Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K/A
Amendment to Report
Filed Pursuant to Section 12, 13 or 15(d) of the
Securities Exchange Act of 1934
Mallon Resources Corporation
(Exact name of Registrant as specified in its charter)
0-17267
(Commission file number)
Amendment No. 1
The undersigned registrant hereby amends the following items,
financial statements, exhibits or other portions of its Annual
Report on Form 10K for the year ended December 31, 1994 (the
"1994 Form 10-K"), as set forth in the pages attached hereto:
Item 6 of the 1994 Form 10-K
Item 7 of the 1994 Form 10-K
Item 14 of the 1994 Form 10-K
(List of all such items, financial statements, exhibits
or other portions amended)
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 hereunto duly authorized.
Mallon Resources Corporation
March 28, 1996 /s/ Roy K. Ross
Roy K. Ross, Executive Vice President
Item 6. Selected Financial Data
The following is a summary of selected financial data which the
Company believes highlights trends in its financial condition and
results of its operations. The table presents the consolidated
results of operations for the years ended December 31, 1994,
1993, 1992, 1991, and 1990, and balance sheet data as of December
31, 1994, 1993, 1992, 1991, and 1990. This information should be
read in conjunction with the Consolidated Financial Statements
and Management's Discussion of Financial Condition and Results of
Operations, included elsewhere herein.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
Total revenues $5,082,000 $2,391,000 $1,977,000 $1,608,000 $2,264,000
Operating costs & other
expenses 6,713,000 3,578,000 2,244,000 6,239,000 3,619,000
Net income (loss) (1,631,000) (1,187,000) (268,000) (4,631,000) (1,355,000)
Net income (loss) per
common share (0.25) (0.22) (0.06) (0.99) (0.29)
Net cash provided by (used
in) operating activities (235,000) 10,114,000 47,000 270,000 (776,000)
Total assets 28,226,000 28,773,000 7,675,000 8,026,000 12,947,000
Long-term debt 315,000 2,411,000 348,000 41,000 117,000
Mandatorily Redeemable
Convertible Preferred
Stock 3,804,000 -- -- -- --
Weighted average number
of common shares
outstanding 7,664,000 5,471,000 4,781,000 4,672,000 4,671,000
</TABLE>
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Liquidity, Capital Resources and Capital Expenditures
Effective September 30, 1993, the Company acquired certain oil
and gas properties. As a part of the financing of the
acquisition, the Company entered into a volumetric production
payment (see Note 6 to the Consolidated Financial Statements)
arrangement with Enron, which requires the Company to deliver
substantial amounts of oil and gas. Satisfying the delivery
obligations is not expected to require all of the production or
cash flows expected to be generated from the acquired properties.
The Company's 1994 production enhancement operations (on 6 wells)
and its 1994 development drilling activities (3 operated wells
and 1 non-operated well) had a negative impact on cash flows.
Production enhancement operations require that a well's producing
zones be shut-in while procedures are performed; while shut-in,
the properties do not provide cash flows. In addition, the
production enhancement operations can be expensive. Similarly,
drilling operations required the expenditure of drilling funds
months in advance of the receipt of revenues from the well
drilled. The effect of this combination of factors was seen in
1994, when the Company recorded negative cash flows.
As of yearend 1994, the Company had drilled and completed 3
wells, and was in the process or planning the drilling of 5
additional wells. The Company has, or is in the process of,
permitting an additional 16 development locations for drilling in
1995. The Company expects to drill a total of at least 12 wells
by mid-1995. Cash flows from the 3 wells that were drilled and
completed in 1994 were not received by the Company until late in
the fourth quarter of that year. The Company has budgeted
$2,800,000 for the first phase of the drilling program. It will
then evaluate further drilling based upon the results of the
initial drilling phase.
If, as intended, the Company pursues additional acquisitions of
proven oil and gas properties, it will require additional
acquisition capital. The source of any such capital is not yet
known, nor are any such acquisitions arranged. If an acquisition
is contracted, the Company would expect to finance it with a
combination of debt and equity capital, although the details of
such financing cannot be predicted at this time. No assurance
can be given that additional acquisitions will be arranged or
that the acquisition capital necessary to complete them will be
available.
On April 15, 1994, the Company completed the private placement
(the "Placement") of 400,000 shares of its Series B Mandatorily
Redeemable Convertible Preferred Stock, $0.01 par value per share
(the "Series B Stock"). The newly created Series B Stock bears
an 8% dividend payable quarterly, and is convertible into shares
of the Company's common stock at a conversion price of $4.25 per
share. Gross proceeds from the Placement were $4,000,000; net
proceeds were $3,774,000. Mandatory redemption of this stock
begins on April 1, 1997, when 20% of the total outstanding shares
will be redeemed. An additional 20% per year will be redeemed on
each April 1 thereafter until all $4,000,000 of the Series B
Stock has been redeemed. The first $2,152,000 of net proceeds
were applied to retire the net profits interest held by Enron
(see Note 4 to the Consolidated Financial Statements) that
burdened certain of the Company's producing oil and gas
properties. The remaining net proceeds have been used to drill
development wells and engage in other production enhancement
operations on the Company's properties.
The Company is exploring several alternatives to realize the
value of its mining properties. Until a feasibility study
relating to putting the Rio Chiquito deposit on production as a
commercial gold and silver mine is completed, it is uncertain
what the Company's share of any costs related to that undertaking
will be. No assurance can be given that the Company will be able
to borrow its share of any capital required, although the Company
may attempt to do so. However, subsequent to yearend, the
Company, in a private placement, sold 25,000 shares of Laguna's
Series A Convertible Preferred Stock for $2,500,000, which
represents a 20% equity stake in Laguna. Each share of Series A
Preferred Convertible Stock includes 10 detachable warrants; each
warrant represents the right to purchase one share of the
Company's common stock at $2.50 per share. The warrants expire
on February 15, 2000. Each share of Series A Convertible
Preferred Stock can be converted into shares of Laguna common
stock at the option of the stockholder, or automatically in the
event of a public offering of the common stock of Laguna. The
private placement is scheduled to close on May 31, 1995. The
proceeds from this offering will be used to fund the operations
of Laguna for a twelve month period. The program includes
additional core drilling to expand mineable reserves on the Rio
Chiquito anomaly located on Laguna's Costa Rica concessions, and
preparation of a bankable feasibility study for commercial
development of Rio Chiquito in anticipation of making an initial
public offering of Laguna stock when market conditions become
favorable. Proceeds will also be used to fund day-to-day
operations of Laguna.
At yearend, the Company had a working capital deficit of
$1,764,000 compared to working capital of $462,000 at December
31, 1993. The decrease in working capital was caused primarily
by increased accounts payable and accrued expenses of $1,497,000.
Accounts payable and accrued expenses increased due to costs
incurred in drilling, reworking and development activities.
Current liabilities also increased as a result of prepaid
drilling advances of $207,000 compared to $103,000 last year.
Accounts receivable increased by $257,000 due to higher joint
interest billing receivables related to invoicing joint interest
partners for enhancement work and the drilling program, partially
offset by lower gas prices on gas sales receivable. Inventory
and other current assets decreased by $16,000.
Further reducing the Company's ability to generate cash flows and
positive working capital were the low gas prices received by the
Company in the fourth quarter. The low prices continued into the
first quarter of 1995. Generally, prices are beyond the control
of the Company and it is limited in its ability to protect its
economic interests from the effect of low prices.
To relieve the working capital deficit, on February 15, 1995, the
Company established a $2,500,000 line of credit with three
private investors. Borrowing under this line of credit bears
interest at 11%, which is payable monthly. The line of credit is
collateralized by certain of the Company's oil and gas properties
and is due February 15, 1998. Amounts available under the line
of credit will also be used to pay for the Company's drilling
activities. As of May 1, 1994, the Company had borrowed
$2,000,000 under the line of credit. Management believes that
the ultimate result of the drilling activities, which are
primarily aimed at oil production, will be to increase cash flow,
thereby reduce the working capital deficit and increase
liquidity. However, drilling activities are subject to numerous
risks, including the risk that no commercially productive oil or
gas reservoirs will be encountered. Also, the sales from
successful drilling activities are affected by prevailing prices
for oil and gas. Hydrocarbon prices can be extremely volatile
and can substantially affect the Company's revenues, cash flows
and working capital. There can be no assurance that the proceeds
from the line of credit and drilling activities will eliminate
the working capital deficit. If they do not, however, the
Company will take other measures to improve its working capital
position. While it has no current intention to do so, management
could reduce expenses through staff layoffs and other means of
expense reduction, sell non-core properties, or obtain additional
financing.
Results of Operations
The following table summarizes the revenues from oil and gas
operations for the following years:
<TABLE>
<CAPTION>
1992 1993* 1994*
<S> <C> <C> <C>
Gas revenues $465,000 $1,028,000 $2,346,000
Gas production (mcf) 417,000 695,000 1,648,000
Average price per mcf $ 1.14 $1.48 $ 1.42
Oil revenues $943,000 $1,033,000 $2,283,000
Oil production (bbl) 50,000 20,000 146,000
Average price per bbl $ 18.99 $ 14.75 $ 15.64
Production and opera-
ating costs per BOE $ 6.72 $ 5.91 $5.23
Depreciation, depletion
and amortization
per BOE $ 2.57 $ 5.13 $5.55
</TABLE>
* Does include 961,000 mcf and 48,000 bbls in 1994 and 70,000 mcf
and 6,000 bbls in 1993 delivered to Enron pursuant to the terms
of the volumetric production payment agreement.
1994 Compared to 1993
The Company used net cash for operating activities of $235,000 in
1994 compared to generating $10,114,000 in 1993. Included in
these losses is depreciation, depletion and amortization of
$2,409,000 and $937,000, respectively. Amortization of deferred
revenue of $2,366,000 in 1994 and $184,000 in 1993 negatively
impacted cash flow from operating activities. A loss of
$1,631,000 was incurred in 1994, $444,000 more than the loss of
$1,187,000 experienced during 1993. In 1993, proceeds from the
volumetric production payment increased cash from operating
activities by $10,002,000. Other non-cash items were $93,000 and
$210,000, in 1994 and 1993, respectively. An increase in
accounts payable and accrued liabilities of $1,549,000 in 1994
increased cash flows from operating activities, whereas increases
in accounts receivable and other assets of $357,000 decreased
available cash flows.
The Company's investing activities used cash flows of $2,081,000
in 1994 compared with $13,056,000 last year. The Company
invested significantly more in reworking, recompleting, drilling
and developing properties in 1994. However, the Company
completed a $22,400,000 acquisition effective January 1, 1993 (of
which $7,343,000 was in the form of a note). The adjusted
purchase price on closing at September 30, 1993 was $20,391,000.
The September 1993 acquisition of producing oil and gas
properties has had a significant impact on the results of the
Company's operations. The results of operations from January 1,
1993 to September 30, 1993 of the acquired properties were
recorded as a reduction of the purchase price.
Financing activities netted cash flows of $1,440,000 in 1994,
mainly due to the sale of the Company's Series B Stock resulting
in net proceeds of $3,774,000. Dividends on the Series B Stock
totaled $228,000. Also impacting cash flows provided by
financing activities was payment of the Company's net profits
interest and accrued interest, a change of $2,075,000 since
yearend. In 1993, financing activities provided cash flows of
$3,683,000, reflecting the sale of $8,940,000 of the Company's
common stock, proceeds from the exercise of options of $278,000,
and the sale of the net profits interest of $1,998,000 which was
reduced by a $120,000 origination fee. Payments on long-term
debt of $31,000 and $70,000 decreased cash provided by financing
activities in 1994 and 1993, respectively.
Exclusive of quantities produced and delivered pursuant to the
Company's volumetric production payment, 1994 oil and gas sales
increased to $2,263,000 from $1,877,000 in 1993, representing a
$386,000 (or 21%) increase. This increase is due primarily to
the September 1993 acquisition, and enhancement and drilling
operations completed. Oil production net to Mallon increased by
28,000 barrels or approximately 40%. Not included in the oil
production totals presented above is 48,000 and 6,000 barrels in
1994 and 1993, respectively, which were delivered to Enron in
accordance with the terms of the volumetric production payment.
Reserve engineering forecasts indicate oil production of 106,000
barrels from proved developed producing reserves in 1995, after
delivery of 37,000 barrels to Enron. These quantities do not
include reserves to be produced from the Company's current
drilling program. Management believes that this drilling program
will provide a substantial increase in oil production in 1995.
Average oil prices increased from $14.75 per barrel in 1993 to
$15.64 per barrel 1994, a 6% increase. Through the first quarter
of 1995, oil prices have continued to increase.
Gas production net to Mallon increased by 62,000 mcf (or 10%) in
1994. Natural gas production delivered to meet the demand of the
volumetric production payment was 961,000 mcf in 1994, thereby
limiting the net amount to the Company (70,000 mcf were delivered
in 1993). Further, production was curtailed in the Company's
Burns Ranch area, further reducing gas production for the
Company's account. Reserve engineering forecasts indicate gas
production of 490,000 mcf from proved developed producing
reserves in 1995, after delivery of 849,000 mcf to Enron.
Average gas prices decreased in 1994 by $.06 per mcf (or 4%).
The decrease in gas prices adversely affects the Company's
potential to generate cash flows. However, prices have risen
since yearend.
Included in total revenues for 1994 is $2,366,000 from the
amortization of the Company's deferred revenues. Deferred
revenues were recorded from the sale of a volumetric production
payment covering approximately 4.3 MMBTU of gas and 215,000
barrels of oil. The deferred revenue is amortized over eight
years as deliveries are made to the purchaser. The Company
delivered approximately 961,000 mcf and 48,000 barrels to Enron
in 1994. The Company incurs all costs related to the production
and delivery of these quantities.
Further limiting the Company's ability to generate cash flows was
the fact that certain of the Company's significant wells,
including the Mobil 12, the White Baby Comm. #1 and #2, the Eddy
21 Federal #1, and the Allied 21 Federal #1 were shut-in during
the first part of 1994 while production enhancement operations
were performed. Also, the South Carlsbad compressor was out of
service during most of the first quarter.
Lease operating expense per equivalent barrel averaged $5.23 in
1994, compared to $5.91 in 1993. The decrease of $.68 (or 12%)
is due primarily to the lower operating costs of the acquired
properties and operational efficiencies employed by the Company's
field personnel. This reduction occurred despite substantial
costs for significant workovers and repairs on the Company's
properties in 1994. The Company is constantly working to improve
operations and decrease operating expense. While total lease
operating expenses may not decrease in 1995, management intends
to continue the decrease in per barrel expense.
There were no sales of gold and silver in 1994 or 1993, and no
sales are expected in the immediate future. The Company
recognized management fees of $81,000 associated with the Newmont
operation in 1993. This agreement expired as of March 31, 1993.
Direct costs related to the mining operation were $169,000 in
1994 and $133,000 in 1993. Laguna has raised approximately
$2,500,000 in early 1995. The proceeds from this offering will
be used to fund the operations of Laguna for a twelve month
period. The program includes additional core drilling to expand
mineable reserves on the Rio Chiquito anomaly located on Laguna's
Costa Rica concessions, and preparation of a bankable feasibility
study for commercial development of Rio Chiquito in anticipation
of making an initial public offering of Laguna stock when market
conditions become favorable. Proceeds will also be used to fund
day-to-day operations of Laguna. The net result should be an
increase in cash flows to the Company in 1995.
Depreciation, depletion and amortization increased to $5.55 per
barrel of oil equivalent for 1994, up from $5.13 in 1993. The
increase of $0.42 (or 8%) reflects a decrease in production in
relation to the underlying reserve base, which declined due to
low yearend gas prices and a significant downward revision as a
result of decreased actual production on one of the Company's
major properties. As of December 31, 1994, the net book value of
the Company's oil and gas properties exceeded the net present
value of the underlying reserves by $916,000. However, oil and
gas prices have increased subsequent to yearend. Applying these
increased prices to yearend oil and gas reserves indicates that
the oil and gas properties were not, in fact, impaired.
Accordingly, the $916,000 impairment was not charged to expense
as of December 31, 1994.
Interest and other expense of $116,000 was down significantly in
1994 ($244,000 was incurred in 1993) as the Company incurred
interest at 15% on its net profits interest in 1993. The net
profits interest was paid in April 1994. However, the Company
has a $2,500,000 line of credit established in 1995, which bears
interest at 11%. Accordingly, management expects interest
expense to increase in 1995.
Total general and administrative costs were $1,806,000 in 1994,
an increase of $623,000 (or 53%) over the $1,183,000 for 1993.
The increase is due primarily to increased salary expense for
additional personnel directly related to the September 1993
acquisition. Legal fees increased dramatically, as the Company
was plaintiff in a complex lawsuit in which it sought substantial
damages. Travel expenses increased significantly due the effort
in pursuing the realization of the mining property. The Company
had anticipated general and administrative expenses of
approximately $1,500,000 for 1994. The entire overrun was due
almost exclusively to legal expenses of $360,000. The Company
has budgeted general and administrative expenses of approximately
$1,600,000 for 1995.
The factors discussed above combined to result in a net loss of
$1,631,000 for 1994, compared to a net loss of $1,187,000 for
1993. This represents a $444,000 (or 37%) decrease in the
Company's profitability.
The Company paid the 8% dividend on its $4,000,000 face value
Series B Stock. This amount totaled $228,000 for the period from
April 16, 1994 to December 31, 1994. The annual dividend is
$320,000, payable quarterly.
1993 Compared to 1992
The Company's revenues increased for 1993 to $2,391,000 from
$1,977,000 in 1992 as a result of increased production, which is
in turn attributable to having the Pennzoil Properties on
production for the fourth quarter. Mining revenues decreased as
a contract expired in March 1993 and only three months of mining
management fees were earned for the year.
Lease operating expense per equivalent barrel averaged $5.91
during 1993 compared to $6.72 for 1992. This improvement is
primarily attributable to the lower operating costs of the
Pennzoil Properties included in the operating results for the
fourth quarter.
Depreciation, depletion and amortization totaled $937,000 in
1993, up $583,000 or 165% from the prior year. This increase,
which was expected, was the result of increased production and an
increased depletion base.
General and administrative expenses also increased, as was
expected, due to the acquisition of the Pennzoil Properties. The
increase of $292,000 was due largely to an increase in non-cash
compensation paid to employees, consultants and directors of
$44,000, an increase in salaries, bonuses and related taxes and
benefits of $100,000, and an increase in professional fees of
$40,000.
The 1993 net loss increased to $1,187,000 from a loss of $268,000
in 1992. The increased loss resulted because the increased
revenues were more than offset by an increase in expenses,
especially depreciation, depletion and amortization and interest
expense.
Miscellaneous
The Company's oil and gas operations are significantly affected
by certain provisions of the Internal Revenue Code of 1986 (the
"Code") applicable to the oil and gas industry. Current law
permits the Company to deduct currently, rather than capitalize,
intangible drilling and development costs incurred or borne by
it. The Company, as an independent producer, is 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 by it (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 the Company's taxable income.
Any depletion disallowed under the 65% limitation, however, may
be carried over indefinitely.
At December 31, 1994, the Company had a net operating loss
("NOL") carryforward of approximately $7,000,000, which will
begin to expire in 2005. The amount and availability of an NOL
carryforward is subject to a variety of interpretations and
restrictions. Under a provision of the Code, a corporation's
ability to utilize an NOL carryforward to offset income following
an "ownership change" is limited. If an ownership change occurs,
the ability of the Company to use its NOL carryforward will be
limited so that a portion of the Company's NOL carryforward will
not be available to offset the Company's taxable income in a
particular year. Management is not aware of any such ownership
change.
The Company has in the past and may in the future engage in
hedging transactions (transactions in which a portion of the
Company's future oil and/or gas production is sold into the
futures market) when management believes it is in the Company's
interest to do so. Such transactions "lock-in" prices, thus
protecting against future price downturns, but they also limit
the Company's ability to benefit from future price increases.
Inflation has not historically had a material impact on the
Company's financial statements, and management does not believe
that the Company will be materially more or less sensitive to the
effects of inflation than other companies in the oil and gas
business.
In February 1992, the Financial Accounting Standards Board
released Statement of Financial Accounting Standard (SFAS) No.
109, "Accounting for Income Taxes," which requires an asset and
liability approach for financial accounting and reporting for
income taxes. The new standard was adopted by the Company in
fiscal 1993. The impact of SFAS No. 109 on the Company's
consolidated financial statements was immaterial. At December
31, 1994 the Company has a net deferred tax asset of $963,000,
for which a valuation allowance for an equal amount was
established.
Item 14. Exhibits, Financial Statements, and Reports on Form 8-K
(a) The following documents are filed as part of this Annual
Report on Form 10-K:
1. Financial Statements: See the accompanying "Index of
Consolidated Financial Statements" at page F-1.
2. Exhibits
EXHIBIT INDEX
Sequential
Exhibit Page
Number Document Description Number
*3.01 Articles of Incorporation (1)
*3.02 Bylaws (1)
*3.03 Statement of Designations --
Series A Preferred Stock (4)
*3.04 Statement of Designations --
Series B Preferred Stock (8)
Material Contracts
*10.21 Farmout Agreement among Southland Royalty
Company, Robert L. Bayless and Mallon Oil
Company covering the Burns Ranch Prospect (1)
*10.35 Exploitation Concession Permit #1888 for lands
to be mined at Rio Chiquito (2)
*10.38 Overseas Private Investment Corporation,
Contract of Insurance (3)
*10.1.1 Stock Purchase Agreement dated December 22, 1989 (4)
*10.1.2 Shareholders Agreement dated December 28, 1989 (4)
*10.48 Purchase and Sale Agreement between Pennzoil
Exploration and Production Company and the
Company dated June 3, 1993 (6)
*10.51 Purchase and sale agreement between Mallon Oil
Company and Enron Reserve Acquisition Corp. (6)
*10.52 Production and Delivery Agreement between Mallon
Oil and Enron (6)
*10.53 Conveyance of Overriding Royalty from Mallon
Oil to Enron (6)
*10.54 Assignment of Overriding Royalty from Mallon
Oil to Cactus Hydrocarbons (6)
10.55 Loan Agreement dated February 15, 1995 45
Executive Compensation Plans and Arrangements
*10.1.3 Equity Participation Plan,
amended November 2, 1990 (5)
*10.1.4 Stock Compensation Plan for Outside Directors (7)
Consents
23.1 Consent of Price Waterhouse LLP 82
23.2 Consent of Hein + Associates LLP 83
__________________________
* The exhibit numbers are the exhibit numbers assigned in the
previous filings with the Securities and Exchange Commission,
which are identified in the notes below.
(1) Incorporated by reference from Mallon Resources
Corporation Exhibits to Registration Statement on Form S-4 (SEC
File No. 33-23076) filed on August 15, 1988.
(2) Incorporated by reference from Mallon Minerals Corporation
(Commission File No. 0-11673) Form 10-K for fiscal year ended
February 28, 1986.
(3) Incorporated by reference from Mallon Minerals Corporation
(Commission File No. 0-11673) Form 10-K for fiscal year ended
February 28, 1987.
(4) Incorporated by reference from Mallon Resources
Corporation (Commission File No. 0-17267) Form 8-K filed on
January 8, 1990.
(5) Incorporated by reference from Mallon Resources
Corporation (Commission File No. 0-17267) Form 10-K for fiscal
year ended December 31, 1990.
(6) Incorporated by reference from Mallon Resources
Corporation Exhibits to Registration Statement on Form S-3 (SEC
File No. 33-65846) filed on July 12, 1993.
(7) Incorporated by reference from Mallon Resources
Corporation Exhibits to Registration Statement on Form S-8 (SEC
File No. 33-39635) filed on March 28, 1991.
(8) Incorporated by reference from Mallon Resources
Corporation (Commission File No. 0-17267) Form 8-K filed on April
15, 1994.
Index of Consolidated Financial Statements
Page
Independent Auditors' Reports F-2
Consolidated Balance Sheets F-4
Consolidated Statements of Operations F-6
Consolidated Statements of Stockholders' Equity F-7
Consolidated Statements of Cash Flows F-8
Notes to Consolidated Financial Statements F-9
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Mallon Resources Corporation
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects,
the financial position of Mallon Resources Corporation and its
subsidiaries at December 31, 1994 and 1993, and the results of
their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles. These
consolidated financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion
on these financial statements based on our audits. We conducted
our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for the opinion expressed above.
As discussed in Note 1, the Company restated its 1994
consolidated financial statements related to accounting for its
Series B Mandatorily Redeemable Convertible Preferred Stock.
As of December 31, 1994, the Company had a net investment in
mineral properties and equipment of approximately $4,500,000.
The ability of the Company to recover this investment is
dependent upon achieving and maintaining profitable operations at
the mine or sale of the property. Management's plans in this
regard are discussed in Note 3.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Denver, Colorado
May 5, 1995
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors and Shareholders of
Mallon Resources Corporation
We have audited the accompanying consolidated statements of
operations, stockholders' equity and cash flows for the year
ended December 31, 1992. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the results of
operations and cash flows of Mallon Resources Corporation and
subsidiaries for the year ended December 31, 1992, in conformity
with generally accepted accounting principles.
/s/ HEIN + ASSOCIATES LLP
HEIN + ASSOCIATES LLP
Certified Public Accountants
Denver, Colorado
March 12, 1993
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
1993 1994
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 964,000 $ 88,000
Accounts receivable, with no
allowance for doubtful accounts:
Joint interest participants 229,000 490,000
Related parties 13,000 15,000
Oil and gas sales 636,000 551,000
Other ----- 79,000
Inventories 24,000 30,000
Other 111,000 89,000
Total current assets 1,977,000 1,342,000
Property and equipment:
Oil and gas properties,
under full cost method 38,885,000 41,127,000
Mining properties and equipment 4,832,000 4,888,000
Other equipment 294,000 375,000
44,011,000 46,390,000
Less accumulated depreciation,
depletion and amortization (17,425,000) (19,834,000)
26,586,000 26,556,000
Other assets:
Notes receivable, related parties 41,000 43,000
Other, net 169,000 285,000
Total Assets $28,773,000 $ 28,226,000
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and current portion
of long-term debt $ 10,000 $ -----
Trade accounts payable 1,354,000 2,837,000
Deferred revenues and drilling
advances 103,000 207,000
Accrued taxes and expenses 48,000 62,000
Total current liabilities 1,515,000 3,106,000
Notes payable 20,000 -----
Drilling advances 316,000 315,000
Net profits interest 2,075,000 -----
Deferred revenues 9,818,000 7,452,000
Commitments and contingencies (Note 7)
Series B Mandatorily Redeemable Convertible
Preferred Stock, $0.01 par value,
500,000 shares authorized, 0 and
400,000 shares issued and outstanding,
respectively, liquidation preference
and mandatory redemption of $4,000,000 ----- 3,804,000
Stockholders' equity:
Series A Preferred Stock, $0.01 par
value, 1,467,890 shares authorized,
1,100,918 shares issued and outstanding,
liquidation preference $6,000,000 5,730,000 5,730,000
Common Stock, $0.01 par value,
25,000,000 shares authorized;
7,597,725 and 7,672,503 shares
issued and outstanding, respectively 76,000 77,000
Additional paid-in capital 38,547,000 38,727,000
Accumulated deficit (29,324,000) (30,985,000)
Total stockholders' equity 15,029,000 13,549,000
Total Liabilities and Stockholders'
Equity $ 28,773,000 $ 28,226,000
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
For the Years Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Revenues:
Oil and gas sales $1,408,000 $1,877,000 $2,263,000
Deferred revenue amortization ----- 184,000 2,366,000
Mining management fee 324,000 81,000 -----
Operating service revenue 145,000 201,000 347,000
Interest and other 99,000 48,000 106,000
1,976,000 2,391,000 5,082,000
Costs and expenses:
Oil and gas production 800,000 1,076,000 2,197,000
Mine operating expense 171,000 133,000 169,000
Depreciation, depletion and
amortization 354,000 937,000 2,409,000
General and administrative 891,000 1,183,000 1,806,000
Interest and other 28,000 249,000 132,000
2,244,000 3,578,000 6,713,000
Net loss before preferred
dividends (268,000) (1,187,000) (1,631,000)
Dividends on preferred stock
and accretion ----- ----- (258,000)
Net loss available to common
stockholders $ (268,000) $(1,187,000) $(1,889,000)
Net loss per share of common stock $ (.06) $ (0.22) $ (0.25)
Weighted average shares outstanding 4,781,000 5,471,000 7,664,000
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Series A Additional
Preferred Stock Common Stock Paid-in Accumulated
Shares Amount Shares Amount Capital Deficit Total
(000's) (000's) (000's) (000's) (000's)
<S> <C> <C> <C> <C> <C> <C> <C>
Balances 1/1/92 1,100,918 $5,730 4,679,801 $ 47 $28,737 $(27,869) $6,645
Private placement
of common stock ----- ----- 100,000 1 212 ----- 213
Stock issued for
consulting fees ----- ----- 7,500 -- 19 ----- 19
Employee stock options
exercised ----- ----- 30,500 -- ----- ----- -----
Stock issued to directors ----- ----- 23,226 -- ----- ----- -----
Stock to be issued to
directors ----- ----- ----- -- 8 ----- 8
Employee stock options
granted ----- ----- ----- -- 121 ----- 121
Net loss ----- ----- ----- -- -- (268) (268)
Balances 12/31/92 1,100,918 5,730 4,841,027 48 29,097 (28,137) 6,738
Private placement
of common stock ----- ----- 2,213,888 22 8,918 ----- 8,940
Stock options exercised ----- ----- 100,000 1 261 ----- 262
Employee stock options
exercised ----- ----- 3,240 -- 16 ----- 16
Stock issued to directors ----- ----- 1,570 -- 8 ----- 8
Stock issued for FGC ----- ----- 400,000 4 (105) ----- (101)
Stock issued for property
and equipment ----- ----- 30,000 1 150 ----- 151
Options exercised for
services ----- ----- 8,000 -- 33 ----- 33
Stock issued to directors ----- ----- ----- -- 4 ----- 4
Employee stock options
granted ----- ----- ----- -- 165 ----- 165
Net loss ----- ----- ----- -- ----- (1,187) (1,187)
Balances 12/31/93 1,100,918 5,730 7,597,725 76 38,547 (29,324) 15,029
Employee stock options
exercised ----- ----- 5,000 -- ----- ----- -----
Stock issued to directors ----- ----- 3,078 -- 11 ----- 11
Stock issued for property
and equipment ----- ----- 66,700 1 299 ----- 300
Employee stock options
granted ----- ----- ----- -- 32 ----- 32
Other ----- ----- ----- -- 66 ----- 66
Dividends on preferred
stock ----- ----- ----- -- (228) ----- (228)
Accretion on preferred
stock ----- ----- ----- -- ----- (30) (30)
Net loss ----- ----- ----- -- ----- (1,631) (1,631)
Balances 12/31/94 1,100,918 $5,730 7,672,503 $77 $38,727 $(30,985) $13,549
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Years Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $(268,000) $(1,187,000) $(1,631,000)
Adjustments to reconcile net loss
to net cash provided by (used in)
operating activities:
Depletion, depreciation and
amortization 354,000 937,000 2,409,000
Stock issued for compensation 148,000 210,000 43,000
Amortization of deferred revenues ----- (184,000) (2,366,000)
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable (13,000) (607,000) (257,000)
Inventories 10,000 ----- (6,000)
Other assets 42,000 (117,000) (94,000)
Increase (decrease) in:
Accounts payable (241,000) 963,000 1,549,000
Accrued taxes and expenses 15,000 105,000 14,000
Deferred revenues and
drilling advances ----- (8,000) 104,000
Proceeds from volumetric
production payment ----- 10,002,000 -----
Net cash provided by (used in)
operating activities 47,000 10,114,000 (235,000)
Cash flows from investing activities:
Increase in notes receivable -
related party (7,000) (8,000) (2,000)
Additions to property and equipment (190,000) (13,048,000) (2,079,000)
Proceeds from sale of oil and gas
properties and other 108,000 ----- -----
Net cash used in investing activities (89,000) (13,056,000) (2,081,000)
Cash flows from financing activities:
Payments on long-term debt (219,000) (70,000) (31,000)
Payments of note payable ----- (7,343,000) -----
Proceeds from sale of net profits
interest ----- 1,998,000 -----
Payments on net profits interest ----- ----- (2,075,000)
Payment of origination fee for
net profits interest ----- (120,000) -----
Net proceeds from private placement
of common stock 213,000 8,940,000 -----
Proceeds from stock options exercised ----- 278,000 -----
Issuance of preferred stock, net ----- ----- 3,774,000
Payment of preferred dividends ----- ----- (228,000)
Net cash (used in) provided by
financing activities (6,000) 3,683,000 1,440,000
Net increase (decrease) in cash
and cash equivalents (48,000) 741,000 (876,000)
Cash and cash equivalents,
beginning of year 271,000 223,000 964,000
Cash and cash equivalents, end of year $ 223,000 $ 964,000 $ 88,000
Supplemental cash flow information:
Cash paid for interest $ 30,137 $ 93,271 $ 175,000
Cash paid for income taxes $ ----- $ ----- $ -----
Non-cash transactions:
Note payable exchanged for oil
and gas property ----- $7,343,000 -----
Issuance of common stock in exchange for:
Acquisition of FGC, net of
$70,000 property acquisition ----- (101,000) -----
Acquisition of property and
equipment ----- 151,000 $300,000
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
Organization:
Mallon Resources Corporation (the "Company" or "MRC") was
incorporated on July 18, 1988 under the laws of the State of
Colorado. The Company had no significant business activity until
December 21, 1988 when the combination of two companies and 19
limited partnerships into MRC became effective (the
"Consolidation"). The participants in the Consolidation were
Mallon Oil Company ("MOC"), a privately held Colorado
corporation, Mallon Minerals Corporation (which is now known as
Laguna Gold Company ("LGC")), a publicly held Colorado
corporation, 15 Colorado limited partnerships for which MOC
served as a general partner and four Colorado limited
partnerships for which LGC served as a general partner.
Effective December 21, 1988, the Company issued shares of its
$0.01 par value common stock in exchange for all of the shares of
MOC and LGC and for the net assets of all of the partnerships.
Principles of Consolidation:
The consolidated financial statements include the accounts of
MOC, LGC, and all of their wholly owned subsidiaries. All
significant intercompany transactions and accounts have been
eliminated from the consolidated financial statements.
Cash Equivalents:
Cash equivalents include amounts which are readily
convertible into cash and have an original maturity of three
months or less, such as bankers acceptances, certificates of
deposit, and commercial paper.
Inventories:
Inventories, which are composed of oil and gas lease and well
equipment, and mining materials and supplies, are valued at the
lower of average cost or estimated net realizable value.
Oil and Gas Properties:
Oil and gas properties are accounted for using the full cost
method of accounting. Under this method, all costs associated
with property acquisition, exploration and development are
capitalized. All such costs are in one cost center, the
continental United States. Costs incurred on foreign oil and gas
properties are not material.
Proceeds on disposal of properties are ordinarily accounted
for as adjustments of capitalized costs, with no profit or loss
recognized, unless such adjustment would significantly alter the
relationship between capitalized costs and proved oil and gas
reserves. Costs capitalized net of accumulated depreciation,
depletion and amortization, and the deferred revenue from the
volumetric production payment, cannot exceed the estimated future
net revenues, net of the related income tax effects, discounted
at 10%, of the Company's proved reserves.
Depletion is calculated using the units-of-production method
based upon the ratio of current period production to estimated
proved oil and gas reserves expressed in physical units, with oil
and gas converted to a common unit of measure on the basis of
their relative energy content.
Estimated abandonment costs (including estimated plugging,
site restoration, and dismantlement expenditures) are accrued if
the estimated costs exceed estimated salvage values, as
determined using current market values and other information.
Abandonment costs are estimated based primarily on environmental
and regulatory requirements in effect from time to time. As of
December 31, 1994, estimated salvage values equaled or exceeded
estimated abandonment costs.
Mineral Properties and Equipment:
The Company expenses general prospecting costs as incurred
while the costs of acquiring and exploring unproved mining
properties are capitalized, pending a decision as to the
commercial profitability of projects. Costs of subsequent
development of mining operations are deferred. When commercially
profitable ore reserves are developed, deferred costs are
amortized when operations commence using the units-of-production
method based on the estimated tons of ore to be recovered. Upon
abandonment or sale of projects, all deferred costs relating to
the specific project are expensed in the year abandoned or sold
and the gain or loss is recognized. Proceeds from advanced
royalties are accounted for as adjustments of capital costs, with
no profit or loss recognized.
Mining equipment is depreciated using the units-of-production
method, except during suspended operations. When not in
production, this equipment is depreciated at approximately 2% per
year.
Capitalized costs, net of accumulated depreciation, depletion
and amortization, may not exceed the estimated net realizable
value of the properties, as determined by management on a
quarterly basis. Management estimates net realizable values
based on reserve reports (including informal deposit, resource
and reserve estimates prepared by Company staff), feasibility
studies, engineering data, commodity prices and market trends,
actual or projected mining and operating costs, estimated income,
severance and other taxes, and other information deemed to be
relevant to such estimations. As of December 31, 1994,
capitalized costs were less than estimated net realizable values.
Other Property and Equipment:
Other property and equipment are recorded at cost, and
depreciated over their estimated useful lives (five to seven
years) using the straight-line method. The cost of normal
maintenance and repairs is charged to expense as incurred.
Significant expenditures which increase the life of an asset are
capitalized and depreciated over the estimated useful life of the
asset. Upon retirement or disposition of assets, related gains or
losses are reflected in operations.
Gas Balancing:
The Company uses the entitlements method for recording
natural gas sales revenues. Under the entitlements method of
accounting, revenue is recorded based on the Company's net
working interest in field production. Deliveries of natural gas
in excess of the Company's working interest are recorded as
liabilities while under-deliveries are recorded as receivables.
Intangible Assets:
Intangible assets are recorded at cost and are amortized over
their estimated useful lives using the straight-line method.
Deferred Revenues:
Revenues billed in advance for services are deferred and
recorded in income in the period in which the related services
are rendered. Revenues received in advance of production are
classified as deferred revenue. The deferred revenue is
amortized as production and delivery occur.
Income Taxes:
In fiscal 1993, the Company adopted the provisions of
Statement of Financial Accounting Standards ("SFAS") No. 109,
"Accounting for Income Taxes". SFAS No. 109 requires the
recognition of deferred tax liabilities and assets for the
expected future tax consequences of temporary differences between
the carrying amounts and tax bases of those assets and
liabilities. The adoption of SFAS No. 109 had no impact on the
Company's 1993 consolidated financial statements.
The benefits of tax credits will be reflected as a reduction
of income tax expense in the year in which management determines
that such credits are more likely than not realized.
Management Fees:
Management fees received in connection with oil and gas
properties are credited to the full cost pool. All other
management fees are recorded as income when earned.
Foreign Currency Translation:
Management has determined the U.S. dollar to be the
functional currency for Costa Rican operations. Accordingly, the
assets, liabilities and results of operations of the Costa Rican
subsidiaries are measured in U.S. dollars. Transaction gains and
losses are not material for any of the periods presented.
Per Share Data:
Per share data is calculated using the weighted average
number of common shares outstanding during each period. Common
equivalent shares are excluded from the calculation because they
are anti-dilutive.
Change in Reporting of Mandatorily Redeemable Convertible
Preferred Stock:
The Company has corrected the accounting for its Mandatorily
Redeemable Convertible Preferred Stock. The balance of such
preferred stock has been reclassified and is now presented outside
the equity section. Further, the Company is recording accretion for
the difference between the net proceeds received and the mandatory
redemption amount of $4,000,000. The effect of this correction was
to reduce stockholder's equity at December 31, 1994 by $3,804,000
and to increase the net loss available to common stockholders and
the net loss per common share for the year ended December 31, 1994
by $30,000 and $.01, respectively.
Note 2. OIL AND GAS PROPERTIES
The Company's oil and gas activities are conducted entirely
in the United States. Although the Company has made a bid for
oil and gas concessions in Costa Rica, no concessions have been
awarded, and the Company has not incurred significant costs to
date. Therefore, all data herein is associated with the
continental United States cost center.
Depletion of oil and gas property costs were $2.57, $5.13 and
$5.55 per equivalent barrel of oil production for the years ended
December 31, 1992, 1993, and 1994, respectively.
In March 1993, the Company signed a letter of intent for the
purchase of interests in certain properties for $23 million. On
September 30, 1993, the Company closed the transaction for an
adjusted purchase price of approximately $19,300,000. The
purchase price was paid through the sale of a volumetric
production payment for net proceeds of $10,002,000, the sale of a
net profits interest for $1,998,000, which was repaid in April
1994, and a note payable to the seller of $7,343,000, which was
paid in November 1993.
The operations of the acquired properties have been included
with the Company's accompanying consolidated statements of
operations, beginning October 1, 1993. The following represents
the unaudited pro forma results of operations for the year ended
December 31, 1993, assuming the acquisition had taken place as of
January 1, 1993:
Total revenues $6,006,000
Net loss available to common stockholders $ (242,000)
Earnings per share $ (.03)
Capitalized Costs Relating to Oil and Gas Activities:
<TABLE>
<CAPTION>
December 31,
1992 1993 1994
<S> <C> <C> <C>
Oil and gas properties $ 18,668,000 $ 38,885,000 $ 41,127,000
Accumulated depreciation,
depletion and
amortization (15,798,000) (16,863,000) (19,011,000)
2,870,000 22,022,000 22,116,000
Deferred revenues attri-
butable to the volumetric
production payment ----- (9,818,000) (7,452,000)
$ 2,870,000 $ 12,204,000 $ 14,664,000
</TABLE>
The Company does not have significant costs of unproved
properties or costs excluded from the full cost pool amortization
base. As of December 31, 1994, the net book value of the
Company's oil and gas properties exceeded the net present value
of the underlying reserves by $906,000. However, oil and gas
prices increased subsequent to yearend. Applying these increased
prices to yearend oil and gas reserves indicates that the oil and
gas properties were not, in fact, impaired. Accordingly, the
$906,000 impairment was not charged to expense as of December 31,
1994.
Costs Incurred in Oil and Gas Producing Activities:
<TABLE>
<CAPTION>
For the Year Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Property acquisition
costs $ 34,000 $16,919,000 $ 721,000
Exploration costs 31,000 144,000 325,000
Development costs 99,000 3,174,000 1,477,000
Full cost pool credits (103,000) (21,000) (142,000)
$ 61,000 $20,216,000 $2,381,000
</TABLE>
Results of Operations from Oil and Gas Producing Activities:
<TABLE>
<CAPTION>
For the Year Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Oil and gas sales $1,408,000 $ 1,877,000 $2,263,000
Deferred revenue amortization ----- 184,000 2,366,000
Lease operating expense (800,000) (1,076,000) (2,197,000)
Depreciation, depletion and
amortization (283,000) (874,000) (2,330,000)
Results of operations - from
producing activities (excluding
corporate overhead, interest
and income taxes) $ 325,000 $ 111,000 $ 102,000
</TABLE>
Estimated Quantities of Proved Oil and Gas Reserves (unaudited):
Set forth below is a summary of the changes in the net
quantities of the Company's proved crude oil and natural gas
reserves estimated by an independent consulting petroleum
engineering firm for the years ended December 31, 1992, 1993, and
1994. All of the Company's reserves are located in the
continental United States.
<TABLE>
<CAPTION>
Oil Gas
(BBLS) (MCF)
Proved Reserves
<S> <C> <C>
Reserves, January 1, 1992 374,000 11,905,000
Extensions, discoveries and additions 22,000 147,000
Production (50,000) (417,000)
Revisions (9,000) (743,000)
Reserves, December 31, 1992 337,000 10,892,000
Acquisition of reserves in place 855,000 14,967,000
Sale of reserves in place (215,000) (3,626,000)
Extensions, discoveries and additions 8,000 20,000
Production (64,000) (625,000)
Revisions (62,000) 708,000
Reserves, December 31, 1993 859,000 22,336,000
Extensions, discoveries and additions 664,000 448,000
Production (98,000) (858,000)
Revisions 119,000 (5,632,000)
Reserves, December 31, 1994 1,544,000 16,294,000
</TABLE>
Much of the downward revision in total gas reserves in 1994
is attributable to a 27% decrease in gas prices and a significant
downward revision as a result of decreased actual production on
one of the Company's major properties.
<TABLE>
<CAPTION>
Oil Gas
(BBLS) (MCF)
Reserves attributable to the volumetric production payment
(not included above)
<S> <C> <C>
December 31, 1993 209,000 3,575,000
December 31, 1994 162,000 2,938,000
Proved Developed Reserves
December 31, 1992 231,000 6,495,000
December 31, 1993 602,000 17,999,000
December 31, 1994 811,000 11,733,000
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
(unaudited):
The following summary sets forth the Company's unaudited
future net cash flows relating to proved oil and gas reserves
based on the standardized measure prescribed in Statement of
Financial Accounting Standards No. 69:
<TABLE>
<CAPTION>
For the Year Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Future cash in-flows $ 23,170,000 $ 61,012,000 $ 50,964,000
Future production and
development costs (12,727,000) (27,075,000) (28,435,000)
Future income taxes (1,645,000) (1,701,000) -----
Future net cash flows 8,798,000 32,236,000 22,529,000
Discount at 10% (4,373,000) (14,048,000) (8,771,000)
Standardized measure of
discounted future net
cash flows $ 4,425,000 $ 18,188,000 $ 13,758,000
</TABLE>
Future net cash flows were computed using yearend prices and
yearend statutory income tax rates (adjusted for permanent
differences and tax credits) that relate to existing proved oil
and gas reserves in which the Company has an interest.
The following are the principal sources of changes in the
standardized measure of discounted future net cash flows:
<TABLE>
<CAPTION>
For the Year Ended December 31,
1992 1993 1994
<S> <C> <C> <C>
Standardized measure,
beginning of year $ 5,162,000 $ 4,425,000 $18,188,000
Net revisions to previous
quantity estimates and
other (267,000) (2,826,000) (4,696,000)
Extensions, discoveries,
additions, and changes
in timing of production,
net of related costs 276,000 85,000 3,959,000
Purchase of reserves in
place ----- 27,485,000 -----
Sales of reserves in place ----- (10,002,000) -----
Increase in future development
costs (142,000) (906,000) (1,065,000)
Sales of oil and gas produced,
net of production costs (608,000) (985,000) (66,000)
Net change in prices and
production costs (1,051,000) 602,000 (5,341,000)
Accretion of discount 516,000 443,000 1,819,000
Net change in income taxes 539,000 (133,000) 960,000
Standardized measure,
end of year $ 4,425,000 $18,188,000 $13,758,000
</TABLE>
Reserves to be delivered pursuant to the Company's volumetric
production payment discussed in Note 6 are excluded from the SFAS
No. 69 calculations presented herein. Accordingly, the
standardized measure of discounted future net cash flows, which
is cash flow based, does not include deferred revenues to be
amortized as production and delivery occurs in the future.
However, all costs related to such production and delivery, which
is a commitment of the Company, are included.
There are numerous uncertainties inherent in estimating
quantities of proved oil and gas reserves and in projecting the
future rates of production, particularly as to natural gas, and
timing of development expenditures. Such estimates involve the
use of judgments which may not be realized due to curtailment,
shut-in conditions and other factors which cannot be accurately
determined. The above information represents estimates only and
should not be construed as the current market value of the
Company's oil and gas reserves or the costs that would be
incurred to obtain equivalent reserves.
Note 3. MINERAL PROPERTIES
The Company's principal precious metals property is the Rio
Chiquito project located in Guanacaste Province, Costa Rica. The
net book value of the mineral properties and equipment was
approximately $4,500,000 at December 31, 1994. The Company,
through its subsidiary LGC, holds 12 exploration concessions and
one exploitation concession covering approximately 182 square
kilometers or about 45,000 acres. A 2% gross royalty on
production from the Rio Chiquito is reserved for the government
of Costa Rica. Sunshine Mining Corp. owns a 5% net profits
interest. LGC believes that it has valid rights to the Rio
Chiquito concessions, and that all necessary exploration work has
been performed.
In 1984, LGC began active exploration and evaluation of the
Rio Chiquito prospect. In April 1987, construction of a small
open pit mine and pilot project processing facility commenced.
Mining and leaching operations began in October 1987 and the
first shipment of gold and silver concentrate occurred in January
1988. Subsequently, LGC experienced negative cash flow from
operations due to low volume of ore processed and the resulting
high unit operating cost. LGC suspended mining operations
effective July 1, 1989 and continuous recovery operations were
terminated in October 1989.
In order to achieve profitable operations, management
believes that an additional capital investment is required for
equipment and improvements which would increase production rates
and lower unit costs. Such equipment and improvements would
include additional mining equipment, installation of permanent
electricity, and improvements to the processing facilities.
During the mine shutdown period, the Company pursued discussions
with several possible joint venture partners for a possible joint
exploration and development program and, on January 3, 1992, the
Company signed an agreement with Newmont Mining Corporation
whereby Newmont had certain rights to explore and develop the Rio
Chiquito gold mine. For these rights, Newmont agreed to expend
$1.3 million on the property. Newmont carried out a core drill
program and geochemical sampling program before their agreement
ended December 31, 1992. The Newmont agreement was terminated as
of December 31, 1992; however, Newmont agreed to continue paying
to the Company the $30,000 per month management fee called for
under the venture agreement through March 1993. After Newmont's
withdrawal, the project is owned 90% by the Company and 10% by
Red Rock Ventures, Inc. ("Red Rock"). As part of the joint
venture agreement, the owner of Red Rock bought 50,000 shares of
the Company's common stock at $2.00 per share and 50,000 shares
at $2.25 per share, and had options to buy 50,000 shares for
$2.50 per share (which were exercised in March 1993) and 50,000
shares for $2.75 per share in 1993 (which were exercised in
September 1993).
On January 6, 1993, Mallon signed a letter agreement with
Polymet Resources Corporation (Polymet), a subsidiary of Minproc
Corporation, to carry out a feasibility study on the Rio Chiquito
mine. The scope of this project was to study the ore body, the
metallurgy of the ore, design an appropriate recovery system and
present this information in an appropriate manner to help secure
financing to open the mine and construct the proper processing
facility. For this work, Polymet was to receive an ownership
interest in the mine. That agreement expired. Subsequent to
December 31, 1994, the Company and Polymet completed an agreement
under which the Company paid Polymet $200,000 in exchange for
Polymet's delivery to the Company of all studies, reports, data,
and other information Polymet obtained in connection with the
original feasibility study.
Subsequent to yearend, the Company privately placed 25,000
shares of LGC's Series A Convertible Preferred Stock for
$2,500,000. The shares of Series A Preferred Stock are
convertible into 20% of LGC's common stock. The net effect of
this sale is that the Company will retain an 80% equity stake in
LGC. Each share of Series A Preferred Convertible Stock includes
10 detachable warrants; each warrant represents the right to
purchase one share of the Company's common stock at $2.50 per
share. The warrants expire on February 15, 2000. Each share of
Series A Convertible Preferred Stock can be converted into 100
shares of LGC $.01 par value common stock at the option of the
stockholder, or automatically in the event of a public offering
of the common stock. The private placement is scheduled to close
May 31, 1995.
Note 4. NOTES PAYABLE AND LONG-TERM DEBT
Effective April 18, 1988, LGC purchased certain ore crushing
and handling equipment under a note agreement with an original
principal balance of $91,000. The balance at December 31, 1993
of $30,000 was paid during 1994.
On September 30, 1993, the Company purchased certain oil and
gas properties. The purchase price was paid in part by delivery
of a promissory note in the principal amount of $7,343,000. The
principal and accrued interest (8%) thereon was paid on November
24, 1993. As part of the financing of the acquisition, the
Company sold a net profits interest (the "NPI") that provided
that 80% of the net revenues generated from the acquired
properties (exclusive of production delivered in satisfaction of
the Production Payment described in Note 6) were payable until
such payments aggregated $1,998,000, plus interest thereon equal
to 15% per annum. The NPI and accrued interest (a total of
$2,152,000) was retired in April 1994.
On February 15, 1995, the Company established a $2,500,000
line of credit pursuant to a loan agreement with three private
investors. Borrowings under this line of credit, which totaled
$2,000,000 as of May 1, 1995, bear interest at 11%, which is due
and payable monthly. The line of credit is collateralized by
certain of the Company's oil and gas properties and is due
February 15, 1998.
Note 5. DRILLING ADVANCES
In 1988 the Company sold a portion of its working interest in
seven proved developed and various undeveloped gas properties
located in the Burns Ranch Field to a group of related and
unrelated investors. Proceeds from the sale were divided between
acquisition costs and future drilling and completion costs which
were recorded in the books under current liabilities as deferred
revenues and drilling advances.
Because gas prices are low and excess gas supplies exist, the
Company has no current plans to drill in this area in 1995.
Therefore, approximately 75% of these proceeds, which were
advanced as turnkey drilling contracts payments, have been
classified as long-term debt at December 31, 1993 and 1994.
Note 6. DEFERRED REVENUE
In connection with the Company's September 30, 1993
acquisition of producing oil and gas properties, the Company sold
a volumetric production payment payable out of the Company's
interest in the acquired properties for net proceeds of
$10,002,000.
The production payment covers approximately 4,354,000 MMBTU
of natural gas at an average price of $1.98 and 215 MBbls barrels
of oil at an average price of $13.01 per barrel to be delivered
over eight years. The Company is responsible for production
costs associated with operating the properties subject to the
production payment agreement. The amount received is recorded as
deferred revenue. Annual amortization of deferred revenue, based
on the scheduled remaining deliveries under the production
payment agreement is as follows:
<TABLE>
<CAPTION>
Scheduled Deliveries
Annual Natural Gas Oil
Amortization (MCF) (Bbl)
<S> <C> <C> <C>
1995 $ 2,029,000 849,000 37,000
1996 1,485,000 614,000 28,000
1997 1,168,000 457,000 26,000
1998 943,000 351,000 23,000
1999 751,000 275,000 19,000
2000 611,000 223,000 16,000
2001 465,000 169,000 12,000
$7,452,000 2,938,000 161,000
</TABLE>
Note 7. COMMITMENTS AND CONTINGENCIES
Operating Leases:
The Company leases office space under non-cancelable leases
which expire October 1997. Rental expense is recognized on a
straight-line basis over the term of the lease. The Company has
no other lease agreements that have initial or remaining non-
cancelable lease terms in excess of one year. The total minimum
rental commitments at December 31, 1994 are as follows:
<TABLE>
<CAPTION>
<S> <C>
1995 $ 81,000
1996 81,000
1997 68,000
$ 230,000
</TABLE>
Rent expense was $56,000, $56,000 and $74,000 for the years
ended December 31, 1992, 1993, and 1994, respectively.
Benefit Plans:
Effective January 1, 1989, the Company and its affiliates
established the Mallon Resources Corporation 401(k) Profit
Sharing Plan (the "401(k) Plan"). MRC and its affiliates match
an employee's contribution to the 401(k) Plan in an amount up to
25% of his or her eligible monthly contributions. The Company
may also contribute additional amounts at the discretion of the
Compensation Committee of the Board of Directors, contingent upon
realization of earnings by the Company which, in the sole
discretion of the Compensation Committee, are adequate to justify
a corporate contribution. For the years ended December 31, 1992,
1993 and 1994, the Company made $4,000, $6,000 and $8,000,
respectively, of matching contributions and no discretionary
contributions.
The Company maintains a plan to provide additional
compensation to employees from lease revenues which are included
in a pool to be distributed at the discretion of the Chairman of
the Board. For the years ended December 31, 1992, 1993 and 1994,
a total of $30,000, $40,000 and $59,000, respectively, was
distributed to employees.
Contingencies:
In 1993, the Minerals Management Service commenced an audit
of royalties payable on certain oil and gas properties in which
the Company owns an interest. The operator of the properties is
contesting certain deficiencies. The audit is not complete, and
it is not possible for the Company to estimate any potential
liability. However, management of the Company does not believe
that the ultimate outcome of this matter will have a material
negative impact on the financial position, liquidity or results
of operations of the Company. This matter has been dormant for
more than a year.
The Company is a defendant in a matter which arises out of an
automobile accident involving one of the Company's employees.
The matter has been referred to the Company's automobile
insurance carrier for defense. The Company does not believe it
will have exposure for damages beyond its insurance coverage
limits.
Note 8. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK
On April 15, 1994, the Company completed the private
placement (the "Placement") of 400,000 shares of its new Series
B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par
value per share ("Series B Stock"). Mandatory redemption of this
stock begins on April 1, 1997, when 20% of the total outstanding
shares will be redeemed. An additional 20% per year will be
redeemed on each April 1 thereafter until all $4,000,000 of the
Series B Stock has been redeemed. The newly created Series B
Stock bears an 8% dividend payable quarterly, and is convertible
into shares of the Company's common stock at a conversion price
of $4.25 per share. Gross proceeds from the Placement were
$4,000,000 and net proceeds were approximately $3,774,000. In
connection with the Series B Stock, dividends of $228,000 were
paid in 1994.
Note 9. CAPITAL
Preferred Stock:
The Board of Directors is authorized to issue up to
10,000,000 shares of preferred stock having a par value of $.01
per share, to establish the number of shares to be included in
each series and to fix the designation, rights, preferences and
limitations of the shares of each series.
The 1,100,919 shares of Series A Preferred Stock are
convertible to common stock of the Company on a share for share
basis at any time at the option of the holder, or automatically
if the common stock of the Company trades at $5.39 per share.
The Series A Preferred Stock provides for a non-cumulative,
preferential dividend only to the extent declared by the
Company's Board of Directors. The Series A Preferred Stock has a
preference on liquidation of $6,000,000 (the original face
value); thereafter, after an equivalent amount has been
distributed to the holders of common stock, it shares
proportionately with the common stock. It has the right to one
vote for each share of common stock into which it could be
converted, with voting powers equal to holders of common stock.
In addition, the Series A Preferred Stock has the right to elect
one director to the Company's Board of Directors. The Series A
Preferred Stock is not redeemable and may not be called.
Common Stock:
The Company has reserved 1,113,173 and 941,177 shares of
common stock for issuance upon a possible conversion of the
Series A and Series B Stock, respectively.
The Company adopted the Mallon Resources Corporation 1988
Equity Participation Plan (the "Equity Plan"). Under the Equity
Plan, 1,000,000 shares of common stock have been reserved in
order to provide for incentive compensation and awards to
employees and consultants. The Equity Plan provides that a three
member committee may grant stock options, awards, stock
appreciation rights, and other forms of stock-based compensation
in accordance with the provisions of the Equity Plan. No grants
or awards were made under the Equity Plan until June 22, 1990.
On June 22, 1990, the Compensation Committee of the Board of
Directors of the Company approved the grant of options for
178,800 shares of the Company's common stock to certain officers
and employees, exercisable at a price of $0.01 per share.
Subsequently, options for 31,560 shares that had not vested were
canceled due to employee resignations. During 1994, an
additional 69,000 options were issued to certain officers and
employees exercisable at a price of $.01 per share, which vest
annually beginning in 1995 through 1999. As of December 31,
1994, options for 112,380 shares were vested and exercisable.
The difference between the exercise price and the estimated fair
value of the shares at the date of grant is charged to
compensation expense with a corresponding increase to
Stockholders' Equity.
Also on June 22, 1990, options exercisable at $.01 per share
for 10 years were granted that do not vest until the market price
of the Company's common stock exceeds certain prices for in
excess of 120 consecutive days, as follows:
Stock Price Aggregate
in excess of: shares covered:
$ 8.00 20,750
$10.00 20,750
$12.00 41,500
Management of the Company reviews the probability of these
options vesting on a quarterly basis. When management believes
it is probable that the stock will reach the required levels for
vesting, it will begin accruing compensation expense based on the
difference between the market price of the stock at that date and
the exercise price. No compensation expense was recorded for
these options during the years ended December 31, 1994, 1993 and
1992. Any difference between the amount of accrued compensation
at the date the stock has attained the required level for 120
consecutive days and the amount accrued will be charged to
operations in that period.
The Board of Directors of the Company approved a Stock
Compensation Plan for outside directors of the Company. This
plan provides that the Company's outside directors (presently
three in number) will be compensated by periodically granting
them shares of the Company's $0.01 par value common stock worth
$1,000 for each board meeting, but no less than $4,000 per year,
for each outside director. The Company has expensed $8,000,
$12,000 and $11,000 for the years 1992, 1993 and 1994,
respectively.
In November 1992, the Company granted to a consultant options
to purchase 50,000 shares at $6.50 per share, exercisable from
November 1993 through October 1997.
During 1992, Red Rock Ventures, Inc. purchased 50,000 shares
of the Company's common stock at $2.00 per share and 50,000
shares at $2.25 per share. During 1993, Red Rock purchased
50,000 additional shares at $2.50 per share and 50,000 shares at
$2.75 per share. Red Rock is the Company's joint venture partner
in the Rio Chiquito project.
In April 1993, the Company sold 200,000 shares of its common
stock for net proceeds of $931,000 in a private placement
offering.
Also in April 1993, the Company issued 30,000 shares of
common stock at $5.00 per share to an existing stockholder in
satisfaction of an obligation relating to the drilling of a well.
In November 1993, the Company completed a private placement
of its common stock, selling 2,013,888 shares at $4.50 per share
resulting in net proceeds of $8,025,000. A registration
statement on Form S-3 was filed, and declared effective in
November 1993, which will permit the investors to sell their
shares without further registration.
In February 1994, the Company issued 66,700 shares of its
common stock to an individual who is a partner in the same law
firm as one of the Company's directors. The Company recorded the
stock at the fair value of the stock on the date of grant of
$300,000. Subsequent to yearend, an additional 56,000 shares,
valued at $112,000, were issued to the same individual. Also
subsequent to yearend, $32,000 was paid to this same individuals
for consulting services provided.
Note 10. MAJOR CUSTOMERS
Sales to customers in excess of 10% of total revenues were:
For the Year Ended December 31,
1992 1993 1994
Customer A $ ----- $222,000 $2,579,000
Customer B 436,000 323,000 298,000
Customer C 283,000 308,000 573,000
Customer D 399,000 302,000 113,000
Note 11. INCOME TAXES
The Company incurred a loss for both book and tax purposes in
1992, 1993, and 1994. There is no income tax benefit (expense)
for the years ended December 31, 1992, 1993 or 1994.
Deferred tax assets (liabilities) are comprised of the following
as of December 31, 1993 and 1994:
<TABLE>
<CAPTION>
1993 1994
<S> <C> <C>
Deferred Assets (Liabilities):
Net operating loss carryforward $ 1,674,000 $ 2,567,000
Accumulated depreciation and
amortization differences 5,127,000 5,355,000
Other 87,000 209,000
Total deferred tax assets 6,888,000 8,131,000
Mining properties basis
differences (1,351,000) (1,312,000)
Oil, gas and other properties
basis differences (5,238,000) (5,856,000)
Total deferred tax liabilities (6,589,000) (7,168,000)
Net deferred tax assets 299,000 963,000
Less valuation allowance (299,000) (963,000)
$ ----- $ -----
</TABLE>
At December 31, 1994, for tax purposes the Company's
remaining net operating loss ("NOL") carryforward was
approximately $6,900,000 which will begin to expire in 2005.
This tax loss carryforward is in addition to net operating losses
arising from the operations of LGC prior to 1989 which can be
utilized only to the extent of future taxable income of LGC, but
limited to consolidated taxable income.
Under the Internal Revenue Code of 1986, as amended (the
"Code"), the Company generally would be entitled to reduce its
future federal income tax liabilities by carrying the unused NOL
forward for a period of 15 years to offset its future income
taxes. The Company's ability to utilize any NOL in future years
may be restricted, however, in the event the Company undergoes an
"ownership change" as defined in the Code. Management is not
aware of any such change.
Note 12. SEGMENT INFORMATION
The Company operates in two business segments, oil and gas
exploration and production in the United States, and gold and
silver mining in Costa Rica. Information regarding total assets
by business segment and geographic location for the Company as of
December 31, 1992, 1993, and 1994 is as follows:
<TABLE>
<CAPTION>
December 31,
1992 1993 1994
<S> <C> <C> <C>
Total assets:
Oil and gas $3,682,000 $24,442,000 $23,746,000
Mining 4,055,000 4,331,000 4,480,000
$7,675,000 $28,773,000 $28,226,000
</TABLE>
<TABLE>
<CAPTION>
December 31,
1992 1993 1994
<S> <C> <C> <C>
United States $3,647,000 $24,375,000 $23,777,000
Costa Rica 4,028,000 4,398,000 4,449,000
$7,675,000 $28,773,000 $28,226,000
</TABLE>
The following tables summarize the Company's revenues,
operating income or loss, depreciation and depletion and capital
expenditures by business segment for years ended December 31,
1992, 1993 and 1994:
<TABLE>
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Revenues:
Oil and gas $1,653,000 $2,310,000 $ 5,082,000
Mining 324,000 81,000 -----
$1,977,000 $2,391,000 $ 5,082,000
Operating income (loss):
Oil and gas $ (322,000) $(1,090,000) $(1,427,000)
Mining 54,000 (97,000) (204,000)
$ (268,000) $(1,187,000) $(1,631,000)
Depreciation, depletion and amortization:
Oil and gas $ 350,000 $ 893,000 $ 2,389,000
Mining 4,000 44,000 36,000
$ 354,000 $ 937,000 $ 2,425,000
Capital expenditures:
Oil and gas $ 173,000 $20,326,000 $ 2,322,000
Mining 17,000 313,000 57,000
$ 190,000 $20,639,000 $ 2,379,000
</TABLE>
The following tables summarize the Company's revenues and
income or loss before income taxes by geographic area for the
years ended December 31, 1992, 1993 and 1994:
<TABLE>
<CAPTION>
December 31,
1992 1993 1994
<S> <C> <C> <C>
Revenues:
United States $ 1,653,000 $ 2,310,000 $ 5,082,000
Costa Rica 324,000 81,000 -----
$ 1,977,000 $ 2,391,000 $ 5,082,000
Income (loss) before income taxes:
United States $ (411,000) $ (940,000) $(1,427,000)
Costa Rica 143,000 (247,000) (204,000)
$ (268,000) $ (1,187,000) $(1,631,000)
</TABLE>
Note 13. RELATED PARTY TRANSACTIONS
The accounts receivable from related parties consists
primarily of joint interest billings to directors, officers,
stockholders, employees and affiliated entities for drilling and
operating costs incurred on oil and gas properties in which these
related parties participate with MOC and MOC partnerships as
working interest owners. These amounts will generally be settled
in the ordinary course of business without interest.
Notes receivable of $41,000 and $43,000 at December 31, 1993
and 1994, respectively, consist of loans to employees, which bear
interest at prime plus 2%.
On June 30, 1993, the Company acquired all of the stock of
Fruitland Gas Corporation ("FGC") in exchange for 400,000 shares
of the Company's common stock. The acquisition was made in order
to acquire the acreage in the Burns Ranch gas field that was
owned by the seller. The value of the acreage acquired, net of a
$171,000 receivable owed by FGC to the Company, was set at
$2,500,000, a value deemed "fair" in the opinion of an
independent third party appraiser. For purposes of the exchange,
shares of the Company's common stock were valued at $6.25. The
shares issued in the transaction are restricted securities. The
acquisition was accounted for as a reorganization of entities
under common control and recorded at predecessor cost. The
assets and operations of FGC are insignificant to the Company's
balance sheet and results of operations. FGC is owned by the
former shareholders of MOC, two of whom are also directors of the
Company, and one of whom is also chairman of the Company. The
former shareholders of FGC also own Deep Gas LLC, a Colorado
limited liability company that acquired the mineral rights
underlying the Burns Ranch gas field at depths more than 20 feet
below the bottom of the Pictured Cliffs geologic formation from
FGC immediately prior to the Company's acquisition of FGC.
Certain oil and gas properties located in Alabama, in which
the Company has working interests, are operated by a company
owned by an individual who also owns, beneficially, in excess of
5% of the Company's common stock. As of December 31, 1993 and
1994, the Company had a payable to the related company of $14,000
and $7,000, respectively, which is included in accounts payable
on the accompanying consolidated balance sheets.
Red Rock is owned by an individual who owns, beneficially, in
excess of 5% of the Company's common stock. The Company has
receivables from (payables to) the stockholder of $7,000 and
$(9,000) as of December 31, 1993 and 1994, respectively, which
are included in joint interest receivables on the accompanying
consolidated balance sheets.
During the year ended December 31, 1994, the Company paid
legal fees of $1,100 to a law firm of which a director of the
Company is a senior partner. That firm is also representing the
Company in connection with a current litigation matter.
Additionally, consulting fees valued at $300,000 were paid to a
member of the firm in the form of 66,700 shares of the Company's
common stock. In January 1995, an additional 56,000 shares
valued at $112,000 were issued for services to the same
individual. Also in 1995, fees of $32,000 were paid to this
individual.
During the year ended December 31, 1994, the Company recorded
consulting and other fees of $200,000, of which $16,667 was
payable at yearend to an investment banking firm in which a
director is a partner. The Company also has a consulting
agreement with that firm for investment banking services of
$400,000 in 1995.
In February 1995, the Company entered into a Loan Agreement
establishing a $2,500,000 line of credit facility pursuant to
which it can borrow funds from three entities, two of which are
affiliates of an individual who owns, beneficially, in excess of
5% of the Company's outstanding common stock.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 88
<SECURITIES> 0
<RECEIVABLES> 1,135
<ALLOWANCES> 0
<INVENTORY> 30
<CURRENT-ASSETS> 1,342
<PP&E> 46,390
<DEPRECIATION> 19,834
<TOTAL-ASSETS> 28,226
<CURRENT-LIABILITIES> 3,106
<BONDS> 7,767
<COMMON> 77
3,804
9,504
<OTHER-SE> 7,772
<TOTAL-LIABILITY-AND-EQUITY> 28,226
<SALES> 2,263
<TOTAL-REVENUES> 5,682
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 6,581
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 132
<INCOME-PRETAX> (1,636)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,636)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,631)
<EPS-PRIMARY> (.24)
<EPS-DILUTED> (.24)
</TABLE>
