Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(mark one)
[X] Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1995
or
[ ] Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the Transition Period from
____ to _____
Commission file number 0-17267
Mallon Resources Corporation
(Exact name of Registrant as specified in its charter)
Colorado 84-1095959
(State or other jurisdiction (IRS Employer Identification No.)
of incorporation or organization)
999 18th Street, Suite 1700 Denver, Colorado 80202
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: (303)293-2333
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, par value $0.01 per share
(Title of Class)
Indicate by check mark whether the Registrant (l) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. [X] Yes [ ] No
As of the close of business on March 29, 1996, the aggregate
market value of the 4,270,659 shares of voting stock held by non-
affiliates of the Registrant, based upon on the $1.90 average of
the closing bid and asked prices for the Registrant's Common
Stock as reported on the Nasdaq's National Market System, was
approximately $8,114,000. Because such persons may be deemed to
be affiliates of Registrant, shares of Common Stock held by each
officer and director and by each person who owns 5% or more of
the outstanding Common Stock were excluded in making this
calculation. This determination of possible affiliate status is
not necessarily determinative for any other purposes.
As of March 29, 1996:
8,045,722 shares of Registrant's Common Stock were
outstanding; and
1,100,918 shares of Registrant's Series A Preferred Stock
(convertible into 1,113,173 shares of Common Stock)
were outstanding
400,000 shares of Registrant's Series B Mandatorily
Redeemable Convertible Preferred Stock (convertible
into 973,370 shares of common stock) were outstanding
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of Registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment hereto.
[ X ]
Documents Incorporated By Reference:
Portions of the Registrant's Proxy Statement relating to its
1995 Annual Meeting of Shareholders are incorporated by reference
into Part III of this Report.
Mallon Resources Corporation
Annual Report
on
Form 10-K
for the fiscal year ended
December 31, 1995
Table of Contents
PART I Page
Item 1 Business 1
Introduction 1
Development of the Company's Business --
Oil and Gas Operations 1
Development of the Company's Business --
Mining Activities 2
General Matters 2
Executive Officers 2
Special Considerations 3
Item 2 Properties 6
Oil and Gas 6
Mining 8
Item 3 Legal Proceedings 10
Item 4 Submission of Matters to a Vote of Security Holders 10
PART II 10
Item 5 Market for the Registrant's Common Equity and
Related Stockholder Matters 10
Item 6 Selected Financial Data 11
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
1995 Summary 12
Liquidity, Capital Resources and Capital
Expenditures 12
Results of Operations 14
Item 8 Consolidated Financial Statements 18
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 18
PART III
Item 10 Directors and Executive Officers of the Registrant 18
Item 11 Executive Compensation 18
Item 12 Security Ownership of Certain Beneficial Owners
and Management 18
Item 13 Certain Relationships and Related Transactions 19
PART IV
Item 14 Exhibits, Financial Statements and Reports on
Form 8-K 19
EXHIBIT INDEX 19
CONSOLIDATED FINANCIAL STATEMENTS
Index to Consolidated Financial Statements F-1
Report of Independent Accountants F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Operations F-5
Consolidated Statements of Stockholders' Equity F-6
Consolidated Statements of Cash Flows F-7
Notes to Consolidated Financial Statements F-9
SIGNATURES S-1
PART I
Item 1. Business
Introduction
Mallon Resources Corporation (the "Company") was incorporated in
Colorado in 1988, in connection with the consolidation of Mallon
Oil Company ("Mallon Oil"), Laguna Gold Company ("Laguna") and 19
limited partnerships that they sponsored. Mallon Oil continues
as a wholly owned subsidiary of the Company. Laguna is an 80%
owned subsidiary of the Company. All of the Company's business
activities are conducted through these two subsidiaries. See
Note 13 to the Consolidated Financial Statements for certain
financial information about the two segments. The Company's
common stock is traded on Nasdaq under the trading symbol "MLRC."
The Company's executive offices are at 999 18th Street, Suite
1700, Denver, Colorado 80202 (telephone 303/293-2333). The
Company's Transfer Agent is Securities Transfer Corporation,
Dallas, Texas.
In broad perspective, the Company's business objectives are to
increase earnings, revenues, cash flows and net assets, on both
an absolute and per share basis. These objectives are pursued
through a two-pronged strategy of: (i) developing the Company's
existing assets (both oil and gas and mining), and (ii) seeking
the acquisition of additional properties.
The Company conducts operations in two disparate industries --
oil and gas and mining. Management intends to separate Laguna
from its core oil and gas business. The Company has initiated
the process of this separation as is discussed in greater detail
herein.
Development of the Company's Business -- Oil and Gas Operations
On September 30, 1993, Mallon Oil purchased a group of producing
oil and gas properties located in neighboring Lea and Eddy
Counties, New Mexico from Pennzoil Exploration and Production
Company (the "Pennzoil Properties"). The acquisition was
significant to the Company.
Since the acquisition and through first quarter 1996, virtually
all of Mallon Oil's operational efforts were directed toward
enhancing the production from, and conducting development
drilling operations on, the Pennzoil Properties. During 1995,
the Company had one Morrow gas discovery in its South Kenmitz
Field. Also during 1995, Mallon Oil drilled eight wells in its
Quail Ridge/Northeast Lea Field. Seven of these wells were
productive; one was a dry hole. In 1995, Mallon's average
production over the year was approximately 470 BOPD and 3,600
MCFPD. At yearend 1995, Mallon Oil's oil reserves were 17%
greater than yearend 1994 amounts, and its gas reserves were 22%
greater as compared with yearend 1994 reserves, primarily as a
result of the reacquisition of Pennzoil Property reserves in
connection with the Company's August 1995 termination of its
production payment obligation (see Note 6 to the Consolidated
Financial Statements).
The Burns Ranch area, located in Rio Arriba County, New Mexico,
in the San Juan Basin, has been under development by Mallon Oil
since 1986. Mallon Oil owns a 59% average working interest in
this 20,000 acre block to the bottom of the Pictured Cliffs
Formation. The entire acreage block is held by production. All
production in the area has been gas, and Burns Ranch wells
typically contain reserves in more than one productive zone,
primarily the Pictured Cliffs Formation and the Ojo Alamo
Formation. The wells also penetrate the Fruitland Coal
Formation, which is productive in fields adjacent to Burns Ranch.
At present, management has identified 44 potential development
locations at Burns Ranch. Of the 44 locations currently
identified, 14 have been assigned proved undeveloped reserves in
the Pictured Cliffs or Ojo Alamo zones. Mallon Oil has delayed
development work at Burns Ranch due to the unattractive wellhead
prices that have prevailed in this portion of the San Juan Basin
since 1991.
Mallon Oil operates seven wells in Gavilan Field, in the New
Mexico portion of the San Juan Basin, with an average ownership
of 35%. The wells produce gas and small quantities of oil from
the Mancos Formation and the Gallup Formation. With stable gas
prices, management believes that development projects for Gavilan
Field are economically feasible, and future development will be
directed toward adding secondary pay zones.
Development of the Company's Business -- Mining Activities
Laguna holds 18 Mineral Exploration Concessions and one Mineral
Exploitation Concession granted by the Government of Costa Rica.
The Concessions cover 277 square kilometers divided into two
large blocks within north-central Costa Rica's Arenal-Fortuna
Gold District. At present, Laguna owns a 90% interest in all of
the Concessions, and Red Rock Ventures, Inc. (Red Rock), a
private company, owns a 10% interest. Red Rock is owned by an
individual who also owns, beneficially, in excess of 5% of the
Company's common stock.
A regional stream sediment geochemistry exploration study has
identified numerous gold and arsenic anomalies in the concession
area. Several of these form coherent anomalies, and are
geologically significant in the framework of the known regional
structure in that they occur in the hangingwall of the regional
geological control. Laguna began active exploration and
evaluation of the Rio Chiquito deposit area in March 1984. Since
then, it has drilled 250 holes totaling 23,000 meters at Rio
Chiquito, which is one of the smaller identified gold anomalies.
In 1995, Laguna's efforts were devoted primarily to additional
drilling at Rio Chiquito and to conducting a geophysical
examination of Laguna's southern concession block.
General Matters
For 1996, approximately 450 BOPD (more than 80%) of Mallon's oil
production is committed under a contract, which extends through
October 31, 1996, with one company. Other oil and liquids are
sold on the open market to unaffiliated purchasers, generally
pursuant to purchase contracts that are cancelable on 30 days
notice. The price paid for this production is generally an
established or "posted" price that is offered to all producers in
the field, plus any applicable differentials. Natural gas is
generally sold on the spot market or pursuant to short term
contracts. Prices paid for crude oil and natural gas fluctuate
substantially. Because future prices are difficult to predict,
Mallon Oil hedges a portion of its oil and gas sales to protect
against market downturns. The nature of hedging transactions is
such that producers forego the benefit of some price increases
that may occur after the hedging arrangement is in place. Mallon
Oil nevertheless believes that hedging may be prudent in certain
circumstances in order to minimize the risk of falling prices.
Mallon Oil believes it has satisfactory title to its oil and gas
properties, based on standards prevalent in the oil and gas
industry, subject to exceptions that do not detract materially
from the value of the properties. Laguna believes it has
satisfactory title to its Costa Rica mineral concessions.
Laguna has political risk insurance through the Overseas Private
Investment Corporation, a quasi-governmental agency sponsored by
the United States government. The risks that it insures against
are (1) loss due to the inability to convert into U.S. dollars
local currency received by the insured as profits or earnings or
return of the original investment; (2) loss of investment due to
expropriation, nationalization or confiscation by action of a
foreign government; (3) loss due to war, revolution, insurrection
or civil strife; and (4) loss of profits due to closing of
operations because of any revolution, war, insurrection or civil
strife.
At March 29, 1996, the Company had 15 full-time employees in its
Denver office; three full-time employees in its Carlsbad, New
Mexico office; two full-time employees in its San Jose, Costa
Rica office; and 10 employees at Rio Chiquito in Costa Rica.
Executive Officers
The Executive Officers of the Company are as follows:
Name Age Title Officer Since
George O. Mallon, Jr. 51 President, Chairman of the Board 1988
Kevin M. Fitzgerald 41 Executive Vice President 1988
James A. McGowen 53 Executive Vice President 1988
Roy K. Ross 45 Executive Vice President,
General Counsel 1992
Duane C. Knight, Jr. 35 Treasurer 1994
Carolena F. Chapman 52 Secretary, Controller 1989
Laurence D. Marsland 42 President of Laguna 1995
George O. Mallon, Jr., formed Mallon Oil in 1979, and served as
its President until December 1988, when he became that company's
Chairman of the Board. Mr. Mallon was a co-founder of Laguna in
1980, and served as its President until April 1986. He is now
Vice-Chairman of Laguna's Board. Mr. Mallon earned a B.S. degree
in Business from the University of Alabama in 1965, and an M.B.A.
degree from the University of Colorado in 1977.
Kevin M. Fitzgerald joined Mallon Oil in 1983 as Petroleum
Engineer and served as Vice President of Engineering from 1987
through December 1988, when he became President of that company.
Mr. Fitzgerald was Vice President, Oil and Gas Operations for the
Company from 1988 through October 1990, when he was named
Executive Vice President. Mr. Fitzgerald is also a director of
Mallon Oil. Mr. Fitzgerald earned a B.S. degree in Petroleum
Engineering from the University of Oklahoma in 1978.
James A. McGowen, a co-founder of Laguna, served as Vice
President of Production and a director of Laguna from its
inception in 1980 until December 1988, when he became President
of that company. Mr. McGowen is currently Chairman and a
director of Laguna. He earned an A.B. degree in Zoology from the
University of California in 1966.
Roy K. Ross joined the Company as Executive Vice President,
General Counsel and a director in October 1992. From June 1976
through September 1992, Mr. Ross was an attorney in private
practice with the Denver-based law firm of Holme Roberts & Owen.
Mr. Ross is also Executive Vice President, General Counsel and a
director of Mallon Oil and Laguna. He earned his B.A. degree in
Economics from Michigan State University in 1973, and his J.D.
degree from Brigham Young University in 1976.
Duane C. Knight, Jr. joined the Company as Treasurer in April
1994. From 1986 through March 1994, Mr. Knight, a certified
public accountant, was employed by Hein + Associates L.L.P., an
independent accounting firm. Mr. Knight also serves as Vice
President -- Finance and Treasurer of Mallon Oil and Laguna. Mr.
Knight earned his B.A. degree in Accounting from Colorado State
University in 1983.
Carolena F. Chapman is Controller and Secretary of the Company.
She has been with Mallon Oil since 1979 in various accounting
capacities and was promoted to her present position in October
1989. She also serves as Secretary and Controller for Mallon Oil
and Laguna.
Laurence D. Marsland is President and a director of Laguna. He
joined Laguna in 1995. Prior to then, he was Vice President of
New Ventures with MinCorp Ltd. He has been Project Manager for
numerous gold projects throughout the world. He holds a Masters
of Science in Management from the Sloan Fellows Program at the
Graduate School of Business, Stanford University, and a degree in
Mechanical Engineering from Western Australia Institute of
Technology.
Special Considerations
When evaluating the Company, its operations, or its expectations,
the reader should bear in mind that the Company and its
operations are subject to all of the following special
considerations and business risks, among others:
Oil and Gas Prices; Marketability of Production. The
Company's oil and gas revenues and profitability are
substantially affected by prevailing prices for oil and natural
gas. Hydrocarbon prices can be extremely volatile and can
experience periods of weak demand and resulting excess total
domestic and imported supplies. In general, hydrocarbon prices
are affected by numerous factors such as economic, political and
regulatory developments. The unsettled nature of the energy
market, which is sensitive to foreign political and military
events and the unpredictability of the actions of the
Organization of Petroleum Exporting Countries, make it
particularly difficult to estimate future prices of oil and
natural gas. Any significant decline in prices of oil or natural
gas for an extended period would have a material adverse effect
on the Company's financial condition and results of operations.
In addition, the marketability of the Company's production
depends upon the availability and capacity of pipelines and gas
gathering systems, the effect of federal and state regulation of
such production and transportation, general economic conditions,
and changes in demand, all of which could adversely affect the
Company's ability to market its production. All of these factors
are beyond the control of the Company, and the Company is limited
in its ability to protect its economic interests from their
effect.
Estimates of Reserves and Future Net Revenues. There are
numerous uncertainties inherent in estimating quantities of oil
and gas reserves, including many factors beyond the control of
the Company. Reserve estimates are based on numerous assumptions
and, therefore, are inherently imprecise. Actual future
production, prices, revenues, taxes, development expenditures,
operating expenses and quantities of recoverable oil and gas
reserves may vary substantially from those assumed in developing
the estimates. Any significant variance from such assumptions
can materially affect the accuracy of the estimates. In
addition, reserves may be subject to downward or upward revision
based upon production history, results of future development,
prevailing oil and gas prices and other factors.
Operating Hazards. The oil and gas business involves a
variety of operating risks, including the risk of fire,
explosions, blow-outs, pipe failure, casing collapse, abnormally
pressured formations, and environmental hazards such as oil
spills, gas leaks, ruptures and discharges of toxic gases, the
occurrence of any of which could result in substantial losses to
the Company due to injury and loss of life, damage to and
destruction of property and equipment, pollution and other
environmental damage, and related suspension of operations.
Gathering systems and processing plants are subject to many of
the same hazards, and any significant problems related to those
facilities could adversely affect the Company's ability to market
its production. Drilling activities are subject to numerous
risks, including the risk that no commercially productive oil or
gas reservoirs will be encountered, or that particular wells will
not produce at economic levels. The cost of drilling, completing
and operating wells may vary from initial estimates. Drilling
operations may be curtailed, delayed or canceled as a result of
numerous factors outside the Company's control, including but not
limited to title problems, weather conditions, compliance with
governmental requirements, mechanical difficulties and shortages
or delays in the delivery of drilling rigs or other equipment.
The Company maintains insurance against some, but not all,
potential risks; however, there can be no assurance that such
insurance will be adequate to cover any losses or exposure for
liability. Furthermore, the Company cannot predict whether
insurance will continue to be available at premium levels that
justify its purchase or whether insurance will be available at
all.
Regulation. Virtually all of the Company's oil and gas and
mining activities are subject to a wide variety of federal,
state, foreign and local governmental regulations, which are
changed from time to time in response to economic or political
conditions. Matters subject to regulation include, but are not
limited to, environmental matters, discharge permits for drilling
and mining operations, drilling and operating bonds, reports
concerning operations, the spacing of wells, unitization and
pooling of properties, allowable rates of production, restoration
of surface areas, mining pits and tailings ponds, plugging and
abandonment of wells, requirements for the operation of wells,
and taxation. From time to time, regulatory agencies have
imposed price controls and limitations on production by
restricting the rate of flow of oil and gas wells below actual
production capacity in order to conserve supplies of oil and gas.
During the past years, there has been a significant amount of
discussion by legislators concerning a variety of energy tax
proposals. There can be no certainty that any such measure will
be passed or what its effect will be on the Company if it is
passed. Many states have raised state taxes on energy sources
and additional increases may occur, although there can be no
certainty of the effect that such increases would have on the
Company. Legislation and new regulations concerning oil and gas
exploration and production operations and mining operations are
constantly being reviewed and proposed. All of the jurisdictions
in which the Company owns and operates properties have statutes
and regulations governing a number of the matters enumerated
above. Compliance with such laws and regulations generally
increases the Company's cost of doing business, and consequently
affects its profitability. Due to the frequently changing
requirements of laws and regulations, there can be no assurance
that costs of future compliance will not impose new or
substantial burdens on the Company.
Environmental Matters. The discharge of oil, gas or other
pollutants into the air, soil or water may give rise to
liabilities to the government and third parties, and may require
the Company to incur costs to remedy the discharge. Oil, natural
gas and other pollutants (including salt water brine and minerals
processing by-products) may be discharged in many ways, including
from a well or drilling equipment at a drill site, leakage from
pipelines or other gathering and transportation facilities,
leakage from storage tanks and tailings ponds, and sudden
discharges from damage or explosion at natural gas facilities,
oil and gas wells or tailings dams. Discharged pollutants may
migrate through soil to water supplies or adjoining property,
giving rise to additional liabilities. A variety of federal,
state and foreign laws and regulations govern the environmental
aspects of the oil and natural gas and mining businesses. In
addition, laws impose liability in the event of discharges
(whether or not accidental), failure to notify the proper
authorities of a discharge, and other noncompliance with those
laws. Compliance with environmental quality requirements and
reclamation laws imposed by governmental authorities may
necessitate significant capital outlays, may materially affect
the economics of a given property, or may cause material changes
or delays in the Company's intended activities. New or different
environmental standards imposed in the future may adversely
affect the Company's activities. Foreign operations are
increasingly being subjected to environmental standards that are
patterned after prevailing United States' standards, which tend
to be more rigorous and costly than standards that formerly
prevailed in such jurisdictions. The Company does not believe
that its environmental risks are materially different from those
of comparable companies in the oil and gas and mining industries.
Limited environmental assessments relating to some, but not all,
of the Company's properties have been performed, and no material
environmental noncompliance or cleanup liabilities were found.
However, despite such efforts, there can be no assurance that
such problems do not in fact exist, and they may arise in the
future; accordingly, there can be no assurance that significant
costs for compliance will not be incurred in the future.
Moreover, no assurance can be given that environmental laws will
not, in the future, result in curtailment of production or
material increases in the cost of exploration, development or
production or otherwise adversely affect the Company's operations
and financial condition.
Competition. The oil and gas industry and the mining
industry are highly competitive. The Company competes with major
companies, other independent concerns and individual producers
and operators. Many of these competitors have substantially
greater financial and other resources than does the Company.
Nature of Mineral Exploration. Exploration for minerals is
highly speculative and involves greater risks than many other
businesses. Many exploration programs do not result in the
discovery of mineralization and any mineralization discovered may
not be of sufficient quantity or quality to be profitably mined.
Uncertainties as to the metallurgical amenability of any minerals
discovered may not warrant the mining of these minerals on the
basis of available technology. The Company's mining operations
are subject to all of the operating hazards and risks normally
incident to exploring for and developing mineral properties.
Fluctuations in Minerals Prices. The market price of
minerals is extremely volatile and beyond the control of the
Company. If the price of a mineral should drop dramatically, the
value of the Company's properties being explored or developed for
that mineral could also drop dramatically and the Company might
not be able to recover its investment in those properties. The
decision to put a mine into production, and the commitment of the
funds necessary for that purpose, must be made long before the
first revenues from production will be received. Price
fluctuations between the time that such a decision is made and
the commencement of production can change completely the
economics of the mine. Although it is sometimes possible to
protect against price fluctuations by hedging, the volatility of
mineral prices represents a substantial risk in the mining
industry generally, which no amount of planning or technical
expertise can eliminate. If the Company determines to proceed
with mining operations based on prices that turn out to represent
a temporary high, such operations could prove to be uneconomic.
Foreign Operations. The Company's current mining operations
take place in Costa Rica. Foreign operations of any sort are
subject to risks related to monetary instability, revolution,
war, confiscation and other matters, all of which are outside of
the Company's control. The Company maintains insurance coverage
issued by the Overseas Private Investment Corporation on Rio
Chiquito against these sorts of risks. Nevertheless, no
assurance can be given that all potential losses would be covered
by the insurance, or that the insurance coverage will continue to
be available at acceptable premium levels.
Estimates of Mineralized Deposits. There are numerous
uncertainties inherent in estimating mineralized deposits,
including many factors beyond the control of the Company. Such
estimates are based on numerous assumptions and, therefore, are
inherently imprecise. Actual prices, recovery factors,
development expenditures, operating expenses and other factors
may vary substantially from those assumed in developing the
estimates. Any significant variance from such assumptions could
materially affect the accuracy of the estimates. A "mineralized
deposit" does not necessarily contain any "mineral reserves"
because sufficient information has not been obtained to determine
whether the deposit can be economically exploited. No assurance
can be given that a particular mineralized deposit will ever
qualify as a mineable ore reserve, that any particular level of
recovery of gold from ore reserves will in fact be realized or
that ore reserves may be mined and milled on a profitable basis.
Volumes and costs of future production can also be affected by
such factors as weather, environmental factors, unforeseen
technical difficulties, unusual or unexpected geological
formations, equipment breakdowns or malfunctions and work
interruptions. In addition, the grade of ore ultimately mined
may differ from that indicated by drilling results.
Capital Needs. In order for the Company to expand its
reserve bases, it must make significant capital expenditures for
acquisition of properties and for exploration and development.
There can be no assurance additional capital will be available to
the Company or that capital, if any, will be available on
satisfactory terms.
Reliance on Key Personnel; Demand of Rapid Growth. The
Company is dependent upon its executive officers and key
employees. The Company does not maintain key man insurance on
any of its executive officers or key employees. The unexpected
loss of services of one or more of these individuals could have a
detrimental effect on the Company. In addition, the continued
growth and expansion of the Company will depend upon, among other
factors, the successful retention and recruitment of skilled and
experienced management and technical personnel, especially in
connection with expanding development programs, exploitation
efforts and any future acquisitions.
Item 2. Properties
Oil and Gas
All of Mallon Oil's oil and gas operations are conducted on-
shore, in the United States. It currently has operations in the
states of New Mexico, Colorado, Oklahoma, Wyoming, North Dakota,
and Alabama. Subsequent to December 31, 1995, Mallon Oil
acquired a 2.5% working interest in an exploration venture to
drill one or more wells offshore Belize. The Company is
initially committed to spend approximately $200,000. These
expenditures will not begin until late 1996 or early 1997.
Acreage. The majority of Mallon Oil's producing oil and gas
properties is located on leased land held by Mallon Oil for as
long as production is maintained. The following table summarizes
Mallon Oil's oil and gas acreage holdings as of December 31,
1995. The "Gross" numbers reflect the total number of acres in
which Mallon Oil has a working interest. The "Net" numbers
reflect the total number of acres represented by Mallon Oil's
working interest.
Gross Net Gross Net
Developed Developed Undeveloped Undeveloped
Acreage Acreage Acreage Acreage
43,115 26,011 25,264 13,395
Proved Reserves. The following reserve information is based
upon an evaluation by Schlumberger/GeoQuest Reservoir
Technologies (formerly Intera Information Technologies, Inc.),
Petroleum Production Division, independent petroleum engineers,
and is included herein in reliance on such firm as an expert in
preparing such information. The following table sets forth the
estimated quantities of proved reserves and the present value of
estimated future net revenues from these reserves.
At December 31,
1993 1994 1995
Estimated Proved Oil Reserves
(Mbbls)(1) 1,069(2) 1,706(2) 1,813
Estimated Proved Gas
Reserves (Mmcf)(1) 25,909(2) 19,232(2) 19,921
Estimated Future
Net Revenues (1) $44,699,000(2) $29,970,000(2) $35,656,000
Present Value of Estimated Future
Net Revenues (1, 3) $25,219,000(2) $18,302,000(2) $21,038,000
(1) These estimates were prepared using constant prices and
costs in accordance with the guidelines of the Securities and
Exchange Commission.
(2) These include the volumes deliverable under the Enron
Production Payment. Deducting those volumes reduces Mallon Oil's
net reserves to 859 MBbls of oil and 22,336 MMcf of gas at
December 31, 1993 and 1,544 Mbbls of oil and 16,294 Mmcf of gas
at December 31, 1994, reduces the estimated future net revenues
to $32,236,000 and $22,529,000 at December 31, 1993 and 1994,
respectively, and reduces the present value of estimated future
net revenues to $18,188,000 and $13,758,000 at December 31, 1993
and 1994, respectively. The Enron Production Payment was retired
in August 1995 (see Note 6 to the Consolidated Financial
Statements).
(3) Calculated using a discount factor of 10%.
Drilling Activity. The following table sets forth, for each
of the three years ended December 31, 1995, 1994, and 1993, the
drilling activities conducted by Mallon Oil.
Exploratory Wells
Gross Wells Net Wells
Productive Dry Total Productive Dry Total
1995 1 0 1 .3 0 .3
1994 0 0 0 0 0 0
1993 0 0 0 0 0 0
Development Wells
Gross Wells Net Wells
Productive Dry Total Productive Dry Total
1995 7 1 8 4.4 .56 5.20
1994 4 0 4 1.75 0 1.75
1993 0 0 0 0 0 0
Productive Wells. The following table summarizes Mallon
Oil's gross and net interests in producing wells at December 31,
1995. Net interests represented in the table are net "working
interests" which bear the cost of operations. Productive wells
are producing wells and wells capable of production and include
gas wells awaiting pipeline connections.
Gross Wells Net Wells
Oil Gas SWD Total Oil Gas SWD Total
119 107 4 230 38.4 32.6 1.4 72.5
In addition, Mallon Oil owns interests in 4 waterflood units,
which contain a total of 544 gross wells (8.5 net wells).
Production and Sales Price. Mallon Oil's total oil and gas
production, including deliveries under the Enron Production
Payment, for each of the last three years was as follows:
1993 1994 1995
Oil (Bbls) 70,000 146,000 173,000
Gas (Mcf) 695,000 1,648,000 1,238,000
The average sales price per barrel of oil and Mcf of gas,
and average production costs per barrel of oil (expressed in
barrel of oil equivalents - BOE) and per Mcf of gas (expressed in
equivalent mcf - McfE) were as follows:
1993 1994 1995
Average Sales Price
Oil (per bbl) $14.75 $14.81 $16.45
Gas (per Mcf) $ 1.48 $ 1.50 $ 1.58
Average Production Cost
per BOE $ 5.25 $ 4.81 $ 4.93
per McfE $ .88 $ .80 $ .82
Hedging Activities. In November 1995, the Company entered
into a "collar" hedging transaction with an independent crude oil
buyer covering 12,000 barrels per month of its oil production.
Under this arrangement, for each month beginning November 1995
through October 1996, if the price for light sweet crude oil as
quoted on the New York Mercantile Exchange (NYMEX) is less than
$16.50 per barrel, the Company will receive the difference
between $16.50 and the average settlement price for that month
for the 12,000 barrels subject to the collar agreement. If the
average settlement price exceeds $18.00 per barrel, the Company
will pay the difference between $18.00 and such average price on
the 12,000 barrels. The premium for this collar is $0.30 per
barrel, payable monthly.
Also in November 1995, the Company entered into a "floor"
hedging transaction with an independent crude oil buyer covering
30,000 MMBTUs per month of the Company's gas production. Under
this arrangement, for each month beginning November 1995 through
October 1996, if the price for gas as quoted on the NYMEX is less
than $1.70, the Company will receive the difference between $1.70
and the average settlement price for that month for the 30,000
MMBTUs subject to the floor agreement. The premium for this
floor is $.095 per MMBTU, payable monthly.
Mining
General. Laguna holds 18 Mineral Exploration Concessions
and one Mineral Exploitation Concession granted by the Government
of Costa Rica. The Concessions cover 277 square kilometers,
divided into two large blocks (south and north) within north-
central Costa Rica's Arenal-Fortuna Gold District.
Location. The Concessions are located in north central
Costa Rica. They are reached by driving three hours north from
San Jose (the Capitol of Costa Rica) on paved highways to the
town of Tilaran, and then 30 minutes by gravel road east of
Tilaran.
Geology. The Southern Block area is generally characterized
by hot springs-style epithermal systems comprised of quartz
sulfide stockwork zones, locally massive silicification and
extensive adjacent zones of phyllic and argillic alteration.
Reserve and Resource Information. The Rio Chiquito anomaly
has defined in-situ geologic resources of approximately 410,000
ounces of gold and 7.8 million ounces of silver. This resource
relates only to the partially drilled Rio Chiquito anomaly, and
not to the five additional anomalies identified to date. The
Northern Concession Block has yet to be evaluated. Laguna
believes it contains several promising geologic characteristics.
Potential. Based on the results of an extensive stream
sediment geochemical sampling program covering virtually all of
the streams and drainages on the Southern Concession Block,
Laguna believes the Concessions may contain maar breccia hosted
gold deposits. A total of 401 samples were collected and
analyzed for arsenic and gold. The results of the geochemical
program showed a large arsenic anomaly trending northwest to
southeast across the entire Southern Concession Block. Within
the arsenic anomaly and peripheral to it, six large gold
anomalies were found, ranging in size from approximately 250
acres to 2,000 acres. Numerous smaller gold anomalies were also
identified. The Rio Chiquito deposit was found to be located
within a gold anomaly of approximately 250 acres. Except for the
drilling at Rio Chiquito and limited work at the Agua Caliente
anomaly, these anomalous areas have yet to be thoroughly
explored.
Ownership. At present, Laguna holds a 90% interest in all
of the Concessions, and Red Rock holds a 10% interest.
History. Laguna began active exploration and evaluation of
the Rio Chiquito deposit area in March 1984. In October 1987,
Laguna commenced operation of an open pit mine and a small pilot
plant processing facility at Rio Chiquito. Simple open pit
mining and heap leaching techniques were used, and produced gold
and silver using a standard Merrill-Crowe recovery plant. By
July 1989, Laguna was satisfied that the project's commercial
potential warranted additional development. Laguna also
concluded that the scope of the project was such that it should
seek a large mining company as a joint venture partner in order
to more thoroughly evaluate Rio Chiquito and plan for its
commercial development. Accordingly, Laguna suspended its pilot
mining operations at Rio Chiquito in July 1989. In total, the
pilot project at Rio Chiquito mined and processed approximately
110,000 tons of ore, and produced a total of 3,800 ounces of gold
and 28,600 ounces of silver.
In December 1990, Laguna and Red Rock entered into a joint
venture agreement with Sunshine International Exploration
Company, a subsidiary of Sunshine Mining Company, which provided
for additional exploration at Rio Chiquito. The program under
that joint venture commenced in late 1990 and resulted in 12,300
feet of reverse circulation drilling within an 800 foot by 800
foot grid that overlays the original Rio Chiquito pit area.
Sunshine elected not to go forward with the project in May 1991,
retaining a 5% net operating profits interest in the Rio Chiquito
deposit only. Laguna has an option to purchase this interest for
$200,000.
In January 1992, Laguna and Red Rock entered into a joint venture
agreement with Newmont Overseas Exploration Limited, a subsidiary
of Newmont Mining Company, under which Newmont could earn a 51%
interest in the Concessions by spending specified amounts and
making specified payments to Laguna and Red Rock. Newmont, at
its cost, performed a stream-bed sediment geochemical exploration
program, and drilled a total of 8,000 feet of core holes into and
surrounding the Rio Chiquito deposit. The majority of the core
holes were extended step-outs, drilled well outside of the known
boundaries of the deposit, looking for extensions in all
directions. An extension was found approximately 1,300 feet to
the north, but the gold values were low. An extension to the
southwest was also found and the deposit remains open at depth.
The joint venture was terminated as of December 31, 1992, and
Newmont retains no interest in the project.
During 1993, Laguna drilled an additional 6,000 feet of core
holes into the Rio Chiquito deposit. This work was undertaken to
confirm data to be used in the preparation of a commercial
development feasibility study.
During 1994, the Company carried out surface exploration in the
Agua Caliente and Bolanos areas. James Askew and Associates were
engaged to do an ore reserve study for the Rio Chiquito pit area.
During 1995, a group of private investors purchased a 20% equity
stake in Laguna. Proceeds were used to continue the exploration
and development of the Costa Rican concessions. Approximately
10,000 feet of core holes were completed. A geophysical survey
was completed over a part of the Southern Block, and an
engineering company was engaged to complete a feasibility study
of the project. As of the end of 1995, the study was 80%
complete.
Topography and Climate. The terrain over the Concessions is
rugged. Ash deposits from nearby Arenal Volcano mantle most of
the topography, and range from 3 to 50 feet in thickness. This
cover has made exploration of the area difficult, as outcrops are
rare and often covered with vegetation. Until it was cleared for
dairy cattle operations approximately 25 years ago, the area was
covered by rain forest. The climate is subtropical. The area
receives an average of 100 inches of rainfall each year,
primarily during the rainy season, which extends from August
through November.
Permitting. All governmental permits necessary for the
commercial development of the Rio Chiquito deposit, including all
required environmental clearances, were obtained in 1987 in
connection with the pilot project described above. Those permits
and approvals remain in effect, and, under current Costa Rica
requirements, will be sufficient for any operations recommended
by the feasibility study. In any event, Laguna intends to
conduct additional environmental analyses of the project as it is
planned, and all operations will be conducted in accordance with
internationally recognized and accepted practices. Because of
the tropical climate, reclamation work using native vegetation is
planned.
Political Risk Insurance. Laguna has political risk
insurance through the Overseas Private Investment Corporation, a
quasi-governmental agency sponsored by the United States
government. The risks that it insures against are (1) loss due
to the inability to convert into U.S. dollars local currency
received by the insured as profits or earnings or return of the
original investment; (2) loss of investment due to expropriation,
nationalization or confiscation by action of a foreign
government; (3) loss due to war, revolution, insurrection or
civil strife; and (4) loss of profits due to closing of
operations because of any revolution, war, insurrection or civil
strife.
Item 3. Legal Proceedings
The Minerals Management Service (the "MMS"), the federal agency
with regulatory responsibility for royalty matters on federal and
Indian oil and gas leases, has commenced an audit of royalties
payable with respect to production during the period of
January 1, 1987 through January 31, 1993 from federal and Indian
leases operated by Robert L. Bayless in northern New Mexico.
Included in these leases are the Company's Jicarilla Apache
leases in the Burns Ranch gas field. The MMS has asserted that
production from the Jicarilla leases was understated by 50,761
Mcf during January and February 1990 due to a production
measurement issue, resulting in non-payment of the 10-2/3%
royalty on that amount of production. The MMS also has asserted
that royalties were understated by $18,271 on the Jicarilla
leases for the period from September 1, 1989 to December 31,
1989 due to a dual accounting issue, and by $812 on such leases
for October 1989 due to a transportation deduction issue.
Amounts claimed by the MMS for the remainder of the six-year
audit period have not been quantified pending resolution of a
Bayless appeal on the MMS positions. The Company has a 59%
working interest in the Jicarilla leases at Burns Ranch, and it
may therefore be responsible for 59% of amounts finally
determined by the audit to be owing from such leases. Robert L.
Bayless, as operator, is contesting the asserted deficiencies on
behalf of all working interest owners. This matter has been
dormant for more than two years.
Item 4. Submission of Matters to a Vote of Securities Holders
None.
PART II
Item 5. Market For Registrant's Common Equity and Related
Stockholder Matters
The Company's only class of outstanding common equity, its common
stock, is traded on the Nasdaq National Market System under the
trading symbol "MLRC." The following table sets forth the high
and low bid information for the common stock as reported by the
NASD for the periods shown. Quotations reflect inter-dealer
prices, without retail mark-up, and mark-down or commission, and
may not represent actual transactions.
High Low
Quarter ended March 31, 1994 $4.50 $3.88
Quarter ended June 30, 1994 3.75 2.63
Quarter ended September 30, 1994 3.50 2.38
Quarter ended December 31, 1994 3.13 1.38
Quarter ended March 31, 1995 2.00 1.25
Quarter ended June 30, 1995 2.00 1.38
Quarter ended September 30, 1995 2.50 1.50
Quarter ended December 31, 1995 2.75 1.00
Quarter ended March 31, 1996 2.06 1.38
At March 29, 1996, there were approximately 750 holders of record
of the Company's common stock.
The Company does not intend to pay cash dividends on its common
stock in the foreseeable future. The Company instead intends to
retain its earnings to support the growth of the Company's
businesses. Any future cash dividends would depend on future
earnings, capital requirements, the Company's financial condition
and other factors deemed relevant by the Board of Directors.
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, 1991,
1992, 1993, 1994 and 1995, and balance sheet data as of
December 31, 1991, 1992, 1993, 1994 and 1995. 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
1991 1992 1993 1994 1995
<S> <C> <C> <C> <C> <C>
Total revenues $1,608,000 $1,977,000 $2,291,000 $4,909,000 $5,428,000
Operating costs & other
expenses 6,239,000 2,244,000 3,478,000 6,540,000 7,104,000
Loss before extraordinary
item (4,631,000) (268,000) (1,187,000) (1,631,000) (1,676,000)
Extraordinary item -- -- -- -- (253,000)
Net loss (4,631,000) (268,000) (1,187,000) (1,631,000) (1,929,000)
Dividends on preferred
stock and accretion -- -- -- (258,000) (360,000)
Net loss available to
common shareholders (4,631,000) (268,000) (1,187,000) (1,889,000) (2,289,000)
Net loss per common share (0.99) (0.06) (0.22) (0.25) (0.29)
Net cash provided by (used in)
operating activities 270,000 47,000 10,114,000 (235,000) (6,897,000)
Total assets 8,026,000 7,675,000 28,773,000 28,226,000 31,635,000
Long-term debt, deferred
revenues and drilling
advances 41,000 348,000 2,411,000 7,767,000 10,352,000
Mandatorily Redeemable
Convertible Preferred
Stock -- -- -- 3,804,000 3,844,000
Weighted average number of
common shares outstanding 4,672,000 4,781,000 5,471,000 7,664,000 7,786,000
</TABLE>
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
1995 Summary
As a result of the Company's activities in 1995, it showed
continued improvement in several key areas:
- - The Company had significant discoveries in two fields
through its drilling program;
- - The Company drilled and successfully completed eight oil
wells in 1995, resulting in a 9% increase in its oil production
and a 5% increase in its BOE reserves over 1994 levels;
- - The Company established a new line of credit with a
commercial bank, which enabled it to terminate its Enron
Production Payment financing; and
- - The Company raised $2.4 million from the issuance of
Laguna's preferred stock and associated warrants.
Despite the progress made, four factors combined to generate a
loss for the year: first, gas sales suffered from lower
production and low gas prices; second, additional interest
expense was incurred in connection with the Company's lines of
credit; third, increased mining project expenses were incurred in
relation to the ongoing Rio Chiquito project, and finally,
general and administrative expenses were higher than in 1994.
Liquidity, Capital Resources and Capital Expenditures
The Company took several steps in 1995 to reduce its working
capital deficit as of December 31, 1995 to $476,000, down from a
deficit of $1,764,000 at December 31, 1994. On February 15,
1995, the Company established a $2,500,000 line of credit with
three private investors. On August 24, 1995, the Company
refinanced this line of credit and its volumetric production
payment obligation by establishing a $15,000,000 line of credit
with a bank. This $15,000,000 line of credit was subsequently
replaced, on March 20, 1996, by a $35,000,000 line of credit (the
Facility). By (i) lowering borrowing costs, (ii) eliminating the
Company's production payment delivery obligations, (iii)
providing a three-month period of "interest-only" debt service
obligations, and (iv) providing a $2 million "over-advance"
facility to be used specifically for an approved drilling
program, these financing transactions are expected to enhance the
Company's working capital, cash flows and overall financial
condition. The significant terms of the Facility are as follows:
- - The initial borrowing base is $10,500,000, subject to
redetermination every six months, beginning June 30, 1996;
- - The interest rate is the London Interbank Offered Rate
(LIBOR), plus 2.5%;
- - The Facility requires a reduction in the commitment of
$130,000 per month beginning on June 30, 1996, subject to the
initial borrowing base redetermination;
- - The Facility provides for an additional $2,000,000 advance
line of credit to be used solely for a development drilling
program approved by the lender; this advance line is repayable
through 100% of the future net revenues generated by successful
wells under the drilling program. In addition, if borrowing base
levels increase under the Facility, such amounts must be borrowed
and used to prepay amounts outstanding under the advance line.
In any event, any advance line balance must be repaid by
September 30, 1997;
- - The Facility is collateralized by substantially all of the
Company's oil and gas properties;
- - The Company is obligated to maintain certain financial and
other covenants including a minimum current ratio of 1 to 1,
minimum net equity requirement, and a debt coverage ratio; and
- - The Facility expires on March 31, 1999.
With these important financial arrangements in place, the key to
the long-term resolution of the Company's working capital
situation is its drilling. For 1996, the Company has budgeted
for drilling one gross well (approximately .5 net) per month.
The Company has permitted, or is in the process of permitting, an
additional 15 development locations for drilling. It will then
evaluate further drilling based on the initial results. Drilling
operations inevitably have an initial negative impact on the cash
and working capital positions of the Company as up-front drilling
expenditures are incurred. On a longer term basis - as reserves
are produced - these drilling efforts are designed to have net
positive effects on cash flow and capital.
Management believes that the ultimate result of the drilling
activities, which are primarily aimed at oil production, will be
to increase cash flow, thereby reducing the Company's working
capital deficit and increasing liquidity. However, drilling
activities are subject to numerous risks, including the risk that
no commercially productive oil or gas reservoirs will be
encountered. Also, sales from successfully drilled wells 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, 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 sources of capital, if
available.
Additional drilling, and any acquisitions, would require
additional capital. Beyond the Facility, the source of any such
capital is not yet known, nor are any 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.
In addition to its drilling programs, the Company, from time-to-
time, farms out non-core properties or properties with a higher
risk profile than the Company is willing to accept. One such
farmout agreement in 1995 resulted in a significant gas discovery
which began production in August 1995. Another well has been
drilled and is being tested for completion as of March 29, 1996.
The Company is also evaluating alternatives to realize the value
of its mining properties. During 1995, Laguna sold 25,000 shares
of Laguna Series A Convertible Preferred Stock (the "Laguna
Series A Stock"), representing a 20% equity stake in Laguna. The
proceeds from this offering are being used to fund the
development of Laguna, including additional core drilling in
Costa Rica in preparation of a pre-feasibility study to expand
mineable reserves on the Rio Chiquito anomaly located on Laguna's
Costa Rica concessions, and preparation of a pre-feasibility
study for commercial development of Rio Chiquito to be completed
by The Winters Company of Tucson, Arizona in anticipation of
making an initial public offering of Laguna stock. Proceeds are
also being used to fund day-to-day operations of Laguna.
Each share of Laguna Series A Stock includes 10 detachable
warrants; each warrant represents the right to purchase one share
of Mallon's common stock at $2.50 per share. The warrants expire
on February 15, 2000. Each share of Laguna Series A Stock can be
converted into 144 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.
Subsequent to yearend, Laguna signed a letter of intent with a
Canadian underwriter for the sale of a minimum of 4,000,000 and a
maximum of 5,000,000 units at a price of $1.00 per unit. Each
unit will include one share of common stock and one warrant to
purchase one share of common stock, exercisable at $1.50 per
share for an 18-month period. Laguna also agreed to grant the
underwriter an option to purchase an additional 500,000 shares of
common stock, exercisable at $1.00, also for an 18-month period
following the issuance of the common stock.
The Company used net cash for operating activities of $6,897,000
in 1995 compared with $235,000 in 1994. Included in these
amounts are net losses of $1,929,000 and $1,631,000, for 1995 and
1994, respectively. Non-cash items added back include
depreciation, depletion and amortization of $2,340,000 and
$2,409,000 for 1995 and 1994, respectively. Amortization of
deferred revenues of $1,420,000 in 1995 and $2,366,000 in 1994
negatively impacted cash flow from operating activities. The
termination of the volumetric production payment reduced
operating cash flows by a total of $5,941,000, including the gain
of $355,000. The early retirement of the $2,500,000 line of
credit resulted in an extraordinary loss of $253,000. Other non-
cash items increasing operating cash flows were $93,000 and
$43,000 in 1995 and 1994, respectively. Changes in operating
assets and liabilities decreased cash flows from operations by
$130,000 in 1995 as accounts receivable increased. Changes in
operating assets and liabilities increased cash flows from
operating activities in 1994 by $1,310,000 primarily as a result
of an increase in accounts payable and accrued liabilities of
$1,549,000.
Investing activities used cash flows of $3,840,000 in 1995
compared with $2,081,000 in 1994. The Company invested
significantly more in its mining operations in 1995, and
continued reworking, recompleting, drilling and developing its
oil and gas properties.
Financing activities netted cash flows of $11,918,000 in 1995,
due primarily to two transactions described earlier: the receipt
of $10,000,000 as a result of its credit facility refinancing and
$2,400,000 as a result of the issuance of Laguna Series A Stock
and the associated detachable warrants. In 1994, cash provided
by financing activities netted the Company $1,440,000 mainly due
to proceeds from the sale of the Company's Series B Mandatorily
Redeemable Convertible Preferred Stock (the "Series B Stock") of
$3,774,000. Of this amount, $2,075,000 was used to retire the
Company's former net profits interest and accrued interest. The
other financing activity was the payment of the Series B Stock
dividends, $320,000 in 1995 and $228,000 in 1994.
At December 31, 1995, the Company had a working capital deficit
of $476,000 compared with a deficit of $1,764,000 at December 31,
1994. The improvement in working capital was caused primarily by
an increase in cash of $1,181,000, an increase in accounts
payable and accrued expenses of $183,000, and an increase in
accounts receivable, inventory and other assets of $405,000.
Limiting Mallon's ability to generate cash flows and positive
working capital were low gas prices received in 1995, especially
in its San Juan Basin gas properties. 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, although the Company may enter into contracts to reduce
the risk of price fluctuations, as indicated below.
In November 1995, the Company entered into a "collar" hedging
transaction with an independent crude oil buyer covering 12,000
barrels per month of its oil production. Under this arrangement,
for each month beginning November 1995 through October 1996, if
the price for light sweet crude oil as quoted on the New York
Mercantile Exchange (NYMEX) is less than $16.50 per barrel, the
Company will receive the difference between $16.50 and the
average settlement price for that month for the 12,000 barrels
subject to the collar agreement. If the average settlement price
exceeds $18.00 per barrel, the Company will pay the difference
between $18.00 and such average price on the 12,000 barrels. The
premium for this collar is $0.30 per barrel, payable monthly.
Also in November 1995, the Company entered into a "floor" hedging
transaction with an independent crude oil buyer covering 30,000
MMBTUs per month of the Company's gas production. Under this
arrangement, for each month beginning November 1995 through
October 1996, if the price for gas as quoted on the NYMEX is less
than $1.70, the Company will receive the difference between $1.70
and the average settlement price for that month for the 30,000
MMBTUs subject to the floor agreement. The premium for this
floor is $.095 per MMBTU, payable monthly.
Results of Operations
The following table summarizes the revenues from oil and gas
operations for the following years:
1993* 1994* 1995 *
Oil revenues $1,033,000 $2,162,000 $2,845,000
Oil production (bbl) 70,000 146,000 173,000
Average price per bbl $ 14.75 $ 14.81 $ 16.45
Gas revenues $1,028,000 $2,467,000 $1,955,000
Gas production (mcf) 695,000 1,648,000 1,238,000
Average price per mcf $1.48 $1.50 $1.58
Production and operating
costs per BOE $5.25 $4.81 $4.84
Depreciation, depletion and
amortization per BOE $4.70 $5.54 $5.60
* Includes 6,000 bbls and 70,000 mcf in 1993, 48,000 bbls and
961,000 mcf in 1994 and 26,000 bbls and 692,000 mcf in 1995
delivered to Enron pursuant to the terms of the volumetric
production payment agreement (see Note 6 to the Consolidated
Financial Statements).
1995 Compared to 1994
Total revenues increased from $4,909,000 in 1994 to $5,428,000
(or 11%) in 1995. Of this increase, $355,000 is the result of a
gain recognized on the termination of the Company's volumetric
production payment. Because the volumetric production payment
delivery obligation was terminated in August 1995, deferred
revenue amortization decreased to $1,420,000, down $946,000 (or
40%) from $2,366,000 in 1994. In 1996, it is expected that all
of the Company's production will result in cash sales to the
Company.
Oil and gas sales in 1995 increased to $3,380,000, up from
$2,263,000 in 1994, representing a $1,117,000 increase (or 49%).
This increase is primarily due to the Company's successful
development program and the termination of the production
payment, whereby quantities previously delivered to Enron are now
sold to third parties by the Company. Total oil sales increased
by 27,000 barrels or approximately 19%. Reserve engineering
forecasts indicate oil production of 162,000 barrels from proved
developed producing reserves in 1996. This estimate does not
include any incremental production which might result from the
Company's current development program. Management believes 1996
drilling activities will provide another increase in oil
production. Average oil prices increased from $14.81 per barrel
in 1994 to $16.45 per barrel in 1995, a $1.64 (or 11%) increase.
Gas production decreased from 1,648,000 mcf in 1994 to 1,238,000
mcf in 1995, or by 410,000 mcf (or 25%) due in part to a decrease
in one of the Company's producing properties. One of the
Company's significant properties has a steep decline curve,
accounting for 267,000 mcf of the 1995 production decrease.
Reserve engineering forecasts indicate gas production of
1,228,000 mcf from proved developed producing reserves in 1996
before taking into account any new gas production which may come
on line in 1996. Average gas prices increased in 1995 by $.08
per mcf (or 5%).
Included in total revenues for 1995 and 1994 are $1,420,000 and
$2,366,000, respectively, from the amortization of deferred
revenues. These deferred revenues related to a volumetric
production payment agreement with Enron, which was terminated in
August 1995. The deferred revenue was to be amortized over eight
years as deliveries were made to the purchaser. The Company
delivered approximately 692,000 mcf and 26,000 barrels in 1995
and 961,000 mcf and 48,000 barrels in 1994 under the production
payment. The Company incurred all costs related to the
production and delivery of these quantities. As a result of the
termination, the Company recognized a gain of $355,000 for the
difference between the book value of deferred revenues and the
amount paid to terminate the production payment obligation.
Lease operating expenses per equivalent barrel averaged $4.93 in
1995, compared with $4.81 in 1994. On a per barrel basis,
management expects lease operating expenses to decline in 1996.
There were no sales of gold and silver in 1995 or 1994, and no
income is expected in the immediate future. Costs related to the
mining operation were $ 448,000 in 1995, a significant $279,000
(or 165%) increase over $169,000 in 1994. The proceeds from the
Laguna Series A Stock offering are being used to fund development
of Laguna's activities in Costa Rica. The program there includes
additional core drilling to further delineate the Rio Chiquito
ore body and possibly expand mineable reserves. As a result of
these activities, mining project expenses increased in 1995, and
will continue to do so in 1996, and cash flow decreased. The
long-term impact of the Laguna development should be to add value
and to increase cash flows to the Company.
Depreciation, depletion and amortization rose slightly in 1995 to
$5.60 per barrel of oil equivalent, an increase of $.06 per
barrel from 1994. As of December 31, 1995, the net book value of
the Company's oil and gas properties exceeded the net present
value of the underlying reserves by $1,540,000. However, oil and
gas prices have increased substantially 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 $1,540,000 impairment was not charged
to expense during the year ended December 31, 1995.
Interest and other expense of $433,000 was up significantly
($301,000, or 228%) in 1995 as the Company incurred interest on
its lines of credit. The increase is the result of interest
incurred on borrowings under the Company's lines of credit; such
borrowings were incurred to terminate the volumetric production
payment. Management expects that net cash flow will increase in
1996 as sales to the Company of volumes previously delivered to
Enron will more than offset the full year effect of interest
expense under the Company's lines of credit. Management expects
interest expense to increase in 1996, as the new Facility will be
outstanding for the entire year.
Total general and administrative costs were $2,015,000 in 1995,
an increase of $209,000 (or 12%) over the $1,806,000 in 1994. Of
this increase, $200,000 was expensed as investment banking fees
related to a contract which expired in 1995. Salaries for two
officers hired April 1, 1994 were included for the full year in
1995. In 1995, consulting fees related to Laguna's exploration
program also significantly increased general and administrative
expenses. Travel and related expenses increased in 1995 because
of expenditures incurred in pursuing the Laguna private
placement, for travel related to the financing transactions, and
for new personnel traveling to Costa Rica for the mining program.
These increases are offset by the Company's efforts to reduce its
overhead. While reductions were made in several areas, legal
fees, specifically, decreased by more than $200,000 and general
office expenses were reduced by approximately $30,000.
The Company paid the 8% dividend on its $4,000,000 face value
Series B Stock. This amount totaled $320,000 in 1995 and
$228,000 for the period from April 16, 1994 to December 31, 1994.
The annual dividend is $320,000, payable in quarterly
installments of $80,000. Related accretion on the Series B Stock
was $40,000 for the year ended December 31, 1995.
1994 Compared to 1993
The Company used net cash for operating activities of $235,000 in
1994 compared with generating $10,114,000 in 1993. Included in
these amounts are net losses of $1,631,000 and $1,187,000 for
1994 and 1993, respectively. Also included are non-cash charges
for these net losses is depreciation, depletion and amortization
of $2,409,000 in 1994 compared with $937,000 in 1993.
Amortization of deferred revenue of $2,366,000 in 1994 and
$184,000 in 1993 negatively impacted cash flow from operating
activities. In 1993, proceeds from the volumetric production
payment increased cash from operating activities by $10,002,000.
Other non-cash items were $43,000 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 in 1993. In 1994, Mallon's oil
and gas operations involved reworking, recompleting and
developing properties. Effective January 1, 1994, the Company
completed a $22,400,000 acquisition. The adjusted purchase price
at closing on September 30, 1993 was $19,300,000, of which
$7,343,000 was in the form of a promissory note. The financial
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,
primarily from the sale of the Company's Series B Stock, which
resulted 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 repayment of the Company's net profits
interest and accrued interest in the amount of $2,075,000, which
eliminated this obligation. 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. The payment of $7,343,000 on the
Company's note payable, and payments on long-term debt, decreased
cash provided by financing activities.
Exclusive of quantities 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 property acquisition, and drilling and enhancement
operations completed during 1994. Oil production net to Mallon
increased by 34,000 barrels or approximately 53%. Not included
in the above oil production totals are 48,000 barrels in 1994 and
6,000 barrels in 1993 which were delivered to Enron in accordance
with the terms of the volumetric production payment. Average oil
prices increased from $14.75 per barrel in 1993 to $14.81 per
barrel in 1994.
Natural gas production net to Mallon increased by 62,000 mcf (or
10%) in 1994. Natural gas production in 1994 totaled 1,640,000
mcf; of which 961,000 mcf were delivered to meet the production
payment obligation. In 1995, natural gas production totaled
659,000 mcf; 70,000 mcf were delivered to Enron. In addition,
output was curtailed in the Company's Burns Ranch area, further
reducing gas production for the Company's account. Average gas
prices increased in 1994 by $.02 per mcf (or 1%).
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 $4.81 in
1994, compared with $5.25 in 1993. The decrease of $0.44 per
barrel (or 9%) was due primarily to the lower operating costs on
the acquired properties and operational efficiencies employed by
the Company. This reduction occurred despite substantial costs
for significant workovers and repairs on the Company's properties
in 1994.
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.
Depreciation, depletion and amortization increased to $5.53 per
barrel of oil equivalent for 1994, up from $4.70 in 1993. The
increase of $0.83 (or 18%) partially reflects a decrease in
production in one of the Company's major properties and the
effect of low yearend gas prices on reserves. 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 increased subsequent to
yearend. Applying these increased prices to yearend oil and gas
reserves indicated that the oil and gas properties were not, in
fact, impaired. Accordingly, the $916,000 impairment was not
charged to expense during the year ended December 31, 1994.
Interest and other expense of $132,000 was down significantly in
1994 ($249,000 was incurred in 1993), as the Company incurred
interest at 15% on its net profits interest in 1993. The net
profits interest was retired in April 1994.
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 mainly to increased salary expense for
additional personnel directly related to the September 1993
acquisition. Legal fees increased significantly, as the Company
was plaintiff in a complex lawsuit in which it sought substantial
damages. Travel expenses increased significantly due to efforts
related to the Company's mining property.
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. Related accretion on the
Series B Stock was $30,000 for the year ended December 31, 1994.
Item 8. Financial Statements and Supplementary Data
The Company's Consolidated Financial Statements that constitute
Item 8 follow the text of this Annual Report on Form 10-K. An
index to the Consolidated Financial Statements appears at page F-
1.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
Effective November 10, 1994, the Company released Hein +
Associates LLP ("H+A") as its independent certified public
accounting firm. During the two most recent fiscal years, and
for the period from December 31, 1993 through November 10, 1994,
there were no disagreements with H+A on any matter of accounting
principles or practices, financial statement disclosure, or
auditing scope or procedure. The release of H+A was approved by
the Company's Board of Directors at its November 9, 1994 meeting.
At that same meeting, the Company's Board of Directors approved
the selection of Price Waterhouse LLP as the Company's
independent accounting firm for the fiscal years 1993 through
1996. The Company had no prior business dealings or
consultations with Price Waterhouse LLP.
PART III
Item 10. Directors and Executive Officers
(a) Directors
The information set forth under the caption "Election of
Directors" in the Company's Proxy Statement for its May 31, 1996
Annual Meeting of Shareholders, which is to be filed with the
Securities and Exchange Commission, pursuant to Regulation 14A
under the Securities Exchange Act of 1934, is incorporated herein
by reference.
(b) Executive Officers
Information concerning executive officers is set forth in
Item 1 of Part I of this report.
Item 11. Executive Compensation
The information set forth under the caption "Executive
Compensation" in the Company's Proxy Statement for its May 31,
1996 Annual Meeting of Shareholders, which is to be filed with
the Securities and Exchange Commission, pursuant to Regulation
14A under the Securities Exchange Act of 1934, is incorporated
herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and
Management
The information set forth under the caption "Principal
Shareholders" in the Company's Proxy Statement for its May 31,
1996 Annual Meeting of Shareholders, which is to be filed with
the Securities and Exchange Commission, pursuant to Regulation
14A under the Securities Exchange Act of 1934, is incorporated
herein by reference.
Item 13. Certain Relationships and Related Transactions
The information set forth under the caption "Certain
Relationships and Related Party Transactions" in the Company's
Proxy Statement for its May 31, 1996 Annual Meeting of
Shareholders, which is to be filed with the Securities and
Exchange Commission, pursuant to Regulation 14A under the
Securities Exchange Act of 1934, is incorporated herein by
reference.
PART IV
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 to
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 Midland Bank Credit Agreement dated August 24, 1995 (8)
*10.56 Midland Bank Promissory Note dated August 24, 1995 (8)
*10.57 Midland Bank Mortgage dated August 24, 1995 (8)
*10.58 Bank One -- Loan Agreement dated March 20, 1996 (9)
*10.59 Bank One -- $35,000,000 Promissory Note dated
March 20, 1996 (9)
*10.60 Bank One -- $2,000,000 Advance Promissory Note
dated March 20, 1996 (9)
*10.61 Bank One -- Mortgage dated March 20, 1996 (9)
*10.62 Bank One -- Guaranty dated March 20, 1996 (9)
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 August 24, 1995.
(9) Incorporated by reference from Mallon Resources Corporation
(Commission File No. 0-17267) Form 8-K filed on March 20, 1996.
Index to Consolidated Financial Statements
Page
Report of Independent Accountants F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Operations F-5
Consolidated Statements of Stockholders' Equity F-6
Consolidated Statements of Cash Flows F-7
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 accompanying consolidated balance sheets and
the related consolidated statements of cash flows, of operations,
and of changes in stockholders' equity present fairly, in all
material respects, the financial position of Mallon Resources
Corporation and its subsidiaries at December 31, 1995 and 1994,
and the results of their cash flows and operations for each of
the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles. 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 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.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Denver, Colorado
April 12, 1996
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
December 31,
1994 1995
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 88,000 $ 1,269,000
Accounts receivable, with no
allowance for doubtful accounts:
Joint interest participants 490,000 376,000
Related parties 15,000 22,000
Oil and gas sales 551,000 1,065,000
Other 79,000 --
Inventories 30,000 53,000
Other 89,000 143,000
Total current assets 1,342,000 2,928,000
Property and equipment:
Oil and gas properties, under
full cost method 41,127,000 43,751,000
Mining properties and equipment 5,010,000 6,248,000
Other equipment 375,000 508,000
46,512,000 50,507,000
Less accumulated depreciation,
depletion and amortization (19,834,000) (22,085,000)
26,678,000 28,422,000
Notes receivable, related parties 43,000 63,000
Other, net 163,000 222,000
Total Assets $ 28,226,000 $ 31,635,000
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of capital lease
obligation $ -- $ 23,000
Trade accounts payable 2,253,000 2,309,000
Undistributed revenue 584,000 711,000
Drilling advances 207,000 271,000
Accrued taxes and expenses 62,000 90,000
Total current liabilities 3,106,000 3,404,000
Long-term debt -- 10,000,000
Capital lease obligation, net of
current portion -- 37,000
Drilling advances 315,000 315,000
Deferred revenues 7,452,000 --
Total non-current liabilities 7,767,000 10,352,000
Total liabilities 10,873,000 13,756,000
Commitments and contingencies (Note 7) -- --
Minority interest -- 2,275,000
Series B Mandatorily Redeemable
Convertible Preferred Stock,
$0.01 par value, 500,000 shares
authorized, 400,000 shares
issued and outstanding, respectively;
liquidation preference and mandatory
redemption of $4,000,000 3,804,000 3,844,000
Stockholders' equity:
Series A Convertible 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; 7,672,503 and
7,799,658 shares issued and
outstanding, respectively 77,000 78,000
Additional paid-in capital 38,727,000 38,906,000
Accumulated deficit (30,985,000) (32,954,000)
Total stockholders' equity 13,549,000 11,760,000
Total Liabilities and Stockholders'
Equity $ 28,226,000 $ 31,635,000
</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,
1993 1994 1995
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 1,877,000 $ 2,263,000 $ 3,380,000
Deferred revenue amortization 184,000 2,366,000 1,420,000
Mining management fee 81,000 -- --
Operating service revenue 101,000 174,000 158,000
Interest and other 48,000 106,000 115,000
Gain on termination of volumetric
production payment -- -- 355,000
2,291,000 4,909,000 5,428,000
Costs and expenses:
Oil and gas production 976,000 2,024,000 1,868,000
Mining project expenses 133,000 169,000 448,000
Depreciation, depletion and amortization 937,000 2,409,000 2,340,000
General and administrative 1,183,000 1,806,000 2,015,000
Interest and other 249,000 132,000 433,000
3,478,000 6,540,000 7,104,000
Loss before extraordinary item (1,187,000) (1,631,000) (1,676,000)
Extraordinary loss on early retirement of debt -- -- (253,000)
Net loss (1,187,000) (1,631,000) (1,929,000)
Dividends on preferred stock and accretion -- (258,000) (360,000)
Net loss available to common stockholders $(1,187,000) $ (1,889,000) $(2,289,000)
Per share:
Loss available to common stockholders
before extraordinary item $ (0.22) $ (0.25) $ (0.26)
Extraordinary loss -- -- (0.03)
Net loss available to common
stockholders $ (0.22) $ (0.25) $ (0.29)
Weighted average shares outstanding 5,471,000 7,664,000 7,786,000
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Series A Additional
Preferred Stock Common Stock Paid-In Accumulated
Shares Amount Shares Amount Capital Deficit Total
(000) (000) (000) (000) (000)
<S> <C> <C> <C> <C> <C> <C> <C>
Balances 1/1/93 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 -- 12 -- 12
Stock issued for Fruitland
Gas Company -- -- 400,000 4 (105) -- (101)
Stock issued for property
and equipment -- -- 30,000 1 150 -- 151
Options exercised for services -- -- 8,000 -- 33 -- 33
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 of 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
Employee stock options
exercised -- -- 5,000 -- -- -- --
Stock issued to directors -- -- 6,155 -- 12 -- 12
Stock issued for property -- -- 56,000 -- 112 -- 112
Stock issued for loan fees -- -- 60,000 1 111 -- 112
Employee stock options granted -- -- -- -- 89 -- 89
Issuance of warrants -- -- -- -- 175 -- 175
Dividends on preferred stock -- -- -- -- (320) -- (320)
Accretion of preferred stock -- -- -- -- -- (40) (40)
Net loss -- -- -- -- -- (1,929) (1,929)
Balances 12/31/95 1,100,918 $5,730 7,799,658 $78 $38,906 $(32,954) $11,760
</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,
1993 1994 1995
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $(1,187,000) $(1,631,000) $(1,929,000)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Amortization of deferred revenues (184,000) (2,366,000) (1,420,000)
Depletion, depreciation and amortization 937,000 2,409,000 2,340,000
Stock issued for compensation 210,000 43,000 101,000
Termination of volumetric production payment -- -- (5,586,000)
Gain on termination of volumetric production
payment -- -- (355,000)
Non-cash portion of extraordinary loss -- -- 90,000
Other -- -- (8,000)
Proceeds from volumetric production payment 10,002,000 -- --
Changes in operating assets and liabilities:
Increase in:
Accounts receivable (607,000) (257,000) (328,000)
Inventory and other current assets (117,000) (100,000) (77,000)
Increase (decrease) in:
Accounts payable and undistributed revenue 963,000 1,549,000 183,000
Accrued taxes and expenses 105,000 14,000 28,000
Drilling advances (8,000) 104,000 64,000
Net cash provided by (used in) operating activities 10,114,000 (235,000) (6,897,000)
Cash flows from investing activities:
Increase in notes receivable - related party (8,000) (2,000) (20,000)
Additions to property and equipment (13,048,000) (2,079,000) (3,820,000)
Net cash used in investing activities (13,056,000) (2,081,000) (3,840,000)
Cash flows from financing activities:
Proceeds from long-term debt -- -- 10,000,000
Payments on long-term debt and capital
lease obligation (70,000) (31,000) (3,000)
Debt issue costs paid -- -- (159,000)
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 8,940,000 -- --
Proceeds from stock options exercised 278,000 -- --
Issuance of preferred stock, net of
issuance costs -- 3,774,000 --
Issuance of preferred stock in subsidiary,
net of issuance costs -- -- 2,275,000
Issuance of warrants -- -- 125,000
Payment of preferred dividends -- (228,000) (320,000)
Net cash provided by financing activities 3,683,000 1,440,000 11,918,000
Net increase (decrease) in cash and cash equivalents 741,000 (876,000) 1,181,000
Cash and cash equivalents, beginning of year 223,000 964,000 88,000
Cash and cash equivalents, end of year $ 964,000 $ 88,000 $ 1,269,000
Supplemental cash flow information:
Cash paid for interest $ 93,000 $ 175,000 $ 525,000
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 $112,000
Loan origination fee -- -- 112,000
Issuance of warrants in exchange for:
Loan origination fee -- -- 50,000
Acquisition of equipment under capital lease -- -- 63,000
</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"), Laguna Gold Company ("Laguna"), and
19 Colorado limited partnerships for which MOC or Laguna 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 Laguna and for the net assets of all
of the partnerships.
Nature of Operations:
The Company operates in two lines of business: oil and gas
exploration and production, and gold and silver exploration. The
significant majority of the Company's assets and revenues are
utilized in its oil and gas operations, which are conducted
primarily in the State of New Mexico, and entirely within the
United States. Mining operations are conducted through Laguna in
Costa Rica and are in the pre-production stage.
Principles of Consolidation:
The consolidated financial statements include the accounts
of MOC, Laguna, 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.
Fair Value of Financial Instruments:
The Company's on-balance sheet financial instruments consist
of cash and cash equivalents, accounts receivable, inventories,
accounts payable, other accrued liabilities and long-term debt.
Except for long-term debt, the carrying amounts of such financial
instruments approximate fair value due to their short maturities.
At December 31, 1995, based on rates available for similar types
of debt, the fair value of long-term debt was not materially
different from its carrying amount.
The Company's off-balance sheet financial instruments
consist of "collar" and "floor" derivative instruments which are
intended to manage commodity price risk (see Note 10). Based on
market prices at December 31, 1995, the Company will receive
approximately $70,000 less revenue than at spot price over the
term of the derivative agreement.
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 accumulated in one cost center,
the continental United States.
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 deferred revenue from any
volumetric production payments, 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
relative energy content.
Estimated abandonment costs (including plugging, site
restoration, and dismantlement expenditures) are accrued if such
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,
1995, estimated salvage values equaled or exceeded estimated
abandonment costs.
Mineral Properties and Equipment:
The Company expenses general prospecting costs and the costs
of acquiring and exploring unevaluated mining properties. When a
property is determined to have development potential, further
exploration and development costs are capitalized. When
commercially profitable ore reserves are developed and operations
commence, capitalized costs will be amortized using the units-of-
production method based on the estimated tons of ore to be
recovered. Upon abandonment or sale of projects, all capitalized
costs relating to the specific project are expensed in the year
abandoned or sold and any gain or loss would be recognized.
Proceeds from advanced royalties are to be accounted for as
adjustments of capitalized 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 periodic basis. Management estimates net realizable values
based on reserve estimates (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, 1995,
capitalized costs were less than estimated net realizable values.
Other Property and Equipment:
Other property and equipment is recorded at cost, and is
depreciated over the 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.
Impairment of Long-Lived Assets:
In the fourth quarter of 1995, the Company adopted Statement
of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of". SFAS No. 121 prescribes that an impairment loss
is recognized in the event that facts and circumstances indicate
that the carrying amount of an asset may not be recoverable, and
an estimate of future undiscounted cash flows is less than the
carrying amount of the asset. Impairment is recorded based on an
estimate of future discounted cash flows. The adoption of SFAS
No. 121 had no effect on the Company's financial position or
results of operations.
Gas Balancing:
The Company uses the entitlements method of accounting for
recording natural gas sales revenues. Under this method, 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.
Concentration of Credit Risk:
The Company is exposed to credit losses in the event of non-
performance by counterparties to financial instruments, but does
not expect any counterparties to fail to meet their obligations.
The Company generally does not obtain collateral or other
security to support financial instruments subject to credit risk
but does monitor the credit standing of counterparties.
Intangible Assets:
Intangible assets are recorded at cost and are amortized
over their estimated useful lives using the straight-line method.
Drilling Advances and 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 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 based on currently enacted tax rates.
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.
Stock-Based Compensation:
SFAS No. 123, "Accounting for Stock-Based Compensation," was
issued in October 1995 with an effective date for fiscal years
beginning after December 15, 1995. As permitted under SFAS No.
123, the Company has elected to continue to measure compensation
cost using the intrinsic value based method of accounting
prescribed by APB Opinion No. 25, "Accounting for Stock Issued to
Employees." Upon adoption in 1996, the Company will make pro
forma disclosures of net income and earnings per share as if the
fair value based method of accounting as defined in SFAS No. 123
had been applied.
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 the Company's 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 herein.
Hedging Activities:
The Company's use of derivative financial instruments is
limited to management of commodity price risk. 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.
Per Share Data:
Loss per share of common stock is computed by dividing net
loss attributable to shares of common stock by the weighted
average number of common shares outstanding. Loss attributable
to shares of common stock is net loss, preferred stock dividends
and accretion of Series B Mandatorily Redeemable Convertible
Preferred Stock. Preferred stock dividends and accretion totaled
$360,000 and $258,000 for the years ended December 31, 1995 and
1994, respectively. The computation of fully diluted loss per
share of common stock for each of the three years in the period
ended December 31, 1995 was not dilutive; therefore, only primary
loss per share of common stock is presented.
Use of Estimates and Significant Risks:
The preparation of consolidated financial statements in
conformity with generally accepted accounting principles requires
management to make significant estimates and assumptions that
affect the amounts reported in these financial statements and
accompanying notes. The more significant areas requiring the use
of estimates relate to oil and gas and mineral reserves, fair
value of financial instruments, future cash flows associated with
assets, valuation allowance for deferred tax assets, and useful
lives for depreciation, depletion and amortization. Actual
results could differ from those estimates.
The Company and its operations are subject to numerous risks
and uncertainties. Among these are risks related to the oil and
gas and the mining businesses (including operating risks and
hazards and the plethora of regulations imposed thereon), risks
and uncertainties related to the volatility of the prices of oil
and gas and minerals, uncertainties related to the estimation of
reserves of oil and gas and minerals and the value of such
reserves, the effects of competition and extensive environmental
regulation, the uncertainties related to foreign operations, and
many other factors, many of which are necessarily out of the
Company's control. The nature of oil and gas drilling operations
is such that the expenditure of substantial drilling and
completion costs are required well in advance of the receipt of
revenues from the production developed by the operations. Thus,
it will require more than several quarters for the financial
success of that strategy to be demonstrated. 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.
Reclassifications:
Certain prior years' amounts in the consolidated financial
statements have been reclassified to conform to the presentation
used in 1995.
Note 2. OIL AND GAS PROPERTIES
During 1995, the Company's oil and gas activities were
conducted entirely in the United States. Subsequent to
December 31, 1995, Mallon Oil acquired a 2.5% working interest in
an exploration venture to drill one or more wells offshore
Belize. The company is initially committed to spend
approximately $200,000. These expenditures will not begin until
late 1996 or early 1997.
Depletion of oil and gas property costs were $4.70, $5.53
and $5.70 per equivalent barrel of oil production for the years
ended December 31, 1993, 1994, and 1995, respectively.
On September 30, 1993, the Company purchased interests in
certain properties for approximately $19,300,000. The purchase
price was paid with $10.0 million of proceeds from the sale of a
volumetric production payment (which was terminated in August
1995), $2.0 million of proceeds from the sale of a net profits
interest (which was retired in April 1994), and with a note
payable to the seller of $7.3 million (which was repaid in
November 1993).
The operations of the acquired properties have been included
in 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:
(Unaudited)
Total revenues $6,006,000
Net loss available to common stockholders $ (242,000)
Net loss per share $ (.03)
Capitalized Costs Relating to Oil and Gas Activities:
December 31,
1993 1994 1995
Oil and gas properties $ 38,885,000 $ 41,127,000 $43,751,000
Accumulated depreciation,
depletion and
amortization (16,863,000) (19,011,000) (21,173,000)
22,022,000 22,116,000 22,578,000
Deferred revenues attri-
butable to the volu-
metric production
payment (9,818,000) (7,452,000) --
$ 12,204,000 $ 14,664,000 $ 22,578,000
The Company does not have significant costs of unproved
properties or costs excluded from the full cost pool amortization
base. As of December 31, 1995, the net book value of the
Company's oil and gas properties exceeded the net present value
of the underlying reserves by $1,540,000. However, oil and gas
prices increased substantially 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 $1,540,000 impairment was not charged to expense
during the year ended December 31, 1995.
Costs Incurred in Oil and Gas Producing Activities:
December 31,
1993 1994 1995
Property acquisition costs $16,919,000 $ 721,000 $ 131,000
Termination of volumetric
production payment -- -- 5,586,000
Exploration costs -- -- 180,000
Development costs 3,318,000 1,802,000 2,379,000
Full cost pool credits (21,000) (142,000) (66,000)
$20,216,000 $2,381,000 $ 8,210,000
Results of Operations from Oil and Gas Producing Activities:
December 31,
1993 1994 1995
Oil and gas sales $ 1,877,000 $ 2,263,000 $ 3,380,000
Deferred revenue amortization 184,000 2,366,000 1,420,000
Lease operating expense (976,000) (2,024,000) (1,868,000)
Depreciation, depletion and
amortization (874,000) (2,330,000) (2,162,000)
Results of operations from
producing activities
(excluding corporate over-
head, interest and income
taxes) $ 211,000 $ 275,000 $ 770,000
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, 1993, 1994, and
1995. All of the Company's reserves are located in the
continental United States.
Oil Gas
Proved Reserves (BBLS) (MCF)
Reserves, January 1, 1993 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
Acquisition of reserves in place 136,000 2,246,000
Extensions, discoveries and additions 163,000 1,129,000
Production (173,000) (1,277,000)
Revisions 143,000 1,529,000
Reserves, December 31, 1995 1,813,000 19,921,000
Reserves attributable to the volumetric production payment
(not included above)
December 31, 1993 209,000 3,575,000
December 31, 1994 162,000 2,938,000
December 31, 1995 -- --
Proved Developed Reserves
December 31, 1993 602,000 17,999,000
December 31, 1994 811,000 11,733,000
December 31, 1995 1,238,000 14,702,000
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:
December 31,
1993 1994 1995
Future cash in-flows $ 61,012,000 $ 50,964,000 $ 66,178,000
Future production and
development costs (27,075,000) (28,435,000) (30,522,000)
Future income taxes (1,701,000) -- --
Future net cash flows 32,236,000 22,529,000 35,656,000
Discount at 10% (14,048,000) (8,771,000) (14,618,000)
Standardized measure of
discounted future net
cash flows $ 18,188,000 $ 13,758,000 $ 21,038,000
Future net cash flows were computed using yearend prices and
yearend statutory income tax rates (adjusted for permanent
differences, operating loss carryforwards 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:
December 31,
1993 1994 1995
Standardized measure,
beginning of year $ 4,425,000 $ 18,188,000 $13,758,000
Net revisions to previous
quantity estimates and
other (2,910,000) (4,523,000) (1,852,000)
Extensions, discoveries,
additions, and changes
in timing of production,
net of related costs 85,000 3,959,000 1,631,000
Purchase of reserves
in place 27,485,000 -- 5,701,000
Sales of reserves in
place (10,002,000) -- --
Increase in future
development costs (906,000) (1,065,000) (127,000)
Sales of oil and gas
produced, net of
production costs (901,000) (239,000) (1,512,000)
Net change in prices and
production costs 602,000 (5,341,000) 2,063,000
Accretion of discount 443,000 1,819,000 1,376,000
Net change in income
taxes (133,000) 960,000 --
Standardized measure,
end of year $18,188,000 $13,758,000 $21,038,000
Reserves to be delivered pursuant to the Company's
volumetric production payment were excluded from the SFAS No. 69
calculations presented for 1993 and 1994. 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 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. LAGUNA GOLD COMPANY
The Company's principal precious metals property is the Rio
Chiquito project located in Guanacaste Province, Costa Rica,
where Laguna holds 18 exploration concessions and one
exploitation concession covering 277 square kilometers. The
Company believes that it has valid rights to the Rio Chiquito
concessions, and that all necessary exploration work has been
performed. The project is owned 90% by Laguna and 10% by Red
Rock Ventures, Inc. ("Red Rock").
In order to achieve profitable operations, management
believes that an additional capital investment will be required
for equipment and improvements necessary to achieve acceptable
production rates and unit costs.
Laguna's authorized capital consists of 200,000,000 shares
of $.01 par value common stock and 1,000,000 shares of preferred
stock, par value $.01 per share, with designations, rights,
preferences and limitations as may be determined by the Board.
At December 31, 1995, 14,400,000 shares of common stock were
issued, outstanding and owned by the Company. Effective June 30,
1995, the Company privately placed 25,000 shares of Laguna's
Series A Convertible Preferred Stock (the "Laguna Series A
Stock") for net proceeds of $2,275,000. Each share of Laguna
Series A Stock can be converted into 144 shares of Laguna $.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 net effect of this sale is that the Company now
retains an 80% equity stake in Laguna. Each share of Laguna
Series A Stock includes 10 detachable warrants; each warrant
represents the right to purchase one share of Mallon's common
stock at $2.50 per share. The warrants, which are valued at $.50
each for an aggregate value of $125,000, expire on February 15,
2000. The net proceeds received from the Laguna Series A Stock
placement, net of the value assigned to the detachable warrants
which was reflected as additional paid-in capital, are reflected
as Minority Interest in the accompanying financial statements.
In February 1994, Laguna adopted the Laguna Gold Company
Equity Participation Plan (the "Equity Plan"). Under the Equity
Plan, shares of common stock have been reserved for issuance in
order to provide for incentive compensation and awards to
employees and consultants. The Equity Plan provides that stock
options, stock bonuses, stock appreciation rights, and other
forms of stock-based compensation may be granted in accordance
with the provisions of the Plan. Effective January 1, 1995,
options to purchase a total of 1,620,000 shares of Laguna's
common stock were granted to four officers of Laguna, exercisable
at a price of $0.01 per share. The options vest over a period of
up to four years. The options vest in full if controlling
interest in Laguna or substantially all of its assets are sold,
or if Laguna is merged into another company, or if control of
Laguna's Board is obtained by a person or persons not expressly
approved of by a majority of the members of the Board as of the
date the options are granted. The difference between the
exercise price and the estimated fair value of the shares at the
date of grant was charged to compensation expense with a
corresponding entry classified as an increase to Stockholders'
Equity. To date, none of these options have been exercised.
Laguna maintains an "Outside Directors Equity Plan" for
outside directors of Laguna. This plan provides that Laguna's
non-management directors will be compensated with shares of
Laguna's $0.01 par value common stock. Initial stock awards are
to be for $5,000 worth of stock. The Plan has not yet been
implemented and Laguna has recorded no associated expense.
Laguna currently has one outside director.
Subsequent to yearend, Laguna signed a letter of intent with
a Canadian underwriter for the sale of a minimum of 4,000,000 and
a maximum of 5,000,000 units at a price of $1.00 per unit. Each
unit will include one share of common stock and one warrant to
purchase one share of common stock, exercisable for $1.50 for an
18-month period. Laguna also agreed to grant the underwriter an
option to purchase an additional 500,000 shares of common stock,
exercisable at $1.00, also for an 18-month period following the
issuance of the common stock.
Note 4. NOTES PAYABLE AND LONG-TERM DEBT
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 bore interest at 11%. On
August 24, 1995, the Company established a $15,000,000 revolving
line of credit facility with a commercial bank, which bore
interest at the London Interbank Offered Rate (LIBOR) plus 2.5%
(8% at December 31, 1995). The proceeds from this facility were
used to retire the Company's existing $2,500,000 line of credit
and to terminate its volumetric production payment (see Note 6).
The Company paid a $125,000 prepayment penalty in order to retire
the $2,500,000 line of credit, and such amount, along with the
remaining unamortized loan origination fees of the initial line
of credit, is included in the $253,000 extraordinary loss on debt
retirement. As a part of the fee for the $15,000,000 facility,
the Company issued warrants, valued at $0.50 each, to purchase
100,000 shares of the Company's common stock at a price of $2.50
per share. As of December 31, 1995, the total amount outstanding
under the line of credit facility was $10,000,000.
On March 20, 1996, the Company replaced its existing line of
credit facility with a $35,000,000 revolving line of credit
facility from another bank (the "Facility"). The significant
terms of the Facility are as follows:
- - Initial borrowing base under the Facility is $10,500,000,
subject to redetermination every six months beginning June 30,
1996;
- - Interest rate on the Facility is LIBOR plus 2.5%;
- - The Facility requires a reduction in the commitment of
$130,000 per month beginning on June 30, 1996, subject to the
initial borrowing base redetermination;
- - The Facility provides for an additional $2,000,000 advance
line of credit to be used solely for a development drilling
program approved by the lender; this advance line is repayable
through 100% of the future net revenues generated by successful
wells under the drilling program. In addition, if borrowing base
levels increase under the Facility, such amounts must be borrowed
and used to prepay amounts outstanding under the advance line.
In any event, any advance line balance must be repaid by
September 30, 1997;
- - The Facility is collateralized by substantially all of the
Company's oil and gas properties;
- - The Company is obligated to maintain certain financial and
other covenants including a minimum current ratio of 1 to 1,
minimum net equity and a debt coverage ratio; and
- - The Facility expires on March 31, 1999.
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 (approximately 25%) and future drilling and
completion costs (approximately 75%). Because of unfavorable gas
prices in the area, the Company has no current plans to drill in
this field in 1996. Accordingly, the portion of the sales
proceeds allocated to future drilling and completion costs have
been included in non-current liabilities at December 31, 1995.
Note 6. DEFERRED REVENUE
In connection with its September 30, 1993 acquisition of
producing oil and gas properties, the Company sold a volumetric
production payment burdening the Company's interest in the
acquired properties for net proceeds of $10.0 million. The
proceeds received were recorded as deferred revenue. The
production payment covered approximately 4,354,000 MMBTU of
natural gas at an indicated average price of $1.65 and 215 MBbls
barrels of oil at an indicated average price of $13.01 per barrel
to be delivered over eight years. The Company was responsible
for production costs associated with operating the properties
subject to the production payment agreement. In August 1995, the
volumetric production payment was terminated through the
Company's payment of $5,586,000 to Enron. This settlement
resulted in a $355,000 gain to the Company.
Note 7. COMMITMENTS AND CONTINGENCIES
Operating Leases:
The Company leases office space, vehicles and software under
non-cancelable leases which expire in 1998. Rental expense is
recognized on a straight-line basis over the terms of the leases.
The total minimum rental commitments at December 31, 1995 are as
follows:
1996 $123,000
1997 110,000
1998 29,000
$262,000
Rent expense was $56,000, $74,000 and $83,000 for the years
ended December 31, 1993, 1994, and 1995, 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, 1993,
1994 and 1995, the Company made $6,000, $8,000 and $13,000,
respectively, of matching contributions. No discretionary
contributions were made during any of the three years in the
period ended December 31, 1995.
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, 1993, 1994 and 1995,
a total of $40,000, $59,000 and $69,000, 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 two years.
Note 8. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK
On April 15, 1994, the Company completed the private
placement (the "Placement") of 400,000 shares of Series B
Mandatorily Redeemable Convertible Preferred Stock, $0.01 par
value per share (the "Series B Stock"). The Series B Stock bears
an 8% dividend payable quarterly, and is convertible into shares
of the Company's common stock at an adjusted conversion price of
$4.18 per share. 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. Proceeds from the Placement were $3,774,000, net
of stock issue costs of $226,000. In connection with the Series
B Stock, dividends of $228,000 and $320,000 were paid in 1994 and
1995, respectively. Accretion of preferred stock was $30,000 and
$40,000 in 1994 and 1995, respectively.
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 1,100,918 outstanding shares of Series A Convertible
Preferred Stock (the "Series A 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 for a period of time. The
Series A Stock provides for a non-cumulative, preferential
dividend only to the extent declared by the Company's Board of
Directors. The Series A Stock has a preference upon liquidation
of $6,000,000 (the original face value); thereafter, after an
equivalent amount has been distributed to holders of the
Company's common stock, the Series A stockholders share
proportionately with the common stockholders. The Series A Stock
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 Stock has the right
to elect one director to the Company's Board of Directors. The
Series A Stock is not redeemable and may not be called.
Common Stock:
The Company has reserved 1,113,918 and 973,370 shares of
common stock for issuance upon a possible conversion of the
Series A Stock 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.
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 and continuing through 1999. During
1995, 41,000 shares vested, resulting in non-cash compensation
expense of $39,000. As of December 31, 1995, options for 155,737
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, 1993, 1994 and
1995. 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 expensed $12,000, $11,000
and $12,000 for the years 1993, 1994 and 1995, respectively, in
relation to the Stock Compensation Plan.
Effective October 1, 1995, the Compensation Committee of the
Board of Directors approved a plan whereby three of the Company's
executive officers would receive a portion of their compensation
in stock options, payable quarterly. The options are exercisable
at $0.01 per share. For the quarter ended December 31, 1995, the
officers were awarded options valued at $50,000.
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
for net proceeds of $8,025,000.
Subsequent to December 31, 1995, the Company agreed to issue
245,000 shares of common stock to certain consultants in exchange
for services valued at approximately $400,000.
Note 10. HEDGING ACTIVITIES
In November 1995, the Company entered into a "collar"
hedging transaction with an independent crude oil buyer covering
12,000 barrels per month of its oil production. Under this
arrangement, for each month beginning November 1995 through
October 1996, if the price for light sweet crude oil as quoted on
the New York Mercantile Exchange ("NYMEX") is less than $16.50
per barrel, the Company will receive the difference between
$16.50 and the average settlement price for that month for the
12,000 barrels subject to the collar agreement. If the average
settlement price exceeds $18.00 per barrel, the Company will pay
the difference between $18.00 and such average price on the
12,000 barrels. The premium for this collar is $.30 per barrel
payable monthly.
Also in November 1995, the Company entered into a "floor"
hedging transaction with an independent crude oil buyer covering
30,000 MMBTUs per month of the Company's gas production. Under
this arrangement, for each month beginning November 1995 through
October 1996, if the price for gas as quoted on the NYMEX is less
than $1.70, the Company will receive the difference between $1.70
and the average settlement price for that month for the 30,000
MMBTUs subject to the floor agreement. The premium for this
floor is $.095 MMBTU, payable monthly.
Note 11. MAJOR CUSTOMERS
Sales to customers in excess of 10% of total revenues were:
December 31,
1993 1994 1995
Customer A $222,000 $2,579,000 $ 2,213,000
Customer B 323,000 298,000 --
Customer C 308,000 573,000 1,319,000
Customer D 302,000 -- --
Note 12. INCOME TAXES
The Company incurred a loss for both book and tax purposes
in 1993, 1994, and 1995. There is no income tax benefit
(expense) for the years ended December 31, 1993, 1994 or 1995.
Deferred tax assets (liabilities) are comprised of the following
as of December 31, 1994 and 1995:
1994___ 1995
Deferred Tax Assets (Liabilities):
Net operating loss carryforwards $ 2,567,000 $ 5,000,000
Accumulated depreciation and
amortization differences 5,355,000 4,900,000
Other 209,000 200,000
Total deferred tax assets 8,131,000 10,100,000
Mining properties basis differences (1,312,000) (1,800,000)
Oil, gas and other properties basis
differences (5,856,000) (6,500,000)
Total deferred tax liabilities (7,168,000) (8,300,000)
Net deferred tax assets 963,000 1,800,000
Less valuation allowance (963,000) (1,800,000)
Net deferred tax assets
(liabilities) $ -- $ --
At December 31, 1995, the Company's remaining net operating
loss ("NOL") carryforwards were approximately $13,400,000, which
expire in varying amounts during the period 2005 through 2009.
This NOL carryforward is in addition to net operating losses
arising from the operations of Laguna prior to 1989 which can be
utilized only to the extent of future taxable income of Laguna.
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 13. 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, 1993, 1994, and 1995 is as follows:
December 31,
1993 1994 1995
Total assets:
Oil and gas $24,442,000 $23,746,000 $24,791,000
Mining 4,331,000 4,480,000 6,844,000
$28,773,000 $28,226,000 $31,635,000
United States $24,375,000 $23,777,000 $25,867,000
Costa Rica 4,398,000 4,449,000 5,768,000
$28,773,000 $28,226,000 $31,635,000
The following tables summarize the Company's revenues,
operating loss, depreciation, depletion and amortization and
capital expenditures by business segment for the years ended
December 31, 1993, 1994, and 1995:
December 31,
1993 1994 1995
Revenues:
Oil and gas $ 2,310,000 $ 5,082,000 $ 5,391,000
Mining 81,000 -- 37,000
$ 2,391,000 $ 5,082,000 $ 5,428,000
Operating loss:
Oil and gas $(1,090,000) $(1,427,000) $(1,176,000)
Mining (97,000) (204,000) (500,000)
$(1,187,000) $(1,631,000) $(1,676,000)
Depreciation, depletion and amortization:
Oil and gas $ 893,000 $ 2,389,000 $ 2,288,000
Mining 44,000 36,000 52,000
$ 937,000 $ 2,425,000 $ 2,340,000
Capital expenditures:
Oil and gas $20,326,000 $ 2,322,000 $ 2,645,000
Mining 313,000 57,000 1,238,000
$20,639,000 $ 2,379,000 $ 3,883,000
The following tables summarize the Company's revenues and net
loss by geographic area for the years ended December 31, 1993,
1994 and 1995:
1993 1994 1995
Revenues:
United States $ 2,310,000 $ 5,082,000 $5,428,000
Costa Rica 81,000 -- --
$ 2,391,000 $ 5,082,000 $5,428,000
Net loss:
United States $ (940,000) $(1,427,000) $(1,800,000)
Costa Rica (247,000) (204,000) (129,000)
$ (1,187,000) $(1,631,000) $(1,929,000)
Note 14. 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 $43,000 and $62,000 at December 31, 1994
and 1995, 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, 1994 and
1995, the Company had a payable to the related company of $7,000
and $25,000, 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
payables to the stockholder of $9,000 and $100,000 as of
December 31, 1994 and 1995, respectively, which are included in
accounts payable on the accompanying consolidated balance sheets.
During 1993, Red Rock purchased 50,000 shares of the
Company's common stock 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.
During the years ended December 31, 1994 and 1995, the
Company paid legal fees of $1,000 and $31,000 to a law firm of
which a director of the Company is a senior partner.
Additionally, consulting fees valued at $300,000 were paid to a
member of the same 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
offering costs of $200,000, of which $17,000 was payable at
December 31, 1994, 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
$200,000 in 1995, of which $90,000 was payable at December 31,
1995.
In February 1995, the Company entered into a Loan Agreement
establishing a $2,500,000 line of credit facility pursuant to
which it could 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. This line of
credit was retired in August 1995.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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
Date: April 12, 1996 By: /s/ George O. Mallon, Jr.
George O. Mallon, Jr.
Principal Executive Officer
Date: April 12, 1996 By: /s/ Duane C. Knight, Jr.
Duane C. Knight, Jr.
Principal Financial Officer
Principal Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities and on the date
indicated.
Date: April 12, 1996 By: /s/ George O. Mallon, Jr.
George O. Mallon, Jr.
Director
Date: April 12, 1996 By: /s/ Kevin M. Fitzgerald
Kevin M. Fitzgerald
Director
Date: April 12, 1996 By: /s/ James A. McGowen
James A. McGowen
Director
Date: April 12, 1996 By: /s/ Roy K. Ross
Roy K. Ross
Director
S-1
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Registration Statement on Form S-8 (No. 33-39635) and in the
Prospectus constituting part of the Registration Statement on
Form S-3 (No. 33-65846) of Mallon Resources Corporation of our
report dated April 12, 1996 appearing on page F-2 of this Form
10-K.
/s/ Price Waterhouse LLP
Price Waterhouse LLP
Denver, Colorado
April 12, 1996
23
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