period in 1998.
12
Oil and gas operations expense decreased $9.3 million and $24.0 million,
respectively, for the three months and nine months ended September 30, 1999
compared to the same periods in 1998. These decreases are due primarily to
decreased lease operations expenses of $8.6 million and $20.9 million,
respectively, for the three months and nine months ended September 30, 1999,
compared to the same periods in 1998.
Depreciation, depletion and amortization ("DD&A") expense decreased 30
percent and 19 percent, respectively, for the three months and nine months ended
September 30, 1999 compared to the same periods in 1998. 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 $6.29 for the first nine months of 1999, as compared to
$6.32 for the same period of 1998. The unit rate of DD&A for the three months
ended September 30, 1999 was $6.34 compared to $7.18 for the same period in
1998. 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.
FUTURE TRENDS
Samedan Oil Corporation ("Samedan"), a wholly owned subsidiary of the
Company, has from time to time settled various claims against parties which
failed to fulfill their contractual obligation to Samedan to purchase gas at
fixed prices greater than market or pursuant to take-or-pay provisions. The
Company's policy, which is consistent with general industry practice, is that
amounts received in such settlements ("settlement payments") do not represent
payment for gas produced and, therefore, are not subject to royalty payments.
Property owners, including governmental authorities and private parties, have in
recent years asserted claims against Samedan and other oil and gas companies for
royalties on settlement payments.
Samedan may be the subject of future legal actions by property owners
claiming royalties on other settlement payments received by Samedan. There can
be no assurance that Samedan will prevail in any such action. The Company is
unable to estimate the possible amount of loss, if any, associated with this
contingency.
Management believes 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
domestic oil and gas industry. Due to the volatility of oil and gas prices, the
Company, from time to time, uses hedging and plans to do so in the future as a
means of controlling its exposure to price changes. The Company cannot predict
the extent to which its revenues will be affected by inflation, government
regulation or changing prices.
YEAR 2000 ISSUE
The Year 2000 issue is the result of computer programs being written
using two digits rather than four to define the applicable year. Computer
equipment and 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 could 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 has undertaken various initiatives intended to ensure that
its computer equipment and software will function properly with respect to dates
in the year 2000 and thereafter. For this purpose, the term "computer equipment
and software" includes systems that are commonly thought of as information
technology ("IT") systems, including accounting, data processing, telephone/PBX
systems, and other miscellaneous systems, as well as systems that are not
commonly thought of as IT systems, such as field operations equipment, alarm
systems, sprinkler systems, fax machines, or other miscellaneous systems. Both
IT and non-IT systems may contain imbedded technology, which complicates the
Company's Year 2000 identification, assessment, remediation, and testing
efforts. In addition, in the ordinary course of replacing computer equipment and
software, the Company attempts to obtain replacements that it believes are Year
2000 compliant. Utilizing internal resources to identify and assess needed Year
2000 remediation, the Company currently anticipates that its Year 2000
identification, assessment, remediation, and testing efforts, which began in
January 1998, will be completed by December 31, 1999, and that such efforts will
be completed prior to any currently anticipated impact on its computer equipment
and software. The Company estimates that as of October 31, 1999, it had
completed approximately 99 percent of the initiatives that it believes will be
necessary to fully address potential Year 2000 issues relating to its computer
equipment and
13
software. The projects comprising the remaining one percent of the initiatives
are in process and expected to be completed by December 31, 1999.
Percent
Year 2000 Initiative Time Frame Complete
- -----------------------------------------------------------------------------------------------------------------------
Identification and assessment of IT systems March 31, 1999 100%
(Company and subsidiaries)
Identification and assessment of critical non-IT systems October 31, 1999 100%
(Company and subsidiaries)
Remediation and testing of IT and non-IT systems of December 31, 1998 100%
subsidiaries other than Samedan and subsidiaries
Remediation and testing of IT and non-IT systems of September 30, 1999 100%
Samedan and subsidiaries
Remediation and testing of Company's central IT June 30, 1999 100%
and non-IT systems
Replacement and testing of third party software December 31, 1999 95%
Identification and assessment of field equipment used in
oil and gas producing operations October 31, 1999 100%
Remediation and testing of field equipment October 31, 1999 100%
The Company mailed letters in May 1999 to its significant vendors and
service providers and has verbally communicated with many strategic customers to
determine the extent to which interfaces with such entities are vulnerable to
Year 2000 issues and whether the products and services purchased from or by such
entities are Year 2000 compliant. The Company estimates that as of October 31,
1999, it had received 70 percent of the Year 2000 attestation certificates from
vendors, service providers and strategic customers with approximately 99 percent
positive responses. A second solicitation for Year 2000 conformity verification
was mailed during August 1999.
The Company is funding its Year 2000 efforts primarily with internal
resources and does not anticipate making any expenditures in connection
therewith except for the purchase of third party software that it otherwise
would not have purchased or would have purchased at a later date. Although the
Company does not separately track its internal costs related to Year 2000
efforts, which include compensation of employees working on Year 2000 projects,
it believes that such costs will not exceed $80,000, of which approximately
$75,000 had been incurred as of September 30, 1999. The Company estimates that
these internal and external costs will represent less than five percent of total
IT-related costs for 1998 and 1999 and that none of the Company's IT initiatives
that are not related to the Year 2000 issue will be materially delayed or
impacted by Year 2000 efforts.
The Company presently believes that the Year 2000 issue will not pose
significant operational problems for the Company. However, if all Year 2000
issues are not properly identified, or assessment, remediation, and testing are
not effected timely, there can be no assurance that the Year 2000 issue will not
materially adversely impact the Company's results of operations or adversely
affect the Company's relationships with customers, vendors, or others.
Additionally, there can be no assurance that the Year 2000 issues of other
entities will not have a material adverse impact on the Company's systems or
results of operations.
The costs of the Company's Year 2000 identification, assessment,
remediation, and testing efforts and the dates on which the Company believes it
will complete such efforts are based upon management's estimates, which were
derived using numerous assumptions regarding future events, including the
continued availability of certain resources, third-party remediation plans and
other factors. There can be no assurance that these estimates will prove to be
accurate, and actual results could differ materially from those currently
anticipated. Specific factors that could cause such material differences
include, but are not limited to, the availability and cost of personnel trained
in Year 2000 issues, the ability to identify, assess, remediate, and test all
relevant computer codes and imbedded technology, and similar uncertainties. In
addition, variability of definitions of "compliance with Year 2000" may lead to
claims on the Company, the impact of which is not currently estimable. No
assurance can be given that the aggregate cost of defending and resolving such
claims, if any, will not materially adversely affect the Company's results of
operations.
14
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. During
the first nine months of 1999, the Company had no oil or gas hedging
transactions for its production.
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 barrels per day and 2,000 barrels per day and have trigger prices of
$21.73 and $22.45, respectively, and both have floor prices of $17.00. 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 floor price. If a daily settlement price is $17.00 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 barrels 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, multiplied by the
number of days in the month, provided such average NYMEX price is also greater
than the $17.00 floor price. If the average NYMEX settlement price for the month
is $17.00 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 accounted for the swap component of these contracts as a
hedge, at swap prices ranging from $19.40 to $20.20, 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 $1,043,000 recorded in other income, for the
three months ended September 30, 1999.
For each one-dollar closing price for NYMEX crude above $21.73, if
sustained for the entire year, the Company would pay approximately $1.8 million
annually to the counterparty to the contract pertaining to 5,000 barrels per
day, and for each one-dollar closing price for NYMEX crude above $22.45, if
sustained for the entire year, the Company would pay approximately $732,000
annually to the counterparty of the other swap contract.
NGM, from time to time, employs hedging arrangements in connection with
its purchases and sales of production. While most of NGM's purchases are made
for an index-based price, NGM's customers often require prices that are either
fixed or related to NYMEX. In order to establish a fixed margin and mitigate the
risk of price volatility, NGM may convert a fixed or NYMEX sale to an
index-based sales price (such as by purchasing an index-based futures contract
obligating NGM for delivery of production). Due to the size of such transactions
and certain restraints imposed by contract and by Company guidelines, as of
September 30, 1999 the Company had no material market risk exposure from NGM's
hedging activity.
The Company has a $300 million credit agreement (see 1998 Annual Report -
Note 3 - Debt, to the Consolidated Financial Statements) which exposes the
Company to the risk of earnings or cash flow loss due to changes in market
interest rates. At September 30, 1999, there was $225 million outstanding under
the credit facility with a maturity date of December 24, 2002. The interest rate
charged is based upon a Eurodollar rate plus 25 to 35 basis points depending
upon the ratio of debt to book capital (defined as Noble's debt plus its
equity), which was 50.2 percent at September 30, 1999, thereby resulting in an
interest rate of 6.1 percent. On June 17, 1999, the Company entered into a $100
million 364 day credit agreement. There is no balance outstanding under this
agreement which provides for interest on borrowings as a rate based upon the
Eurodollar rate plus 37.5 to 87.5 basis
15
points depending upon the percentage of utilization. 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.
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.
16
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 and is incorporated herein by
reference.
(b) The Company did not file any reports on Form 8-K during the three months
ended September 30, 1999.
17
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 15, 1999 /s/ JAMES L. McELVANY
-------------------------- -------------------------------------
JAMES L. McELVANY
Vice President-Finance and Treasurer
(Principal Financial Officer
and Authorized Signatory)
18
INDEX TO EXHIBITS
Sequentially
Exhibit Numbered
Number Exhibit Page
- ------------ ------------------------------- --------------------
27.1 Financial Data Schedule