SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-Q
(Mark One)
[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 No. 0-17267
MALLON RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
COLORADO 84-1095959
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
999 18th Street, Suite 1700
Denver, Colorado 80202
(Address of principal executive offices)
(303) 293-2333
(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 such shorter period of time registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES [X] NO [ ]
As of October 31, 2000, 10,541,643 shares of registrant's common stock, par
value $0.01 per share, were outstanding.
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1 -- Financial Statements
MALLON RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands)
<TABLE>
<CAPTION>
ASSETS
September 30, December 31,
2000 1999
(Unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 1,419 $ 1,230
Accounts receivable:
Oil and gas sales 2,192 1,315
Joint interest participants, net of allowance of $43
and $43, respectively 356 559
Related parties -- 53
Other 2 153
Inventories 219 200
Other 93 83
Total current assets 4,281 3,593
Property and equipment:
Oil and gas properties, full cost method 116,341 103,315
Natural gas processing plant 8,485 8,341
Other equipment 1,104 1,084
125,930 112,740
Less accumulated depreciation, depletion and amortization (57,110) (53,428)
68,820 59,312
Notes receivable-related parties 7 84
Debt issuance costs 1,554 1,885
Other, net 438 552
Total Assets $ 75,100 $ 65,426
======== =========
</TABLE>
(Continued on following page)
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
MALLON RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS - Continued
(In thousands, except share amounts)
<TABLE>
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, December 31,
2000 1999
(Unaudited)
<S> <C> <C>
Current liabilities:
Trade accounts payable $ 3,449 $ 4,883
Undistributed revenue 1,287 934
Drilling advances 24 --
Accrued taxes and expenses 101 55
Current portion of long-term debt 440 399
Convertible note payable - related party 552 --
Total current liabilities 5,853 6,271
Long-term debt, net of unamortized discount of $2,639 and $3,146,
respectively 49,543 34,874
Total liabilities 55,396 41,145
Commitments and contingencies (Note 6)
Series B Mandatorily Redeemable Convertible Preferred Stock,
$0.01 par value, 500,000 shares authorized, 80,000 and 135,200
shares issued and outstanding, respectively, liquidation preference
and mandatory redemption of $800 and $1,352, respectively 796 1,341
Mandatorily Redeemable Common Stock, $0.01 par value, 420,000
shares authorized, issued and outstanding, mandatory
redemption of $5,250 3,752 3,450
Shareholders' equity:
Common Stock, $0.01 par value, 25,000,000
shares authorized; 7,461,643 and 7,413,300
shares issued and outstanding, respectively 75 74
Additional paid in capital 77,857 77,013
Accumulated deficit (59,855) (54,914)
Notes receivable from related party shareholders (2,823) (2,683)
Accounts receivable from shareholders (98) --
Total shareholders' equity 15,156 19,490
Total Liabilities and Shareholders' Equity $ 75,100 $ 65,426
======== =========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
MALLON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
<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>
Revenues:
Oil and gas sales $ 4,730 $ 3,519 $ 11,830 $ 9,452
Interest and other 78 41 211 86
4,808 3,560 12,041 9,538
Costs and expenses:
Oil and gas production 1,913 1,234 5,119 3,754
Depreciation, depletion and amortization 1,604 1,132 4,323 3,489
General and administrative 724 500 2,770 1,782
Interest and other 1,671 741 4,460 1,903
5,912 3,607 16,672 10,928
Loss before extraordinary item (1,104) (47) (4,631) (1,390)
Extraordinary loss on early retirement of debt -- (105) -- (105)
Net loss (1,104) (152) (4,631) (1,495)
Dividends on preferred stock and accretion (17) (30) (67) (90)
Accretion of mandatorily redeemable common stock (105) -- (304) --
Net loss attributable to common shareholders $ (1,226) $ (182) $ (5,002) $ (1,585)
======== ======== ======== ========
Basic loss per share:
Loss attributable to common shareholders before
extraordinary item $ (0.16) $ (0.01) $ (0.64) $ (0.21)
Extraordinary loss -- (0.01) -- (0.01)
Net loss attributable to common shareholders $ (0.16) $ (0.02) $ (0.64) $ (0.22)
======== ======= ======= ========
Basic weighted average common shares outstanding 7,881 7,173 7,854 7,075
======== ======= ======= =========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
MALLON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
<TABLE>
<CAPTION>
For the Nine Months
Ended September 30,
2000 1999
<S> <C> <C>
Cash flows from operating activities:
Net loss $ (4,631) $ (1,495)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization 4,323 3,489
Amortization of discount on long-term debt and installment obligation 507 34
Accrued interest expense added to long-term debt 3,325 181
Accrued interest income added to notes receivable from related
party shareholders (140) (15)
Extraordinary loss -- 105
Stock compensation expense 452 68
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable (250) 26
Inventory and other assets (193) (113)
Increase (decrease) in:
Trade accounts payable and undistributed revenue (1,082) (2,636)
Accrued taxes and expenses 47 (6)
Drilling advances 24 (1)
Deferred revenue -- (682)
Net cash provided by (used in) operating activities 2,382 (1,045)
Cash flows from investing activities:
Additions to property and equipment (13,156) (5,213)
Decrease in notes receivable-related parties 77 6
Net cash used in investing activities (13,079) (5,207)
Cash flows from financing activities:
Proceeds from long-term debt 11,173 42,187
Payments of long-term debt (296) (34,291)
Debt issue costs -- (1,985)
Payment of preferred dividends (61) (81)
Proceeds from stock option and warrants exercises 68 55
Other 2 --
Net cash provided by financing activities 10,886 5,885
Net increase (decrease) in cash and cash equivalents 189 (367)
Cash and cash equivalents, beginning of period 1,230 1,733
Cash and cash equivalents, end of period $ 1,419 $ 1,366
======== ========
Supplemental cash flow information:
Cash paid for interest $ 592 $ 1,718
======== ========
Non-cash transactions:
Issuance of common stock in exchange for oil and gas properties
purchased from officers and directors $ 119 $ --
======== ========
Issuance of common stock in exchange for accounts receivable from
shareholder $ 98 $ --
======== ========
Issuance of common stock in exchange for notes receivable from
officers and directors $ -- $ 2,621
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
MALLON RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
___________
NOTE 1. GENERAL
Mallon Resources Corporation (the "Company") engages in oil and gas
exploration and production through its wholly-owned subsidiary, Mallon Oil
Company ("Mallon Oil"), whose oil and gas operations are conducted primarily
in the State of New Mexico. The Company operates its business and reports its
operations as one business segment. All significant inter-company balances and
transactions have been eliminated from the consolidated financial statements.
These unaudited consolidated financial statements have been prepared in
accordance with generally accepted accounting principles for interim financial
information and with the instructions to Form 10-Q and Article 10 of
Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by generally accepted accounting principles for complete
financial statements. In the opinion of management, such interim statements
reflect all adjustments (consisting of normal recurring adjustments) necessary
to present fairly the financial position and the results of operations and
cash flows for the interim periods presented. The results of operations for
these interim periods are not necessarily indicative of the results to be
expected for the full year. These interim statements should be read in
conjunction with the consolidated financial statements and notes thereto
included in the Company's 1999 Form 10-K.
Certain prior year amounts in the consolidated financial statements have
been reclassified to conform to the presentation used in 2000.
NOTE 2. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
<S> <C> <C>
Note payable to Aquila Energy Capital Corporation,
due 2003 $47,389 $32,890
Less unamortized discount (effective rate of 13.8%) (2,639) (3,146)
44,750 29,744
Lease obligation to Universal Compression, Inc. 5,106 5,390
8.5% unsecured note payable to Bank One, Colorado,
N.A., due 2002 127 139
49,983 35,273
Less current portion (440) (399)
Total $49,543 $34,874
======= =======
</TABLE>
In September 1999, the Company established a credit agreement (the "Aquila
Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"). The
initial amount available under the agreement is $45.7 million. The amount
available may be increased to as much as $60.0 million as new reserves are
added through the Company's planned development drilling program. At
September 30, 2000, the Company had drawn $47.4 million, including accrued
interest, under the Aquila Credit Agreement.
The borrowing base is subject to redetermination annually on or before
April 30. Aquila delayed its April 2000 redetermination until certain wells
drilled by the Company during the first four months of 2000 were completed and
their reserves evaluated. The Company had delayed its completion of the wells
pending receipt of approval from the Jicarilla Apache Tribe to commingle gas
from different zones. The approval was received in April 2000. In July 2000,
Aquila committed to increase the amount available under the agreement by $6.7
million, making the total available $52.4 million. In connection with the
increase in the borrowing base, Mallon agreed to issue to Aquila an additional
70,000 shares of common stock. Mallon had previously issued to Aquila 420,000
shares of common stock in September 1999 in connection with the establishment
of the credit facility. Aquila has the one-time right to require Mallon to
purchase all 490,000 shares from Aquila at $12.50 per share during the 30-day
period beginning September 9, 2003.
<PAGE>
Principal payments on the four-year loan are based on the Company's cash
flow from operations, as defined, less advances for the Company's development
program. As of September 30, 2000, the advances exceeded cash flow from
operations and the Company had not made any principal payments.
During the nine months ended September 30, 2000, the Company repaid
$284,000 of lease obligation to Universal Compression and $12,000 of unsecured
note payable to Bank One.
NOTE 3. EARNINGS (LOSS) PER SHARE
Under the provisions of Statement of Financial Accounting Standards
("SFAS") No. 128, basic earnings per share is computed by dividing income
available to common shareholders by the weighted average number of common
shares outstanding for the period. Diluted earnings per share reflects the
potential dilution that could occur if the Company's outstanding stock options
and warrants were exercised (calculated using the treasury stock method) or if
the Company's Series B Mandatorily Redeemable Convertible Preferred Stock were
converted to common stock.
The consolidated statements of operations for the nine months ended
September 30, 2000 and 1999 reflect only basic earnings per share because the
Company was in a loss position for all periods presented and all common stock
equivalents are anti-dilutive.
NOTE 4. RECENT PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 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. SFAS No. 133 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 must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting. SFAS No. 133 is effective for all fiscal quarters of fiscal
years beginning after June 15, 2000, but early adoption is permitted. SFAS No.
133 cannot be applied retroactively. The Company has not yet quantified the
impact of adopting SFAS No. 133 on its financial statements and has not
determined the timing or method of adoption of SFAS No. 133. However, SFAS No.
133 could increase volatility in earnings and other comprehensive income.
In March 2000, the FASB issued Interpretation No. 44, "Accounting for
Certain Transactions involving Stock Compensation." This Interpretation
clarifies (a) the definition of employee for purposes of applying APB Opinion
No. 25, (b) the criteria for determining whether a plan qualifies as a
noncompensatory plan, (c) the accounting consequence of various modifications
to the terms of a previously fixed stock option or award, and (d) the
accounting for an exchange of stock compensation awards in a business
combination. This Interpretation is effective July 1, 2000, but certain
conclusions in this Interpretation cover specific events that occur after
either December 15, 1998, or January 12, 2000. To the extent that this
Interpretation covers events occurring during the period after December 15,
1998, or January 12, 2000, but before the effective date of July 1, 2000, the
effects of applying this Interpretation are recognized on a prospective basis
from July 1, 2000. Adoption of this Interpretation did not have a material
impact on the Company's financial position or results of operations.
NOTE 5. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK
In April 2000, the Company redeemed 55,200 shares of its Series B
Mandatorily Redeemable Convertible Preferred Stock at the mandatory redemption
price of $10 per share by issuing a convertible promissory note for $552,000
to the Series B holder, a company in which one of Mallon's directors is also a
director. Interest on the note accrues at 11.3% and is payable quarterly
beginning on June 30, 2000. The note and all unpaid accrued interest is
payable in full on April 15, 2001. The holder of the note may at any time
cause any part of the unpaid principal and accrued interest due to be
converted into shares of the Company's common stock using the same conversion
price applicable to the remaining Series B Preferred Stock shares, currently
$9.18. After this transaction, 80,000 shares of Series B Preferred Stock
remain outstanding, all of which the Company is required to redeem in April
2001.
<PAGE>
NOTE 6. COMMITMENTS AND CONTINGENCIES
In April 1999, Mallon Oil filed a civil action to collect approximately
$265,000 of unpaid joint-interest billings from Wadi Petroleum, Inc. relating
to certain oil and gas properties operated by the Company. In April 2000, the
Company settled the matter for a payment to the Company of $150,000 and the
assignment to the Company of certain oil and gas properties.
NOTE 7. OIL AND GAS PROPERTIES
In April 2000, the Government of Costa Rica awarded the Company a
concession to explore for oil and natural gas on approximately 2.3 million
acres in the northeast quadrant of Costa Rica. The concession acreage is
contained in six large contiguous onshore acreage blocks. The Company has
completed an environmental assessment of its proposed operations, and is
currently in the process of negotiating final concession contracts. The work
program will require the expenditure of $8.8 million (including the drilling
of six wells) over a three-year period, with a possible extension of three
more years.
In June 2000, effective January 1, 2000, the Company purchased additional
working interests in certain wells from two of the Company's officers and one
of its directors in exchange for forgiveness of $56,000 of joint interest
participants accounts receivable, 14,800 shares of common stock valued at
$119,000 and $3,000 in cash.
NOTE 8. SUBSEQUENT EVENTS
In October 2000, the Company issued 2,660,000 shares of its common stock
in a public offering at a price of $6.25 per share. The Company received net
proceeds after commissions and other costs of approximately $15.2 million,
which will be used primarily to finance the Company's oil and gas drilling
activities.
In October 2000, the Company repaid the convertible promissory note of
$552,000, discussed in Note 5 above, in full.
As discussed in Note 10 of the Company's 1999 Form 10-K, certain Company
officers borrowed funds from the Company to exercise options to purchase
381,360 shares of common stock at an exercise price of $6.88. The notes bear
interest at 7%, which along with the principal, was due in August 2002. In
October 2000, the Company extended the due date of the notes receivable and
accrued interest from August 2002 to August 2004.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion is intended to assist in understanding our
historical consolidated financial position at September 30, 2000 and
December 31, 1999, results of operations for the three and nine months ended
September 30, 2000 and 1999 and cash flows for the nine months ended
September 30, 2000. Our Consolidated Financial Statements and notes thereto
contain detailed information that should be referred to in conjunction with
the following discussion.
Overview
Our revenues, profitability and future rate of growth will be
substantially dependent upon our drilling success in the San Juan and Delaware
Basins, and prevailing prices for oil and gas, which are in turn dependent
upon numerous factors that are beyond our control, such as economic, political
and regulatory developments and competition from other sources of energy. The
energy markets have historically been volatile, and oil and gas prices can be
expected to continue to be subject to wide fluctuations in the future. A
substantial or extended decline in oil or gas prices could have a material
adverse effect on our financial position, results of operations and access to
capital, as well as the quantities of oil and gas reserves that we may
economically produce.
Liquidity and Capital Resources
Our operations are capital intensive. Historically, our principal sources
of capital have been cash flow from operations, long and short-term debt
financing arrangements, and proceeds from sales of common and preferred stock.
Our principal uses of capital have been for the acquisition, exploration and
development of oil and gas properties and construction of related facilities.
During the first nine months of 2000, our capitalized costs incurred in
oil and gas producing activities were $13.2 million. Our 2000 capital
expenditure budget is currently $22.9 million. During the first nine months
of 2000, we drilled 20 wells and recompleted five wells of the total 43 wells
we plan to drill or recomplete during the year. Seventeen wells drilled were
completed and put on production, two were completing and the remaining well
was a dry hole. We expect to fund our capital requirements for the next twelve
months out of cash flow from operations, borrowings, and proceeds from our
equity offering as described below.
Although we drilled 14 wells during first quarter 2000, we delayed
completing 13 of them pending approval of commingling by the Jicarilla Apache
Tribe, which owns the land covering most of our acreage in our East Blanco
Field. The approval was granted in April 2000 and we have completed them.
Most of our wells in the East Blanco Field contain three or more pay zones at
depths ranging from 1,200 to 4,000 feet. Prior to the approval of our request
to commingle, wells in the field were limited to producing from no more than
two zones at a time. By commingling the gas production from multiple zones,
we should be able to increase the value of our reserves.
Subsequent to September 30, 2000, we drilled or recompleted three wells
and placed them on production.
In September 1999, we established a credit agreement with Aquila Energy
Capital Corporation (the "Aquila Credit Agreement"). The initial amount
available under the agreement was $45.7 million, which may be increased to as
much as $60.0 million as new reserves are added through our development
drilling program. As of November 7, 2000, we had drawn $49.2 million,
including accrued interest, under the Aquila Credit Agreement. The borrowing
base is subject to redetermination annually on or before April 30. Aquila
delayed its April 2000 redetermination until certain wells we drilled during
the first four months of 2000 were completed and their reserves evaluated. We
had delayed completion of the wells pending receipt of approval from the
Jicarilla Apache Tribe to commingle gas from different zones as discussed
above. In July 2000, Aquila committed to increase the amount available under
the Aquila Credit Agreement by $6.7 million, making the total available $52.4
million. Our planned capital expenditures during 2000 anticipate that this
increase will be available as our drilling program proceeds. Principal
payments on the four-year loan are based on our cash flow from operations, as
defined in the Aquila Credit Agreement, less advances for our drilling. As of
September 30, 2000, the advances exceeded cash flow from operations and we had
not made any principal payments. Because we expect drilling expenditures to
equal or surpass defined cash flow from operations, we do not anticipate
making any principal payments for the next twelve months.
<PAGE>
The Aquila Credit Agreement is secured by liens on substantially all of
our oil and gas properties. Interest on the Aquila Credit Agreement accrues at
prime plus 2% and will be added to the loan balance. The outstanding loan
balance is due in full on September 9, 2003. As part of the transaction, we
also entered into a four year agency agreement with Aquila under which we pay
a marketing fee equal to 1% of the net proceeds, as defined in the Aquila
Credit Agreement, from the sale of all of our oil and gas production. In
addition, we also issued to Aquila 420,000 shares of common stock. In
conjunction with Aquila's agreement to increase in the borrowing base under
the Aquila Credit Agreement in July 2000, we agreed to issue to Aquila an
additional 70,000 shares of common stock. Aquila will also have a one-time
right to require us to purchase 490,000 of our common shares from Aquila at
$12.50 per share during the 30-day period beginning September 9, 2003.
In September 1999 we also entered into a five-year, $5.5 million master
rental contract with Universal Compression, Inc. to refinance our East Blanco
gas sweetening plant. The proceeds from that financing were used to repay a
term loan from Bank One, Texas, N.A. that was secured by the plant. The
master rental contract bears interest at an imputed rate of 12.8%. We made
principal payments totaling $284,000 to Universal Compression during the first
nine months of 2000.
In July 1998, we negotiated an unsecured term loan for up to $205,000 with
Bank One, Colorado, N.A. to finance the purchase of land and a building for
our field office. We drew $155,000 on this loan during 1998. Principal and
interest (at 8.5%) is payable quarterly beginning October 1, 1998. We repaid
$12,000 of this loan during the first nine months of 2000. In March 1999, the
due date of the loan was extended from July 1999 to April 2002.
In April 2000, the Government of Costa Rica awarded us a concession to
explore for oil and natural gas on approximately 2.3 million acres in the
northeast quadrant of Costa Rica. The concession acreage is contained in six
large contiguous onshore acreage blocks. We have completed an environmental
assessment of our proposed operations and are currently in the process of
negotiating final concession contracts. The work program will require the
expenditure of $8.8 million (including the drilling of six wells) over a
three-year period, with a possible extension of three more years.
In October 2000, we issued 2,660,000 shares of our common stock in a
public offering at a price of $6.25 per share. We received net proceeds after
commissions and other costs of approximately $15.2 million, which will be used
primarily to finance our oil and gas drilling activities.
Under the mandatory redemption feature of our Series B Mandatorily
Redeemable Convertible Preferred Stock we were required to redeem 55,200
shares in April 2000, and will be required to redeem the remaining 80,000
shares in April 2001. The mandatory redemption price is $10.00 per share, plus
any accrued but unpaid dividends. We made the April 2000 redemption by issuing
a convertible promissory note for $552,000. Interest on the note accrued at
11.3% and was payable quarterly beginning on June 30, 2000. The note and all
unpaid accrued interest was payable in full on April 15, 2001. In October
2000, we paid the convertible promissory note, in full.
<PAGE>
Results of Operations
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
2000 1999 2000 1999
(In thousands, except per unit data)
<S> <C> <C> <C> <C>
Results of Operations from Oil and Gas Producing Activities:
Oil and gas sales $4,730 $3,519 $11,830 $9,452
Production tax and marketing expense 1,022 474 2,153 1,330
Lease operating expense 891 760 2,966 2,424
Depletion 1,408 1,006 3,719 3,158
Depreciation 69 68 191 203
Net Production:
Oil (MBbl) 42 39 126 130
Natural gas (MMcf) 1,696 1,388 4,358 4,377
Total (MMcfe) 1,948 1,622 5,114 5,157
Average Sales Price Realized: (1)
Oil (per Bbl) $24.17 $20.18 $24.09 $15.60
Natural gas (per Mcf) 2.19 1.97 2.02 1.70
Per Mcfe 2.43 2.17 2.31 1.83
Average Cost Data (per Mcfe):
Production tax and marketing expense $ 0.52 $ 0.29 $ 0.42 $ 0.26
Lease operating expense 0.46 0.47 0.58 0.47
Depletion 0.72 0.62 0.73 0.61
Depreciation 0.04 0.04 0.04 0.04
_________________
1) Includes effects of hedging.
</TABLE>
Three and Nine Months Ended September 30, 2000 Compared to September 30, 1999
Revenues. Total revenues increased 35% to $4,808,000 for the three months
ended September 30, 2000 from $3,560,000 for the three months ended
September 30, 1999 and increased 26% to $12,041,000 for the nine months ended
September 30, 2000 from $9,538,000 for the nine months ended September 30,
1999. Oil and gas sales increased 34% to $4,730,000 for the 2000 quarter from
$3,519,000 for the 1999 quarter due primarily to higher oil and gas production
and higher oil and gas prices in the 2000 quarter. Oil and gas sales
increased 25% to $11,830,000 for the nine months ended September 30, 2000 from
$9,452,000 for the nine months ended September 30, 1999, due to higher oil and
gas prices in the 2000 period. Average oil prices realized per barrel
increased 20% to $24.17 in the fiscal 2000 quarter, from $20.18 in the fiscal
1999 quarter; and average gas prices realized per Mcf increased 11% to $2.19
in the 2000 quarter from $1.97 in the 1999 quarter. Average oil prices
realized per barrel increased 54% to $24.09 for the nine months ended
September 30, 2000, from $15.60 for the comparable 1999 period, and average
gas prices realized per Mcf increased 19% to $2.02 in the 2000 period from
$1.70 for the nine months ended September 30, 1999. Oil production increased
8% to 42,000 barrels in the 2000 quarter from 39,000 barrels in the 1999
quarter and gas production increased 22% to 1,696,000 Mcf in the 2000 quarter
from 1,388,000 Mcf in the 1999 quarter. Oil production decreased 3% to
126,000 barrels for the nine months ended September 30, 2000 from 130,000
barrels for the nine months ended September 30, 1999; and gas production
remained about the same at 4,358,000 Mcf for the nine months ended
September 30, 2000 compared to 4,377,000 Mcf for the same period a year ago.
The production increases in the 2000 quarter are due to our drilling and
recompletion program in 2000. Our oil production for the nine months ended
September 30, 2000 is slightly lower compared to the same period a year ago
due to natural declines. We have been focusing primarily on drilling gas
wells. The gas production for the nine months ended September 30, 2000
remained relatively unchanged from the same period a year ago because of a
planned delay during the 2000 period in new well completions pending approval
of commingling, as discussed above. Many of the wells drilled in first
quarter 2000 were placed on production in the third quarter 2000.
<PAGE>
Oil and Gas Production Expenses. Oil and gas production expenses,
including production tax and marketing expenses, increased 55% to $1,913,000
for the three months ended September 30, 2000 from $1,234,000 for the 1999
quarter, and increased 36% to $5,119,000 for the nine months ended
September 30, 2000 from $3,754,000 for the comparable 1999 period. Per Mcfe,
oil and gas production expense, including production tax and marketing
expense, increased $0.22, or 29%, to $0.98 for the 2000 quarter from $0.76 for
the 1999 quarter. Production tax and marketing expense per Mcfe increased
$0.23 to $0.52 per Mcfe, or 79%, for the 2000 quarter from $0.29 for the 1999
quarter because of higher oil and gas prices in the 2000 quarter. LOE per
Mcfe decreased 2% to $0.46 for the 2000 quarter from $0.47 for the 1999
quarter. Oil and gas production expenses per Mcfe increased $0.27, or 37%, to
$1.00 for the nine months ended September 30, 2000 from $0.73 for the nine
months ended September 30, 1999. Production tax and marketing expense
increased $0.16 per Mcfe, or 62%, during the nine months ended September 30,
2000 as a result of higher oil and gas prices. LOE per Mcfe increased $0.11,
or 23%, to $0.58 for the nine months ended September 30, 2000 compared to
$0.47 for the same period a year ago due to increased personnel and increases
in salary, compression and workover costs relative to increases in production.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the three months ended September 30, 2000 increased 42% to
$1,604,000 from $1,132,000 in the 1999 quarter, and increased 24% to
$4,323,000 for the nine months ended September 30, 2000 from $3,489,000 for
the nine months ended September 30, 1999. Depletion per Mcfe increased 16% to
$0.72 for the fiscal 2000 quarter from $0.62 for the fiscal 1999 quarter and
increased 20% to $0.73 for the nine months ended September 30, 2000 from $0.61
for the nine months ended September 30, 1999, primarily due to a higher ratio
of increases in capital expenditures to increases in reserves.
General and Administrative Expenses. Total general and administrative
expenses for the three months ended September 30, 2000 increased 45% to
$724,000 from $500,000 in the 1999 quarter, and increased 55% to $2,770,000
for the nine months ended September 30, 2000 from $1,782,000 for the same
period in 1999, as a result of the issuance of employee stock options with
below market strike prices and increased costs for contract and consulting
services related to special projects.
Interest and Other Expenses. Interest and other expenses for the three
months ended September 30, 2000 increased 126% to $1,671,000 from $741,000 for
the three months ended September 30, 1999 and increased 134% to $4,460,000 for
the nine months ended September 30, 2000 from $1,903,000 for the nine months
ended September 30, 1999. The increase was primarily due to a higher
outstanding debt balance and higher interest rates in the 2000 periods.
Income Taxes. We incurred net operating losses for U.S. Federal income
tax purposes in 2000 and 1999, which can be carried forward to offset future
taxable income. SFAS No. 109 requires that a valuation allowance be provided
if it is more likely than not that some portion or all of a deferred tax asset
will not be realized. Our ability to realize the benefit of our deferred tax
asset will depend on the generation of future taxable income through
profitable operations and the expansion of our oil and gas producing
activities. The market and capital risks associated with achieving the above
requirement are considerable, resulting in our decision to provide a valuation
allowance equal to the net deferred tax asset. Accordingly, we did not
recognize any tax benefit in the consolidated statements of operations for the
three and nine months ended September 30, 2000 and 1999.
Extraordinary Loss. We incurred an extraordinary loss of $105,000 during
the nine months ended September 30, 1999, as a result of the refinancing of
our debt with a new lender.
Net Loss. Net loss for the three months ended September 30, 2000
increased 626% to $1,104,000 from $152,000 for the three months ended
September 30, 1999, and increased 210% to $4,631,000 for the nine months ended
September 30, 2000 from $1,495,000 for the same period a year ago, as a result
of the factors discussed above. We paid the 8% dividend of $16,000 and $27,000
on our Series B Mandatorily Redeemable Convertible Preferred Stock ("Series B
Preferred Stock"), and realized accretion of $1,000 and $3,000, in the three
months ended September 30, 2000 and 1999, respectively. We paid dividends of
$61,000 and $81,000 and realized accretion of $6,000 and $9,000 in the nine-
month periods ended September 30, 2000 and 1999, respectively. Net loss
attributable to common shareholders for the three months ended September 30,
2000 increased 574% to $1,226,000 from $182,000 for the three months ended
September 30, 1999, and increased 216% to $5,002,000 for the nine months ended
September 30, 2000 from $1,585,000 for the nine months ended September 30,
1999.
<PAGE>
Hedging Activities
We use hedging instruments to manage commodity price risks. We have used
energy swaps and other financial arrangements to hedge against the effects of
fluctuations in the sales prices for oil and natural gas. Gains and losses on
such transactions are matched to product sales and charged or credited to oil
and gas sales when that product is sold. Management believes that the use of
various hedging arrangements can be a prudent means of protecting our
financial interests from the volatility of oil and gas prices. Under our
Aquila Credit Agreement, we agreed to maintain price hedging arrangements in
place with respect to up to 65% of our oil and gas production upon terms
satisfactory to us and Aquila. We recognized hedging gains (losses) of
($2,510,000) and ($278,000) for third quarter 2000 and 1999, respectively, and
recognized hedging gains (losses) of ($4,696,000) and $101,000 for the nine
months ended September 30, 2000 and 1999, respectively. These amounts are
included in oil and gas sales in our consolidated statements of operations.
Miscellaneous
Our oil and gas operations are significantly affected by certain
provisions of the Internal Revenue Code that are applicable to the oil and gas
industry. Current law permits our intangible drilling and development costs
to be deducted currently, or capitalized and amortized over a five year
period. We, as an independent producer, are also entitled to a deduction for
percentage depletion with respect to the first 1,000 Bbls per day of domestic
crude oil (and/or equivalent units of domestic natural gas) produced (if such
percentage depletion exceeds cost depletion). Generally, this deduction is
15% of gross income from an oil and gas property, without reference to the
taxpayer's basis in the property. The percentage depletion deduction may not
exceed 100% of the taxable income from a given property. Further, percentage
depletion is limited in the aggregate to 65% of our taxable income. Any
depletion disallowed under the 65% limitation, however, may be carried over
indefinitely.
Inflation has not historically had a material impact on our consolidated
financial statements, and management does not believe that we will be
materially more or less sensitive to the effects of inflation than other
companies in the oil and gas industry.
The preceding information contains forward-looking statements, the
realization of which cannot be assured. Actual results may differ
significantly from those forecast. When evaluating the Company, its
operations, or its expectations, the reader should bear in mind that the
Company and our operations are subject to numerous risks and uncertainties.
Among these are risks related to the oil and gas business generally (including
operating risks and hazards and the regulations imposed thereon), risks and
uncertainties related to the volatility of the prices of oil and gas,
uncertainties related to the estimation of reserves of oil and gas and the
value of such reserves, uncertainties relating to geologic models and
evaluations, the effects of competition and extensive environmental
regulation, and other factors, many of which are necessarily beyond our
control. These and other risk factors that affect our business are discussed
in our 1999 Form 10-K.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We use commodity derivative financial instruments, including swaps, to
reduce the effect of natural gas and crude oil price volatility on a portion
of our natural gas and crude oil production. Commodity swap agreements are
generally used to fix a price at the natural gas or crude oil market location
or to fix a price differential between a benchmark price of natural gas and
crude oil and the price of gas or crude oil at its market location.
Settlements are based on the difference between a fixed and a variable price
as specified in the agreement. The following table summarizes our derivative
financial instrument position on our natural gas and crude oil production as
of September 30, 2000. The fair value of these instruments reflected below is
the estimated amount that we would receive (or pay) to settle the contracts as
of September 30, 2000. Actual settlement of these instruments when they mature
will differ from these estimates reflected in the table. Gains or losses
realized from these instruments hedging our production are expected to be
offset by changes in the actual sales price received by us for our natural gas
and crude oil production. See "Hedging Activities" above.
<PAGE>
<TABLE>
<CAPTION
Natural Gas:
Fixed Price
Year MMBtu per MMBtu Fair Value
<S> <C> <C> <C>
2000 1,350,000 $2.02 $(3,761,000)
2001 2,392,000 $2.55-$4.68 (3,596,000)
2002 1,558,000 $2.55-$3.91 (2,092,000)
2003 996,000 $2.55 (1,114,000)
2004 852,000 $2.55 (825,000)
Crude Oil:
2000 21,000 $18.73 - $19.00 $ (295,000)
2001 60,000 $17.38 - $18.61 (659,000)
2002 60,000 $17.40 (512,000)
2003 48,000 $17.40 (316,000)
2004 48,000 $17.40 (258,000)
</TABLE>
In addition, we entered into a basis swap to fix the differential between
the NYMEX price and the index price at which the hedged gas is to be sold for
5,798,000 MMBtu for 2001 - 2004 with a fair value of $(185,000).
In November 2000, we entered into one-year put and call contracts pursuant
to which we hedged the price of 60,000 MMBtu per month beginning January 2001
based on an El Paso-Permian Index. We will receive $3.85 per MMBtu if the
settlement price is below $3.85 per MMBtu. If the settlement price is greater
than $5.80 per MMBtu, we will pay the difference between such settlement price
and $5.80 per MMBtu.
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
None.
(b) Reports on Form 8-K:
During third quarter 2000, the Company filed a Periodic Report of Form
8-K dated September 8, 2000 related to an "Item 5. Other Events" matter.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
MALLON RESOURCES CORPORATION
Registrant
Date: November 13, 2000 By: /s/ Roy K. Ross
Roy K. Ross
Executive Vice President
Date: November 13, 2000 By: /s/ Alfonso R. Lopez _
Alfonso R. Lopez
Vice President, Finance/Corporate Treasurer
