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 June 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 August 9, 2000, 7,886,643 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)
ASSETS
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
(Unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 1,610 $ 1,230
Accounts receivable:
Oil and gas sales 1,673 1,315
Joint interest participants, net of allowance of $43 and
$43, respectively 341 559
Related parties -- 53
Other 3 153
Inventories 219 200
Other 167 83
Total current assets 4,013 3,593
Property and equipment:
Oil and gas properties, full cost method 112,262 103,315
Natural gas processing plant 8,407 8,341
Other property and equipment 1,104 1,084
121,773 112,740
Less accumulated depreciation, depletion and amortization (55,608) (53,428)
66,165 59,312
Notes receivable 14 84
Debt issuance costs 1,652 1,885
Other, net 276 552
Total Assets $ 72,120 $ 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)
LIABILITIES AND SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
(Unaudited)
<S> <C> <C>
Current liabilities:
Trade accounts payable $ 4,588 $ 4,883
Undistributed revenue 915 934
Accrued taxes and expenses 48 55
Current portion of long-term debt 427 399
Convertible note payable - related party 552 --
Total current liabilities 6,530 6,271
Long-term debt, net of unamortized discount of $2,814 and $3,146,
respectively 44,785 34,874
Total liabilities 51,315 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 794 1,341
Mandatorily Redeemable Common Stock, $0.01 par value,
420,000 shares authorized, issued and outstanding,
mandatory redemption of $5,250 3,649 3,450
Shareholders' equity:
Common Stock, $0.01 par value, 25,000,000
shares authorized; 7,458,976 and 7,413,300
shares issued and outstanding, respectively 75 74
Additional paid-in capital 77,805 77,013
Accumulated deficit (58,644) (54,914)
Notes receivable from related party shareholders (2,776) (2,683)
Accounts receivable from shareholders (98) --
Total shareholders' equity 16,362 19,490
Total Liabilities and Shareholders' Equity $ 72,120 $ 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 Six Months
Ended June 30, Ended June 30,
2000 1999 2000 1999
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 3,180 $ 2,913 $ 7,100 $ 5,933
Interest and other 71 27 133 45
3,251 2,940 7,233 5,978
Costs and expenses:
Oil and gas production 1,543 1,175 3,206 2,520
Depreciation, depletion and amortization 1,278 1,051 2,719 2,357
General and administrative 856 582 2,046 1,282
Interest and other 1,470 604 2,789 1,162
5,147 3,412 10,760 7,321
Net loss (1,896) (472) (3,527) (1,343)
Dividends on preferred stock and accretion (20) (30) (50) (60)
Accretion of mandatorily redeemable common stock (101) -- (199) --
Net loss attributable to common shareholders $(2,017) $ (502) $(3,776) $(1,403)
======= ======= ======= =======
Basic:
Net loss attributable to common shareholders $ (0.26) $ (0.07) $ (0.48) $ (0.20)
======= ======= ======= =======
Weighted average shares outstanding 7,855 7,025 7,854 7,024
======= ======= ======= =======
</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 Six Months
Ended June 30,
2000 1999
<S> <C> <C>
Cash flows from operating activities:
Net loss $(3,527) $(1,343)
Adjustments to reconcile net loss to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization 2,719 2,357
Accrued interest expense added to long-term debt 2,021 --
Accrued interest income added to notes receivable from
related party shareholders (93) --
Amortization of discount on long-term debt 332 --
Stock compensation expense 413 55
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable 283 117
Inventory and other assets (108) (170)
Increase (decrease) in:
Trade accounts payable and undistributed revenue (314) (2,071)
Accrued taxes and expenses (6) 160
Deferred revenue -- (455)
Net cash provided by (used in) operating activities 1,720 (1,350)
Cash flows from investing activities:
Additions to property and equipment (9,022) (3,866)
Decrease in notes receivable 70 6
Net cash used in investing activities (8,952) (3,860)
Cash flows from financing activities:
Proceeds from long-term debt 7,780 5,280
Payments of long-term debt (195) (654)
Proceeds from stock option and warrants exercises 68 55
Payment of preferred dividends (45) (54)
Other 4 --
Net cash provided by financing activities 7,612 4,627
Net increase (decrease) in cash and cash equivalents 380 (583)
Cash and cash equivalents, beginning of period 1,230 1,733
Cash and cash equivalents, end of period $ 1,610 $ 1,150
======= =======
</TABLE>
(Continued)
The accompanying notes are an integral part of these
consolidated financial statements.
<PAGE>
MALLON RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
(Continued)
<TABLE>
<CAPTION>
For the Six Months
Ended June 30,
2000 1999
<S> <C> <C>
Supplemental cash flow information:
Cash paid for interest $ 400 $ 1,086
======= =======
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 shareholders $ 98 $ --
======= =======
</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>
June 30, December 31,
2000 1999
<S> <C> <C>
Note payable to Aquila Energy Capital Corporation,
due 2003 $42,692 $32,890
Less unamortized discount (effective rate of 13.7%) (2,814) (3,146)
39,878 29,744
Lease obligation to Universal Compression, Inc. 5,203 5,390
8.5% unsecured note payable to Bank One, Colorado,
N.A., due 2002 131 139
45,212 35,273
Less current portion (427) (399)
Total $44,785 $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 million as
new reserves are added through the Company's planned development drilling
program. At June 30, 2000, the Company had drawn $42.7 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
<PAGE>
2000, Aquila agreed to increase the amount available under the agreement from
the initial amount of $45.7 million to approximately $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.
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 June 30, 2000, the advances exceeded cash flow from operations
and the Company had not made any principal payments.
During the six months ended June 30, 2000, the Company repaid $187,000 of
lease obligation to Universal Compression and $8,000 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 six months ended
June 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. The Company believes the adoption of this Interpretation
will not have a material impact on the Company's financial position and
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
<PAGE>
$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
$10.28. 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.
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 expects
approval by the end of August 2000. The Company expects to sign final
contracts thereafter. 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.
<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
consolidated financial position at June 30, 2000 and December 31, 1999,
results of operations for the three and six months ended June 30, 2000 and
1999 and cash flows for the six months ended June 30, 2000 and 1999. Our
Consolidated Financial Statements and notes thereto should be referred to in
conjunction with the following discussion.
Overview
Our revenues, profitability and future growth rates 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 produce
economically.
Liquidity and Capital Resources
Our operations are capital intensive. Historically, our principal sources
of capital have been cash flow from operations, advances from our fixed-term
credit facility, a revolving line of credit 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 related
facilities.
During the first half of 2000, our capitalized costs incurred in oil and
gas producing activities were $8.9 million. Our 2000 capital expenditure
budget is $23.4 million. During the first half of 2000, we drilled 18 wells of
the total 50 wells we plan to drill during the year. Eight wells drilled were
completed and put on production, nine were completing and the remaining well
was a dry hole. We expect to fund our capital requirements for the next 12
months out of cash flow from operations, borrowings, and a possible 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 were able to begin
completion operations in May. 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 substantially
increase initial production rates and reduce drilling, completion and
operating costs, which would in turn increase the value of our reserves.
Subsequent to June 30, 2000, we completed five more 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. As of August 4, 2000, we had
drawn $44.9 million, including accrued interest, under the Aquila Credit
Agreement. The amount available under the Aquila Credit Agreement may be
increased to as much as $60 million as new reserves are added through our
development drilling program. 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
agreed to increase the amount available under the credit agreement by $6.7
million, making the total available $52.4 million. Our planned capital
expenditures during 2000 anticipate that at least $53 million will be
available to us under this credit agreement. We expect these additional funds
to be made available as our drilling program proceeds. 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 June 30,
2000, the advances exceeded cash flow from operations and the Company had not
made any principal payments.
<PAGE>
We do not anticipate making any principal payments for the remainder of
this year because we expect drilling expenditures to equal or surpass defined
cash flow from operations during that period. The Aquila Credit Agreement is
secured by 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, 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 September
1999. In conjunction with the increase in the borrowing base in July 2000, we
agreed to issue to Aquila an additional 70,000 shares of common stock. Aquila
also has a one-time right to require us to purchase all 490,000 of our common
shares from Aquila at $12.50 per share during the 30-day period beginning
September 9, 2003.
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 expect approval by the end of August
2000. We expect to sign final contracts thereafter. 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.
We are currently considering options to secure additional capital to
continue our active drilling and development program through 2000, in the
event that our borrowing base under the Aquila Credit Agreement becomes
insufficient. The options include the issuance of preferred or other equity
securities. However, there is no assurance that we will be able to obtain
additional funding.
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 $187,000 to Universal Compression during the first half 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.We repaid $8,000
of this loan during first quarter 2000.
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 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 Mallon's common stock, using the
same conversion price applicable to the remaining Series B Preferred Stock
shares, currently $10.28. The Series B Stock is convertible to common stock
automatically if the common stock trades at a price in excess of 140% of the
then applicable conversion price for each day in a period of 10 consecutive
trading days.
<PAGE>
Results of Operations
<TABLE>
<CAPTION>
For the Three Months For the Six Months
Ended June 30, Ended June 30,
(In thousands, except per unit data) 2000 1999 2000 1999
<S> <C> <C> <C> <C>
Results of Operations from Oil and Gas Producing Activities:
Oil and gas sales $ 3,180 $ 2,913 $ 7,100 $ 5,933
Production tax and marketing expense 574 411 1,131 856
Lease operating expense 969 764 2,075 1,664
Depletion 1,060 941 2,311 2,152
Depreciation 78 68 122 135
Net Production:
Oil (MBbl) 41 44 84 91
Natural gas (MMcf) 1,218 1,303 2,662 2,989
MMcfe 1,464 1,567 3,166 3,535
Average Sales Price Realized (1):
Oil (per Bbl) $ 24.27 $ 15.89 $ 24.05 $ 13.64
Natural gas (per Mcf) 1.79 1.70 1.91 1.57
Per Mcfe 2.17 1.86 2.24 1.68
Average Cost Data (per Mcfe):
Production tax and marketing expense $ 0.39 $ 0.26 $ 0.36 $ 0.24
Lease operating expense 0.66 0.49 0.65 0.47
Depletion 0.72 0.60 0.73 0.61
Depreciation 0.05 0.04 0.04 0.04
_________________
(1) Includes effects of hedging.
</TABLE>
Three and Six Months Ended June 30, 2000 Compared to June 30, 1999
Revenues. Total revenues increased 11% to $3,251,000 for the three months
ended June 30, 2000 from $2,940,000 for the three months ended June 30, 1999
and increased 21% to $7,233,000 for the six months ended June 30, 2000 from
$5,978,000 for the six months ended June 30, 1999. Oil and gas sales
increased 9% to $3,180,000 for the 2000 quarter compared $2,913,000 for the
1999 quarter. Higher oil and gas prices were somewhat offset by lower oil and
gas production. Oil and gas sales increased 20% to $7,100,000 for the six
months ended June 30, 2000 from $5,933,000 for the six months ended June 30,
1999, due to higher oil and gas prices which were somewhat offset by lower oil
and gas production. Average oil prices realized per barrel increased 53% to
$24.27 in second quarter 2000 from $15.89 for second quarter 1999 and average
gas prices realized per Mcf increased 5% to $1.79 in the 2000 quarter from
$1.70 in the 1999 quarter. Average oil prices realized per barrel increased
76% to $24.05 for the six months ended June 30, 2000, from $13.64 for the
comparable 1999 period, and average gas prices realized per Mcf increased 22%
to $1.91 in the 2000 period from $1.57 for the six months ended June 30, 1999.
Oil production decreased 7% to 41,000 barrels in the 2000 quarter from 44,000
barrels in the 1999 quarter and gas production decreased 7% to 1,218,000 Mcf
in the 2000 quarter from 1,303,000 in the 1999 quarter. Oil production
decreased 8%, to 84,000 barrels for the six months ended June 30, 2000 from
91,000 barrels for the six months ended June 30, 1999, and gas production
decreased 11% to 2,662,000 Mcf for the six months ended June 30, 2000 from
2,989,000 Mcf for the same period a year ago. The oil production decreases
are due to natural declines. We have been focusing on drilling gas wells.
The gas production declines are due to the planned delay in new well
completions pending approval of commingling, as discussed above.
Oil and Gas Production Expenses. Oil and gas production expenses,
including production tax and marketing expenses, increased 31% to $1,543,000
for the three months ended June 30, 2000 from $1,175,000 for the 1999 quarter,
and increased 27% to $3,206,000 for the six months ended June 30, 2000 from
$2,520,000 for the
<PAGE>
comparable 1999 period, due to new wells coming on line as a result of our
drilling program. Per Mcfe, oil and gas production expense, including
production tax and marketing expense, increased $0.30, or 40%, to $1.05 for
the 2000 quarter from $0.75 for the 1999 quarter. Production tax and
marketing expense per Mcfe increased $0.13, or 50%, for the 2000 quarter from
the 1999 quarter because of higher oil and gas prices. LOE per Mcfe increased
35% to $0.66 in the 2000 quarter from $0.49 for the 1999 quarter. Oil and gas
production expenses per Mcfe increased $0.30, or 42%, to $1.01 for the six
months ended June 30, 2000 from $0.71 for the six months ended June 30, 1999.
Production tax and marketing expense increased $0.12 per Mcfe, or 50%, during
the six months ended June 30, 2000 as a result of higher oil and gas prices.
LOE per Mcfe for the six months ended June 30, 2000 increased 38% to $0.65
from $0.47 for the 1999 period. The increase in LOE per Mcfe in the 2000
periods is partially due to lower production and partially due to increased
personnel and increases in salary, compression and workover costs.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the three months ended June 30, 2000 increased 22% to
$1,278,000 from $1,051,000 in the 1999 quarter, and increased 15% to
$2,719,000 for the six months ended June 30, 2000 from $2,357,000 for the six
months ended June 30, 1999. Depletion per Mcfe increased 20% to $0.72 for the
fiscal 2000 quarter from $0.60 for the fiscal 1999 quarter and increased 20%
to $0.73 for the six months ended June 30, 2000 from $0.61 for the six months
ended June 30, 1999 due to a higher ratio of increases in capital expenditures
to increases in reserves.
General and Administrative Expenses. Net general and administrative
expenses for the quarter ended June 30, 2000 increased 47% to $856,000 from
$582,000 in the 1999 quarter, and increased 60% to $2,046,000 for the six
months ended June 30, 2000 from $1,282,000 for the same period in 1999 as a
result of the issuance of employee stock options with a below market strike
price and increased costs for contract and consulting services related to
special projects.
Interest and Other Expenses. Interest and other expenses for the quarter
ended June 30, 2000 increased 143% to $1,470,000 from $604,000 for the 1999
quarter and increased 140% to $2,789,000 for the six months ended June 30,
2000 from $1,162,000 for the six months ended June 30, 1999. The increase was
primarily due to a higher outstanding debt balance and higher interest rates
in the 2000 periods.
Income Taxes. The Company incurred net operating losses ("NOLs") for
U.S. Federal income tax purposes in 2000 and 1999, which can be carried
forward to offset future taxable income. Statement of Financial Accounting
Standards 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. The Company's ability to realize the benefit of its deferred tax
asset will depend on the generation of future taxable income through
profitable operations and the expansion of the Company's oil and gas producing
activities. The market and capital risks associated with achieving the above
requirement are considerable, resulting in the Company's decision to provide a
valuation allowance equal to the net deferred tax asset. Accordingly, the
Company did not recognize any tax benefit in the consolidated statements of
operations for the three and six months ended June 30, 2000 and 1999.
Net Loss. Net loss for the three months ended June 30, 2000 increased
302% to $1,896,000 from $472,000 for the three months ended June 30, 1999, and
increased 163% to $3,527,000 for the six months ended June 30, 2000 from
$1,343,000 for the same period a year ago, as a result of the factors
discussed above. The Company paid the 8% dividend of $16,000 and $27,000 on
its Series B Mandatorily Redeemable Convertible Preferred Stock ("Series B
Preferred Stock") and realized accretion of $4,000 and $3,000 in the three
month periods ended June 30, 2000 and 1999, respectively. The Company paid
dividends of $43,000 and $54,000 and realized accretion of $7,000 and $13,000
during the six month periods ended June 30, 2000 and 1999, respectively. Net
loss attributable to common shareholders for the three months ended June 30,
2000 increased 302% to $2,017,000 from $502,000 for the three months ended
June 30, 1999, and increased 169% to $3,776,000 for the six months ended
June 30, 2000 from $1,403,000 for the six months ended June 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 (losses) gains of
($1,658,000) and $183,000 in second quarter 2000 and 1999, respectively and
recognized hedging (losses) gains of $(2,186,000) and $379,000 in the six
months ended June 30, 2000 and 1999, respectively. These amounts are included
in oil and gas sales in our consolidated statements of operations.
Miscellaneous
Our operations are significantly affected by certain provisions of the
Internal Revenue Code 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 barrels 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 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 business.
The preceding information contains forward-looking statements, the
realization of which cannot be assured. Actual results may differ
significantly from those forecast. When evaluating us, our operations, or our
expectations, the reader should bear in mind that we 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 June 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
June 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 2,700,000 $ 2.02 $(5,666,000)
2001 1,452,000 $ 2.55 (1,582,000)
2002 1,188,000 $ 2.55 (602,000)
2003 996,000 $ 2.55 (302,000)
2004 852,000 $ 2.55 (197,000)
Crude Oil:
2000 42,000 $18.73 - $19.68 $ (499,000)
2001 60,000 $17.38 - $18.61 (495,000)
2002 60,000 $17.40 (340,000)
2003 48,000 $17.40 (181,000)
2004 48,000 $17.40 (115,000)
</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
4,488,000 MMBtu for 2001 - 2004 with a fair value of $(137,000).
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders
The Company held its annual meeting on July 18, 2000. The seven
individuals listed below were elected as directors. The votes cast were as
follows:
With respect to the election of directors:
<TABLE>
<CAPTION>
BROKER
NAME FOR AGAINST ABSTAIN NON-VOTES
<S> <C> <C> <C> <C>
George O. Mallon, Jr. 3,015,417 401,406 4,947 -0-
Kevin M. Fitzgerald 3,416,315 508 4,947 -0-
Roy K. Ross 3,416,315 508 4,947 -0-
Roger R. Mitchell 3,416,315 508 4,947 -0-
Frank Douglass 3,416,315 508 4,947 -0-
Francis J. Reinhardt, Jr. 3,416,315 508 4,947 -0-
Peter H. Blum 2,660,115 756,708 4,947 -0-
</TABLE>
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
None.
(b) Reports on Form 8-K:
During second quarter 2000, the Company filed Periodic Reports of Form 8-K
dated April 11, 2000 and April 17, 2000. Each Report 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: August 14, 2000 By: /s/ Roy K. Ross
Roy K. Ross
Executive Vice President
Date: August 14, 2000 By: /s/ Alfonso R. Lopez
Alfonso R. Lopez
Vice President, Finance/Corporate Treasurer
<PAGE>
