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, 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 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, 1999, 7,833,300 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>
September 30, December 31,
1999 1998
(Unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 1,366 $ 1,733
Accounts receivable:
Oil and gas sales 1,253 1,076
Joint interest participants, net of allowance of $43 and
$43, respectively 477 650
Related parties 60 89
Inventories 378 375
Other 67 32
Total current assets 3,601 3,955
Property and equipment:
Oil and gas properties, full cost method 98,733 93,624
Natural gas processing plant 8,339 8,275
Other equipment 1,049 989
108,121 102,888
Less accumulated depreciation, depletion and amortization (52,186) (48,748)
55,935 54,140
Notes receivable-related parties 83 89
Debt issuance costs 1,985 --
Other, net 204 268
Total Assets $ 61,808 $ 58,452
======== ========
</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>
September 30, December 31,
1999 1998
(Unaudited)
<S> <C> <C>
Current liabilities:
Trade accounts payable $ 2,055 $ 4,424
Undistributed revenue 705 945
Accrued taxes and expenses 144 149
Deferred revenue 227 909
Current portion of long-term debt 409 1,310
Total current liabilities 3,540 7,737
Long-term debt, net of unamortized discount of $3,300 and $-0-,
respectively 32,862 27,183
Accrued expenses 13 39
Total non-current liabilities 32,875 27,222
Total liabilities 36,415 34,959
Series B Mandatorily Redeemable Convertible Preferred Stock,
$0.01 par value, 500,000 shares authorized, 135,200 shares
issued and outstanding, liquidation preference and
mandatory redemption of $1,352 1,338 1,329
Mandatorily Redeemable Common Stock, $0.01 par value, 420,000
shares authorized, issued and outstanding, mandatory
redemption of $5,250 3,334 --
Shareholders' equity:
Common Stock, $0.01 par value, 25,000,000
shares authorized; 7,413,300 and 7,021,065
shares issued and outstanding, respectively 74 70
Additional paid in capital 76,797 74,103
Accumulated deficit (53,514) (52,009)
Notes receivable from shareholders (2,636) --
Total shareholders' equity 20,721 22,164
Total Liabilities and Shareholders' Equity $ 61,808 $ 58,452
======== ========
</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,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 3,519 $ 3,620 $ 9,452 $ 9,602
Interest and other 41 16 86 86
3,560 3,636 9,538 9,688
Costs and expenses:
Oil and gas production 1,234 1,488 3,754 3,847
Depreciation, depletion and amortization 1,132 1,430 3,489 3,764
General and administrative 500 613 1,782 1,802
Interest and other 741 337 1,903 620
3,607 3,868 10,928 10,033
Loss before extraordinary item (47) (232) (1,390) (345)
Extraordinary loss on early retirement of debt (105) -- (105) --
Net loss (152) (232) (1,495) (345)
Dividends on preferred stock and accretion (30) (30) (90) (90)
Net loss attributable to common shareholders $ (182) $ (262) $(1,585) $ (435)
======= ======= ======= =======
Basic loss per share:
Loss attributable to common shareholders before
extraordinary item $ (0.01) $ (0.04) $ (0.21) $ (0.06)
Extraordinary loss (0.01) -- (0.01) --
Net loss attributable to common shareholders $ (0.02) $ (0.04) $ (0.22) $ (0.06)
======= ======= ======= =======
Basic weighted average common shares outstanding 7,173 7,025 7,075 7,012
======= ======= ======= =======
</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,
1999 1998
<S> <C> <C>
Cash flows from operating activities:
Net loss $ (1,495) $ (345)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization 3,489 3,764
Amortization of discount on long-term debt and installment obligation 34 17
Accrued interest expense added to long-term debt 181 --
Accrued interest income added to notes receivable from shareholders (15) --
Extraordinary loss 105 --
Stock compensation expense 68 169
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable 26 1,042
Inventory and other assets (113) (155)
Increase (decrease) in:
Trade accounts payable and undistributed revenue (2,636) 1,185
Accrued taxes and expenses (6) 117
Drilling advances (1) (122)
Deferred revenue (682) --
Net cash (used in) provided by operating activities (1,045) 5,672
Cash flows from investing activities:
Additions to property and equipment (5,213) (26,717)
Decrease (increase) in notes receivable-related parties 6 (1)
Net cash used in investing activities (5,207) (26,718)
Cash flows from financing activities:
Proceeds from long-term debt 42,187 17,281
Payments of long-term debt (34,291) --
Debt issue costs (1,985) --
Lease obligation payments -- (2,061)
Payment of preferred dividends (81) (81)
Proceeds from stock option exercises 55 --
Net cash provided by financing activities 5,885 15,139
Net decrease in cash and cash equivalents (367) (5,907)
Cash and cash equivalents, beginning of period 1,733 6,741
Cash and cash equivalents, end of period $ 1,366 $ 834
======== ========
Supplemental cash flow information:
Cash paid for interest $ 1,718 $ 551
======== ========
Non-cash transactions:
Acquisition of equipment under lease obligation $ -- $ 315
======== ========
Sale of common stock in exchange for notes receivable $ 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, whose oil and gas operations are conducted primarily in the State of
New Mexico. All significant intercompany 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 1998 Form 10-K.
Certain prior year amounts in the consolidated financial statements have
been reclassified to conform to the presentation used in 1999.
Note 2. NOTES PAYABLE AND LONG-TERM DEBT
At September 30, 1999, long-term debt consisted of the following:
<TABLE>
<CAPTION>
(In thousands)
<S> <C>
Note payable to Aquila Energy Capital Corporation, due 2003 $ 30,928
Less: Unamortized discount (effective rate of 13.7%) (3,300)
27,628
Lease obligation to Universal Compression, Inc. 5,500
8.5% unsecured note payable to Bank One, Colorado, N.A., due 2002 143
33,271
Less: Current portion (409)
$32,862
=======
</TABLE>
The Company had a revolving line of credit (the "Bank One Facility") with
Bank One, Texas, N.A. ("the Bank"). The Bank One Facility consisted of two
separate lines of credit: a primary revolving line of credit and a term loan
commitment of $6.5 million (the "Equipment Loan").
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 September 30,
1999, the Company had drawn $30.9 million, including accrued interest, under
the Aquila Credit Agreement, of which $28.0 million was used to retire the
Bank One Facility. Unamortized loan origination fees of $105,000 related to
the Bank One Facility are included in extraordinary loss on early retirement
of debt on the Company's consolidated statement of operations for
September 30, 1999. The remainder of the funds drawn under the Aquila Credit
Agreement was used to pay transaction costs and $1.0 million of outstanding
accounts payable. Additional funds will be advanced as the Company's
development drilling program proceeds. Principal payments on the four-year
loan will begin in November 1999 and are based on the Company's cash flow from
operations, as defined, less advances for the Company's development drilling
program. The Company's management does not anticipate making any principal
payments for the next 18 months because it expects drilling expenditures to
equal or surpass defined cash flow from operations during that period. The
Aquila Credit Agreement is secured by substantially all of the Company's oil
and gas properties. Interest on the amounts outstanding under 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, the Company also entered into an Agency Agreement
with Aquila under which the Company pays a marketing fee equal to 1% of the
net proceeds from the sale of the Company's oil and gas production.
In conjunction with the Aquila Credit Agreement, the Company also issued
to Aquila 420,000 shares of the Company's common stock, which were recorded as
Mandatorily Redeemable Common Stock in the accompanying consolidated balance
sheet, based on the market value of the Company's common stock on the date of
issuance. Aquila has a one-time right to require the Company to purchase the
420,000 shares at $12.50 per share during the 30-day period beginning
September 9, 2003. In October 1999, the Company filed a registration
statement with the Securities and Exchange Commission for the sale of up to
4,000,000 shares of common stock (see Note 7). Aquila, which may be a selling
shareholder in the Company's proposed equity offering, has agreed to waive its
put right with respect to shares it sells in conjunction with the Company's
equity offering in exchange for a payment from the Company of $1.00 per share.
Under the Aquila Credit Agreement, the Company is required to maintain
price hedging arrangements in place with respect to up to 65% of its oil and
gas production. Accordingly, in September 1999, the Company entered into
agreements to hedge a total of 300,000 barrels of oil related to production
for 2000-2004 at fixed prices ranging from $17.40-$22.35 per barrel and to
hedge a total of 4,488,000 MMBtus of gas related to production for 2001-2004
at a fixed price of $2.55 per MMBtu. In addition, the Company 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.
In September 1999, the Company also entered into a sale-leaseback
agreement with Universal Compression, Inc. to refinance and retire the
Equipment Loan under the Bank One Facility. The Company also terminated its
interest rate swap agreement related to the Equipment Loan in September 1999
for a gain of $3,500. The sale-leaseback was recorded as a financing under
the provisions of Statement of Financial Accounting Standards ("SFAS") No. 98,
"Accounting for Leases." The $5.5 million obligation has a five-year term
with monthly payments beginning in September 1999. The obligation bears
interest at an imputed interest rate of 12.8%. During 1999, prior to the
retirement of the Equipment Loan, the Company made principal payments of
$758,000.
Note 3. EARNINGS (LOSS) PER SHARE
Under the provisions of 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 Convertible Preferred Stock were
converted to common stock.
The consolidated statements of operations for the three and nine months
ended September 30, 1999 and 1998 reflect only basic earnings per share
because the Company was in a loss position for all periods presented and all
common stock equivalents were anti-dilutive.
Note 4. HEDGING ACTIVITIES
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
<PAGE>
statement, and requires that a company must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting. The
implementation of SFAS No. 133 has been deferred and is now effective for
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.
Note 5. STOCK OWNERSHIP ENCOURAGEMENT PROGRAM
In July 1999, the Company adopted a Stock Ownership Encouragement Program
to encourage holders of options to exercise their rights to purchase shares of
the Company's common stock. Under the program, the Company may lend option
holders the funds necessary to exercise their options. Funds advanced are
immediately paid to the Company in connection with the exercise of the
options. As a result, the Company incurs no cash outlay. Loans made under
the program must be approved by the Board of Directors or by its Compensation
Committee, and are represented by secured, interest-bearing, full recourse
promissory notes from the participants.
In September 1999, certain officers of the Company exercised options to
purchase 381,360 shares of common stock at an exercise price of $6.88 per
share, and borrowed funds from the Company to do so. The notes bear interest
at 7%, which is due along with the principal in August 2002. The notes and
accrued interest have been reflected as a reduction of shareholder's equity in
the accompanying consolidated balance sheet.
Note 6. WARRANTS
In July 1999, the Company entered into a financial consulting services
contract with Bear Ridge Capital LLC. Under the contract, Bear Ridge Capital
is paid a monthly retainer and was issued warrants to purchase an aggregate of
40,000 shares of the Company's common stock at a per share exercise price of
$0.01. Warrants covering 10,000 shares vest on July 1, 2001. The remaining
warrants do not vest except in the event of certain corporate transactions.
The warrants expire December 31, 2004. Bear Ridge Capital is wholly-owned by
one of the Company's directors.
In October 1999, the Company extended the expiration date of warrants to
purchase 160,000 shares of its common stock from October 16, 2000 to
December 31, 2002. As a result of the extension, the Company will record
approximately $217,000 of compensation expense in fourth quarter 1999.
Note 7. SUBSEQUENT EVENT
In October 1999, the Company filed a registration statement with the
Securities and Exchange Commission for a public offering of up to 4,000,000
shares of common stock and up to 663,000 additional shares should the
underwriters exercise their over-allotment option. In addition, the
registration statement covers the sale of 420,000 shares of the Company's
common stock by a selling shareholder. The registration statement has not yet
become effective. If consummated, the net proceeds from the offering would be
used to fund the Company's drilling activities and the construction of an
approximately 50-mile long natural gas gathering line. There is no assurance
that the public offering will be consummated.
<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, 1999 and
December 31, 1998, results of operations for the three and nine months ended
September 30, 1999 and 1998 and cash flows for the nine months ended
September 30, 1999. Our historical 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, 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 nine months of 1999, we drilled and completed 5 wells
successfully and recompleted 5 wells. We currently have an $8.2 million
capital budget for the remainder of 1999, and plan to drill or recomplete
approximately 19 wells during the remainder of the year. Between September 30
and November 10, 1999, we drilled or recompleted 8 wells.
In September 1999, we 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
our planned development drilling program. At September 30, 1999, we had drawn
$30.9 million, including accrued interest, under the Aquila Credit Agreement,
of which $28.0 million was used to retire our Bank One Facility. The
remainder was used to pay transaction costs and $1.0 million of outstanding
accounts payable. Additional funds will be advanced as our drilling program
proceeds. Principal payments on the four-year loan will begin in November
1999 and are based on our cash flow from operations, as defined, less advances
for our drilling program. We do not anticipate making any principal payments
for the next 18 months 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 outstanding balances under 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 from the
sale of all of our oil and gas production. In conjunction with the Aquila
Credit Agreement, we also issued to Aquila 420,000 shares of common stock.
Aquila has a one-time right to require us to purchase 420,000 of our common
shares from Aquila at $12.50 per share during the 30-day period beginning
September 9, 2003. In October 1999, we filed a registration statement with
the Securities and Exchange Commission for the sale of up to 4.0 million
shares of common stock. Aquila, which may be a selling shareholder in our
proposed equity offering, has agreed to waive this put right with respect to
such shares sold by it in conjunction with our equity offering in exchange for
a payment from us equal to $1.00 per share.
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 the
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%. Payments under
the Master Rental Contract commenced in September 1999.
<PAGE>
Under the mandatory redemption feature of our Series B Mandatorily
Redeemable Convertible Preferred Stock we will be required to redeem 55,200
shares in April 2000, and the remaining 80,000 shares in April 2001. The
mandatory redemption price is $10.00 per share, plus any accrued but unpaid
dividends. 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. The
conversion price, as adjusted, is currently $10.30.
In October 1999, we filed a registration statement with the Securities and
Exchange Commission for a public offering of up to 4,000,000 shares of common
stock and up to 663,000 additional shares should the underwriters exercise
their over-allotment option. In addition, the registration statement covers
the sale of 420,000 shares of our common stock by a selling shareholder. The
registration statement has not yet become effective. If consummated, the net
proceeds from the offering would be used to fund our drilling activities and
the construction of an approximately 50-mile long natural gas gathering line.
There is no assurance that the public offering will be consummated. If the
offering is not consummated, we will not expand or accelerate our current
drilling and recompletion program until we evaluate other sources of capital.
Results of Operations
<TABLE>
<CAPTION>
For the Three Months For the Nine Months
Ended September 30, Ended September 30,
1999 1998 1999 1998
(In thousands, except per unit data)
<S> <C> <C> <C> <C>
Results of Operations from Oil and Gas Producing Activities:
Oil and gas sales $3,519 $3,620 $9,452 $9,602
Production tax and marketing expense 474 508 1,330 1,414
Lease operating expense 760 980 2,424 2,433
Depletion 1,006 1,387 3,158 3,611
Depreciation 68 16 203 80
Net Production:
Oil (MBbl) 39 51 130 180
Natural gas (MMcf) 1,388 1,810 4,377 4,056
Mmcfe 1,622 2,116 5,157 5,136
Average Sales Price Realized: (1)
Oil (per Bbl) $20.18 $12.69 $15.60 $13.46
Natural gas (per Mcf) 1.97 1.64 1.70 1.77
Per Mcfe 2.17 1.71 1.83 1.87
Average Cost Data (per Mcfe):
Production tax and marketing expense $0.29 $0.24 $0.26 $0.28
Lease operating expense 0.47 0.46 0.47 0.47
Depletion 0.62 0.66 0.61 0.70
Depreciation 0.04 0.01 0.04 0.02
</TABLE>_________________
1) Includes effects of hedging.
Three and Nine Months Ended September 30, 1999 Compared to September 30, 1998
Revenues. Total revenues decreased 2% to $3,560,000 for the three months
ended September 30, 1999 from $3,636,000 for the three months ended
September 30, 1998 and decreased 2% to $9,538,000 for the nine months ended
September 30, 1999 from $9,688,000 for the nine months ended September 30,
1998. Oil and gas sales decreased 3% to $3,519,000 for the 1999 quarter from
$3,620,000 for the 1998 quarter due primarily to lower oil and gas production
in the 1999 quarter. Oil and gas sales decreased 2% to $9,452,000 for the
nine months ended September 30, 1999 from $9,602,000 for the nine months ended
September 30, 1998, due to lower oil production and lower gas prices in the
1999
<PAGE>
period. Average oil prices realized per barrel increased 59% to $20.18 in the
fiscal 1999 quarter, from $12.69 in the fiscal 1998 quarter; and average gas
prices realized per Mcf increased 20% to $1.97 in the 1999 quarter from $1.64
in the 1998 quarter. Average oil prices realized per barrel increased 16% to
$15.60 for the nine months ended September 30, 1999, from $13.46 for the
comparable 1998 period, and average gas prices realized per Mcf decreased 4%
to $1.70 in the 1999 period from $1.77 for the nine months ended September 30,
1998. Oil production decreased 24% to 39,000 barrels in the 1999 quarter from
51,000 barrels in the 1998 quarter and gas production decreased 23% to
1,388,000 Mcf in the 1999 quarter from 1,810,000 Mcf in the 1998 quarter. Oil
production decreased 28% to 130,000 barrels for the nine months ended
September 30, 1999 from 180,000 barrels for the nine months ended
September 30, 1998; and gas production increased 8% to 4,377,000 Mcf for the
nine months ended September 30, 1999 from 4,056,000 Mcf for the same period a
year ago.
Production for third quarter 1999 was down from third quarter 1998's
production because our 1999 drilling and recompletion program in the San Juan
Basin East Blanco Field was delayed pending the receipt of additional
financing in September 1999. During the nine months ended September 30, 1999,
we devoted our limited capital to the drilling of six evaluation wells on a
largely undrilled 39,360 acre extension to our East Blanco acreage. Although
five of these wells were successful, only one of them is close enough to our
gathering system to have been placed on production. The remaining wells will
be hooked up as our development work progresses onto the extension acreage.
Our East Blanco Field, where we are focusing our drilling and development,
produces only natural gas.
Oil and Gas Production Expenses. Oil and gas production expenses,
including production tax and marketing expenses, decreased 17% to $1,234,000
for the three months ended September 30, 1999 from $1,488,000 for the 1998
quarter, and decreased 2% to $3,754,000 for the nine months ended
September 30, 1999 from $3,847,000 for the comparable 1998 period. Per Mcfe,
oil and gas production expense, including production tax and marketing
expense, increased $0.06, or 9%, to $0.76 for the 1999 quarter from $0.70 for
the 1998 quarter. Production tax and marketing expense per Mcfe increased
$0.05 to $0.29 per Mcfe, or 21%, for the 1999 quarter from $0.24 for the 1998
quarter because of higher oil and gas prices in the 1999 quarter. LOE per
Mcfe decreased 2% to $0.47 for the 1999 quarter from $0.46 for the 1998
quarter. Oil and gas production expenses per Mcfe decreased $0.02, or 3%, to
$0.73 for the nine months ended September 30, 1999 from $0.75 for the nine
months ended September 30, 1998. Production tax and marketing expense
decreased $0.02 per Mcfe, or 7%, during the nine months ended September 30,
1999 as a result of lower gas prices. LOE remained at $0.47 per Mcfe during
the nine months ended September 30, 1999 compared to the same period a year
ago.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the three months ended September 30, 1999 decreased 21% to
$1,132,000 from $1,430,000 in the 1998 quarter, and decreased 7% to $3,489,000
for the nine months ended September 30, 1999 from $3,764,000 for the nine
months ended September 30, 1998. Depletion per Mcfe decreased 6% to $0.62 for
the fiscal 1999 quarter from $0.66 for the fiscal 1998 quarter and decreased
13% to $0.61 for the nine months ended September 30, 1999 from $0.70 for the
nine months ended September 30, 1998, primarily due to the write-down of oil
and gas properties of $16.8 million in fourth quarter 1998, pursuant to the
rules of the Securities and Exchange Commission.
General and Administrative Expenses. Total general and administrative
expenses for the three months ended September 30, 1999 decreased 18% to
$500,000 from $613,000 in the 1998 quarter, and decreased 1% to $1,782,000 for
the nine months ended September 30, 1999 from $1,802,000 for the same period
in 1998.
Interest and Other Expenses. Interest and other expenses for the three
months ended September 30, 1999 increased 120% to $741,000 from $337,000 for
the three months ended September 30, 1998 and increased 207% to $1,903,000 for
the nine months ended September 30, 1999 from $620,000 for the nine months
ended September 30, 1998. The increase was primarily due to a higher
outstanding debt balance in the 1999 periods.
Income Taxes. We incurred net operating losses for U.S. Federal income
tax purposes in 1999 and 1998, 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 its 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
<PAGE>
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, 1999 and 1998.
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, 1999
decreased 34% to $152,000 from $232,000 for the three months ended
September 30, 1998, and increased 333% to $1,495,000 for the nine months ended
September 30, 1999 from $345,000 for the same period a year ago, as a result
of the factors discussed above. We paid the 8% dividend of $27,000 on our
Series B Mandatorily Redeemable Convertible Preferred Stock ("Series B
Preferred Stock"), and realized accretion of $3,000, in each of the three
months ended September 30, 1999 and 1998, respectively. We paid dividends of
$81,000 and realized accretion of $9,000 in each of the nine-month periods
ended September 30, 1999 and 1998, respectively. Net loss attributable to
common shareholders for the three months ended September 30, 1999 decreased
31% to $182,000 from $262,000 for the three months ended September 30, 1998,
and increased 264% to $1,585,000 for the nine months ended September 30, 1999
from $435,000 for the nine months ended September 30, 1998.
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 ($278,000) and $217,000 for third
quarter 1999 and 1998, respectively, and recognized hedging gains of $101,000
and $329,000 for the nine months ended September 30, 1999 and 1998,
respectively. These amounts are included in oil and gas sales in our
consolidated statements of operations.
Year 2000
The following Year 2000 statements constitute a Year 2000 Readiness
Disclosure within the meaning of the Year 2000 Information and Readiness
Disclosure Act of 1998. Year 2000 issues result from the inability of certain
electronic hardware and software to accurately calculate, store or use a date
subsequent to December 31, 1999. These dates can be erroneously interpreted
in a number of ways; i.e. the year 2000 could be interpreted as the year 1900.
This inability could result in a system failure or miscalculations that could
in turn cause operational disruptions. These issues could affect not only
information technology (so called "IT" systems) such as computer systems used
for accounting, land and engineering, but also systems that contain embedded
chips.
We have completed an assessment of our IT systems to determine whether
these systems are Year 2000 compliant. We have determined that these systems
are either compliant or with relatively minor modifications or upgrades (many
of which would have been made in any event as part of our continuing effort to
enhance our IT systems) will be compliant. All necessary modifications and
upgrades and the testing thereof are expected to be completed by the end of
the fourth quarter of 1999.
We are assessing our non-information systems to ascertain whether these
systems contain embedded computer chips that will not properly function
subsequent to December 31, 1999. These systems include office equipment, the
automatic wellhead equipment used to operate wells, our gas gathering lines,
and our gas sweetening plant in the San Juan Basin. All of these systems have
been determined to be Year 2000 compliant based on information provided by
third party vendors.
To date, we have relied upon our internal staff to assess our Year 2000
readiness. The costs associated with assessing our Year 2000 internal
compliance and related systems modifications, upgrading and testing are not
currently expected to exceed $50,000. Costs incurred through September 30,
1999 have been minimal.
<PAGE>
We are in the process of communicating with certain of our significant
suppliers, service companies, gas gatherers and pipelines, electricity
providers and financial institutions to determine our vulnerability to third
parties' failure to address their own Year 2000 issues. While we have not yet
received definitive responses indicating all such entities are Year 2000
compliant, we have not received information suggesting we are vulnerable to
potential Year 2000 failure by these parties. These communications are
expected to continue into the fourth quarter of 1999. At this time, we have
not developed any contingency plans to address third party non-compliance with
Year 2000 matters. However, should our communications with any third parties
indicate significant vulnerability, development of contingency plans will be
considered.
We do not anticipate any significant disruptions of our operations due to
Year 2000 issues. Among the potential "worst case" problems we could face
would be the loss of electricity used to power well pumps and compressors that
would result in wells being shut-in, or the inability of a third party gas
gathering company or pipeline to accept gas from our wells or gathering lines
which would also result in our wells being shut-in. A disruption in
production would result in the loss of income.
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 1998 Form 10-K.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk. We use commodity derivative financial instruments,
including swaps, to reduce the effect of natural gas price volatility on a
portion of our natural gas production. Commodity swap agreements are
generally used to fix a price at the natural gas market location or to fix a
price differential between the price of natural gas at Henry Hub and the price
of gas at its market location. Settlements are based on the difference
between a fixed and a variable price as specified in the agreement.
Under our Aquila Credit Agreement, we are required to maintain price
hedging arrangements in place with respect to up to 65% of our oil and gas
production. Accordingly, in September 1999, we entered into agreements to
hedge a total of 300,000 barrels of oil related to production for 2000-2004 at
fixed prices ranging from $17.40-$22.35 per barrel and to hedge a total of
4,488,000 MMBtus of gas related to production for 2001-2004 at a fixed price
of $2.55 per MMBtu. In addition, we entered into a basis swap to fix the
differential between the NYMEX price and the
<PAGE>
index price at which the hedged gas is to be sold for 4,488,000 MMBtu for
2001-2004. The fair value of the basis swap at September 30, 1999 was
($138,000).
The following tables summarize our derivative financial instrument
position on our natural gas and crude oil production as of September 30, 1999.
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,
1999.
<TABLE>
<CAPTION>
Fixed Price
Year MMBtu per MMBtu Fair Value
<S> <C> <C> <C>
1999 920,000 $2.18 $ (637,000)
2000 5,400,000 $2.02 (1,987,000)
2001 1,452,000 $2.55 (68,000)
2002 1,188,000 $2.55 (73,000)
2003 996,000 $2.55 (92,000)
2004 852,000 $2.55 (111,000)
</TABLE>
<TABLE>
<CAPTION>
Fixed Price
Year Bbls per Bbl Fair Value
<S> <C> <C> <C>
2000 84,000 $18.73-$22.35 $(92,000)
2001 60,000 $17.38-$18.61 (48,000)
2002 60,000 $17.40 (53,000)
2003 48,000 $17.40 (31,000)
2004 48,000 $17.40 (32,000)
</TABLE>
At September 30, 1999, we also had two basis swaps in place to fix the
differential between the NYMEX price and the index price at which the hedged
gas is to be sold which offset each other for a net volume of 880,000 MMBtu in
1999 with a fair value of $675.
Interest Rate Risk. In September 1999, we established the Aquila Credit
Agreement and retired our previous credit facility with Bank One, Texas, N.A.
and terminated the interest rate swap agreement we had for a gain of $3,500.
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 1999, the Company filed Periodic Reports on Form 8-K
dated July 19, 1999, August 13, 1999 and September 16, 1999. Each of those
reports related to an "Item 5. Other Events" matter. On September 9, 1999,
the Company filed a Periodic Report on Form 8-K relating to an "Item 5. Other
Events", which included exhibits.
<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 12, 1999 By: /s/ Roy K. Ross
Roy K. Ross
Executive Vice President
Date: November 12, 1999 By: /s/ Alfonso R. Lopez
Alfonso R. Lopez
Vice President, Finance/Corporate Treasurer
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE COMPANY'S FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,366
<SECURITIES> 0
<RECEIVABLES> 1,833
<ALLOWANCES> 43
<INVENTORY> 378
<CURRENT-ASSETS> 3,601
<PP&E> 108,121
<DEPRECIATION> 52,186
<TOTAL-ASSETS> 61,808
<CURRENT-LIABILITIES> 3,540
<BONDS> 0
<COMMON> 74
1,338
0
<OTHER-SE> 20,647
<TOTAL-LIABILITY-AND-EQUITY> 61,808
<SALES> 9,452
<TOTAL-REVENUES> 9,538
<CGS> 0
<TOTAL-COSTS> 9,025
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,903
<INCOME-PRETAX> (1,390)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,495)
<DISCONTINUED> 0
<EXTRAORDINARY> (105)
<CHANGES> 0
<NET-INCOME> (1,585)
<EPS-BASIC> (0.22)
<EPS-DILUTED> (0.22)
</TABLE>
