Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K/A
Amendment to Report
Filed Pursuant to Section 12, 13 or 15(d) of the Securities
Exchange Act of 1934
Mallon Resources Corporation
(Exact name of Registrant as specified in its charter)
0-17267
(Commission file number)
Amendment No. 1
The undersigned registrant hereby amends the following items,
financial statements, exhibits or other portions of its Annual
Report on Form 10K for the year ended December 31, 1996 (the "1996
Form 10-K"), as set forth in the pages attached hereto:
Items 1 and 2 of the 1996 Form 10-K
Item 6 of the 1996 Form 10-K
Item 7 of the 1996 Form 10-K
(List of all such items, financial statements, exhibits or other
portions amended)
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned hereunto duly authorized.
Mallon Resources Corporation
December 3, 1997 /s/ Roy K. Ross
Roy K. Ross, Executive Vice President
Items 1 and 2 of the 1996 Form 10-K are hereby amended to read in
their entirety as follows:
ITEMS 1 AND 2: BUSINESS AND PROPERTIES
General History
Mallon Resources Corporation, a Colorado corporation (the
"Company"), is an independent energy company engaged in domestic
oil and gas development, exploration and production. The Company
was organized in 1988 in connection with the consolidation of
Mallon Oil Company ("Mallon Oil") and Laguna Gold Company
("Laguna"). From inception, the Company has engaged in two
separate and distinct facets of the natural resources business:
through Mallon Oil the Company pursued its core oil and gas
business, and through Laguna the Company engaged in mining
activities. By early 1996, the Company concluded that the level
of capital and management resources required to fully develop each
of these businesses made it inadvisable for the Company to
continue to pursue both. Accordingly, over the course of 1996 the
Company reduced its ownership interest in Laguna from 80% to 56%.
By establishing Laguna's financial independence through a Canadian
financing and listing on The Toronto Stock Exchange, the Company
is now able to focus all of its efforts on the oil and gas
business. Since the completion of those events, Laguna has been
operating independently, without reliance on the Company for
financial support.
In light of the recent implementation of this fundamental change
in the manner in which the Company will henceforth pursue its
business, the Company's past performance is not necessarily
indicative of its future operations.
The Company's common stock is traded on the Nasdaq National Market
tier of the Nasdaq Stock Market under the 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.
Overview of Oil and Gas Operations
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. The Company's activities
are focused in the Delaware Basin of southeast New Mexico where it
has been active since 1982, and in the San Juan Basin of northwest
New Mexico where it has been active since 1984. Numerous
potentially productive geologic formations and zones tend to be
stacked atop one another in the Delaware and San Juan Basins.
This feature allows most wells to target multiple potential pay
zones, thus reducing drilling risks. It also permits the Company
to conduct exploration operations in conjunction with its
development drilling. Wells drilled to one horizon offer
opportunities to examine potential up-hole zones or can be drilled
to deeper prospective formations for relatively little additional
cost. Due to its substantial acreage positions and operating
experience in these areas, the Company intends to continue to
concentrate its operational efforts on these two basins for the
foreseeable future.
The Company's objectives are to develop its inventory of
properties, expand its oil and gas reserves and increase its cash
flow. The Company intends to pursue these objectives by
increasing its drilling and recompletion activities on its
Delaware and San Juan Basin properties, while maintaining control
over its drilling, completion and operating costs.
In September 1993, in a significant acquisition, the Company
purchased its core group of Delaware Basin properties from
Pennzoil Exploration and Production Company. In October 1996, the
Company completed a significant financing in which it sold 2.3
million shares of common stock for net proceeds of approximately
$13.2 million. For the first time in the Company's history, the
Company has funds available to develop and exploit the Company's
substantial inventory of oil and gas properties.
In December 1996, the Company entered into an agreement to acquire
additional interests in some of its San Juan Basin gas properties
and to become operator of those properties. The Company assumed
operations on December 31, and title to the properties passed on
January 1, 1997. The reserve information reported in various
places in Items 1 and 2 of this report includes the reserves
attributable to this acquisition as if the Company owned them on
December 31, 1996. See Note 17 to the Consolidated Financial
Statements for a presentation of reserve information excluding
this transaction. The Company increased its estimated proved
reserves from 2.2 MMBOE as of December 31, 1992, to 6.4 MMBOE as
of December 31, 1996, a 191% increase. As of December 31, 1996,
the Company's proved reserves, as estimated by its independent
petroleum engineers, GeoQuest Reservoir Technologies, Inc.
("GeoQuest"), consisted of 1.7 MMBbls of crude oil and 28.4 Bcf of
natural gas, with a Pre-tax SEC 10 Value of $50.0 million. At
December 31, 1996, the Company owned interests in 227 gross (74
net) producing wells and operated 108, or 48%, of them.
Selected Fields and Areas of Interest
The Company's activities are focused in the Delaware Basin of
southeastern New Mexico and in the San Juan Basin of northwestern
New Mexico. At December 31, 1996, these areas accounted for
substantially all of the Company's estimated proved reserves, with
3.8 MMBOE attributable to the Company's Delaware Basin properties
and 2.6 MMBOE attributable to its San Juan Basin properties.
Delaware Basin, Southeastern New Mexico
The Delaware Basin has been an area of significant activity for
the Company since 1982, when the Company acquired an interest in
the Brushy Draw field. Wells in the Delaware Basin produce from a
variety of formations, the principal of which are the Cherry
Canyon, Brushy Canyon, Strawn and Morrow Formations. These
formations each contain multiple potentially productive zones.
The Cherry Canyon and Brushy Canyon formations are shallow and
primarily produce oil, while the deeper Strawn and Morrow
Formations generally produce natural gas. The Company's primary
properties in the Delaware Basin are in the Lea Northeast, Quail
Ridge, White City and South Carlsbad fields. The Company also
continues to assess potential in its Shipp, Lovington Northeast
and Brushy Draw properties. The Company owns interests in
approximately 24,500 gross (19,300 net) acres of oil and gas
leases in the Delaware Basin.
Lea Northeast Field, Lea County, New Mexico. The Company is
actively developing a Cherry Canyon Formation play in this field.
Since 1994, it has drilled 14 wells here, 11 of which were
productive and one of which is used as a salt water disposal well.
In 1996, the Company drilled three wells here, two of which were
completed in the Cherry Canyon. These wells extended the
productive limits of the Lea Northeast Field by more than a mile
to the northwest. The Company currently operates 12 wells in this
field. The Company's wells in Lea Northeast typically target
between 10 and 15 zones that are productive in the area. The
primary producing interval in the field is in the Cherry Canyon
Formation, although more recently attention has also been directed
to the deeper Brushy Canyon Formation. The Company intends to
drill wells to 10,500 feet in order to test zones in the Bone
Springs Formation, which is also productive on portions of the
Company's acreage. These formations contain multiple reservoir
zones that occur at depths between 5,500 and 8,200 feet. The
Company intends to drill additional wells in Lea Northeast during
1997 and has delineated 30 additional drill locations in the
field. The Company's working interest in these wells ranges from
36% to 84%, and averages approximately 55%.
Quail Ridge, Lea County, New Mexico. Adjacent to Lea
Northeast, the Company controls a large block of acreage on which
it operates wells producing from the Bone Springs, Atoka, and
Morrow Formations. The Quail Ridge Field has produced primarily
gas from the Morrow sandstone at depths of approximately 13,500
feet. The Company currently has an interest in 10 wells in this
area and operates five of them. The Company plans to further
develop this block by drilling at least seven wells in 1997.
These wells will be drilled for production from the same Cherry
Canyon Formation and Brushy Canyon Formation zones found by the
Company's recent development activities in Lea Northeast, and, if
successful, would extend the limits of the field by more than two
miles to the northwest. The Company controls an approximate 40%
working interest in this acreage.
White City and South Carlsbad Fields, Eddy County, New
Mexico. These adjacent fields have been the focus of much of the
Company's recompletion and development activities since 1993. The
Company has interests in 29 wells in these fields and operates 11
of them. In 1996, the Company drilled a successful Morrow gas
well and successfully recompleted Morrow gas wells drilled in
prior years in the Canyon, Strawn, and Atoka Formations. Plans
for development include drilling additional wells to the Morrow at
12,000 feet and developing shallower Cherry Canyon zones. Like
all of the Company's recent drilling, a Morrow well will allow for
exploration of various up-hole zones in the Cherry Canyon and
Brushy Canyon Formations at depths from 1,500 to 5,300 feet, as
well as the targeted Canyon, Strawn, Atoka and Morrow Formations,
which range in depth from 9,000 feet to 12,000 feet. The
Company's working interest averages 38%.
Shipp and Lovington Northeast Fields, Lea County, New Mexico.
Shipp and Lovington Fields are comprised of a collection of
individual reservoirs, or algal mounds, in a Strawn Formation
interval at depths of approximately 11,500 feet. The mounds range
in size from 100 to 700 acres. The Company has interests in 33
wells and operates 23 wells in these adjacent fields. During
1996, the Company initiated a low installation cost pilot
waterflood project on one of these mounds. The Company will
evaluate the success of this secondary recovery project and
determine the feasibility of expanding the project to other mounds
in the fields. The Company's working interest averages 33% in
Lovington Northeast, and 46% in Shipp.
Brushy Draw Field, Eddy County, New Mexico. The Company's
initial drilling and field development here began in 1982.
Current production is from the base of the Cherry Canyon
Formation, at a depth of approximately 5,000 feet. The Company
operates 14 wells with an average working interest of 68%. The
Company will continue its Cherry Canyon development here, and
drill three wells in 1997, which will also be analyzed to evaluate
potential productive zones in the Brushy Canyon Formation.
San Juan Basin, Northwestern New Mexico
The San Juan Basin has been a significant area of activity for the
Company since 1984. The Company's primary areas of interest in
the San Juan Basin are the East Blanco, Gavilan and Otero areas.
At December 31, 1996, the Company owned interests in approximately
31,000 gross (16,500 net) acres of oil and gas leases in the San
Juan Basin. Wells on these leases produce from a variety of zones
in the Pictured Cliffs, Mesaverde, Mancos and Dakota Formations
and primarily produce natural gas.
East Blanco Area, Rio Arriba County, New Mexico. This area
has been under development by the Company since 1986. The Company
holds interests in 23 wells in this area. All production in the
area has been natural gas, and East Blanco wells typically contain
reserves in more than one productive zone, primarily in the
Pictured Cliffs Formation and the Ojo Alamo Formation. The wells
also penetrate the Fruitland Coal Formation, which is productive
in fields adjacent to East Blanco. At present, the Company has
identified 44 potential drilling and recompletion locations on its
East Blanco acreage. Of the locations currently identified, 14
have been assigned proved undeveloped reserves in the Pictured
Cliffs or Ojo Alamo Formations. At December 31, 1996, the Company
owned a 59% average working interest in a 20,000 acre block to the
bottom of the Pictured Cliffs Formation. In a transaction
completed on January 1, 1997, the Company enhanced its ownership
interest in this area to an average 81% working interest in a
23,400 acre block and became operator of the acreage. For 1997,
the Company has scheduled recompletion operations for several of
the Pictured Cliffs wells in this area, in order to test the
productive properties of the up-hole Ojo Alamo and Fruitland Coal
formations.
Gavilan Field, Rio Arriba County, New Mexico. The Company
operates seven wells in this field. Current production is
primarily natural gas from the Mancos Formation at approximately
5,600 feet. In 1997 the Company plans to recomplete three wells
in the Mesaverde Formation and to use such wells to test the
Pictured Cliffs gas sand and two additional Mesaverde pays. The
Company holds an average 34% working interest in this acreage.
Otero Field, Rio Arriba County, New Mexico. The Company
operates its two wells in this field, which produce oil from the
Mancos Formation at approximately 5,300 feet. The Company intends
to drill two wells in this field in 1997, which will commingle
production from the Pictured Cliffs, Mesaverde and Mancos
Formations. The Company has an 88% working interest in this
acreage.
Other Areas
All of the Company's oil and gas operations are currently
conducted on-shore in the United States. In addition to the
properties described above, it has properties in the states of
Colorado, Oklahoma, Wyoming, North Dakota and Alabama. While it
intends to continue to produce its current wells in those states,
it currently does not expect to engage in any development
activities in those areas. The Company also owned a 2.25% working
interest in an exploration venture that drilled a dry hole
exploration well offshore Belize in 1997.
Acreage
The majority of the Company's producing oil and gas properties are
located on leased land held by the Company for as long as
production is maintained. The Company 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. The following table summarizes the Company's oil and
gas acreage holdings as of December 31, 1996.
<TABLE>
<CAPTION>
Developed Undeveloped
Area Gross Net Gross Net
<C> <S> <S> <S> <S>
Delaware Basin 23,002 18,975 1,560 312
San Juan Basin 10,308 3,503 20,773 13,033
Other 10,225 3,953 2,931 50
Total 43,535 26,431 25,264 13,395
</TABLE>
Much of the Delaware Basin developed acreage relates to deeper
natural gas zones as to which larger spacing rules apply. Most of
this developed acreage is undeveloped as to shallower zones.
Proved Reserves
The following table sets forth summary information concerning the
Company's proved oil and gas reserves as of December 31, 1996, as
estimated in a report (the "GeoQuest Report") prepared by
GeoQuest. All calculations have been made in accordance with the
rules and regulations of the Securities and Exchange Commission
(the "Commission"). The present value of estimated future net
revenues has been calculated using a discount factor of 10%.
<TABLE>
<CAPTION>
Oil Gas Total
(MBbl) (MMcf) (MBOE)
<C> <S> <S> <S>
Proved developed reserves 1,225 20,521 4,645
Proved undeveloped reserves 482 7,868 1,784
Total proved reserves 1,707 28,388 6,439
Future net revenues before
income taxes (in thousands) $93,026
Present value of future net
revenues before income
taxes (in thousands) $49,957
</TABLE>
Drilling Activity
The following table sets forth, for each of the last three years,
the drilling activities conducted by the Company:
<TABLE>
<CAPTION>
Development Wells
Gross Wells Net Wells
Productive Dry Total Productive Dry Total
<C> <S> <S> <S> <S> <S> <S>
1996 4 1 5 2.69 0.34 3.03
1995 7 1 8 4.64 0.68 5.32
1994 4 0 4 1.75 0.00 1.75
Exploratory Wells
Gross Wells Net Wells
Productive Dry Total Productive Dry Total
1996 0 0 0 0 0 0
1995 1 0 1 .3 0 .3
1994 0 0 0 0 0 0
</TABLE>
From January 1, 1997 to March 25, 1997 the Company drilled seven
development wells in the United States that are not reflected in
the above table. Five of those wells have been completed and two
are currently awaiting completion. The Company also drilled one
gross (0.02 net) dry exploration well in Belize.
Productive Wells
The following table summarizes the Company's gross and net
interests in productive wells at December 31, 1996.
<TABLE>
<CAPTION>
Gross Wells Net Wells
Oil Natural Gas Total Oil Natural Gas Total
<C> <S> <S> <S> <S> <S> <S>
118 109 227 39.7 34.7 74.4
</TABLE>
In addition, the Company owns interests in four waterflood units,
which contain a total of 544 gross wells (8.5 net wells), and four
gross (2.1 net) salt water disposal wells.
Production and Sales
The following table sets forth information concerning the
Company's total oil and gas production (including deliveries under
its volumetric production payment, which was retired in August
1995) and sales for each of the last three years.
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
<C> <S> <S> <S>
Net Production:
Oil (MBbl) 174 173 146
Natural gas (MMcf) 1,286 1,238 1,648
BOE 388 379 421
Average Sales Price Realized (1):
Oil (per Bbl) $18.05 $16.45 $14.81
Natural gas (per Mcf) $ 2.11 $ 1.58 $ 1.50
Per BOE $15.09 $12.66 $11.00
Average Cost (per BOE):
Production costs $ 5.80 $ 4.93 $ 4.81
Depletion $ 4.96 $ 5.70 $ 5.53
Producing Wells (at end of period) (2):
Gross Wells 227 222 220
Net Wells 75 71 66
</TABLE>
1) Includes effects of hedging. See "Management's Discussion
and Analysis of Financial Condition and Results of
Operations--Hedging Activities."
2) In addition, the Company owns interests in four waterflood
units, which contain a total of 544 gross wells (8.5 net
wells), and four gross (2.1 net) salt water disposal wells.
Laguna Gold Company
At December 31, 1996, the Company owned approximately 14 million
common shares, representing an approximate 56% interest, in
Laguna, a company with development stage gold mining concessions
in Costa Rica. To establish itself as a financially independent
company, Laguna completed a financing in Canada in September 1996,
and listed its common shares on The Toronto Stock Exchange under
the trading symbol "LGC." Laguna received approximately
$4.3 million of net proceeds from its Canadian financing, which
should permit Laguna to continue its operations without further
reliance on the Company for financial support. The Company does
not have any obligation or intention to finance Laguna's future
operations. In conjunction with Laguna's Canadian financing, the
Company sold 400,000 shares of Laguna common stock and realized a
gain of $329,000. Over the course of the year, the Company
reduced its ownership interest in Laguna from 80% to 56%, and may
continue to reduce its investment in Laguna in the future.
Approximately 8.4 million of the Laguna shares owned by the
Company are subject to an escrow agreement with The Toronto Stock
Exchange that restricts the ability of the Company to sell such
shares for up to three years. For industry segment information
concerning Laguna, see Note 15 to the Consolidated Financial
Statements.
Laguna is engaged in the exploration for and development of
precious metals in Costa Rica, where it holds mineral concessions
issued by the Government of Costa Rica. The concessions contain
the Rio Chiquito Deposit. Laguna commenced active exploration and
evaluation of Rio Chiquito in March 1984. In October 1987, Laguna
commenced a small pilot heap leach mining operation at the Rio
Chiquito Deposit. In July 1989, Laguna concluded that efficient
commercial exploitation of the project would require a
substantially larger operation than the pilot project.
Accordingly, the project was suspended pending additional
development and funding. The pilot project produced a total of
3,800 ounces of gold and 28,600 ounces of silver.
Further exploration and evaluation of the Rio Chiquito Deposit has
been undertaken since 1989. Based on the results of a stream
sediment geochemical sampling program, the Rio Chiquito Deposit
was found to be located within an arsenic/gold anomaly
approximately 250 acres in size. Pit exposures and core drilling
indicate that the mineralization is found in polyphase stockwork
quartz veining and hydrothermal breccias that formed in andesitic
lavas and pyroclastics. Identified mineralization lies in the
area of the pilot project pit and to the south, along a strike
length of approximately 400 meters.
In September 1997, Laguna reported that the mineralized deposit at
Rio Chiquito consists of an estimated 71.9 million tonnes grading
0.29 grams per tonne gold and 4.81 grams per tonne silver. Laguna
also reported that most of the requisite feasibility work for the
commercial development of Rio Chiquito has been completed, and
that it believes the Rio Chiquito Deposit can be placed on
production if sufficient development capital can be raised.
However, Laguna gives no assurance that any such funding can be
secured, or as to the terms upon which capital may be available.
Pending receipt of the capital required to develop Rio Chiquito,
Laguna has furloughed workers in Costa Rica and otherwise
curtailed its expenditures in order to conserve its cash.
General Matters
Executive Officers and Key Employees
The Executive Officers and key employees of the Company are as
follows:
<TABLE>
<CAPTION>
Name Age Title(s) Since
<C> <S> <S> <S>
George O. Mallon, Jr. 52 President, Chairman of the Board 1988
Kevin M. Fitzgerald 42 Executive Vice President 1988
Roy K. Ross 46 Executive Vice President,
General Counsel 1992
Alfonso R. Lopez 48 Vice President-Finance,
Treasurer 1996
Carolena F. Chapman 53 Secretary, Controller 1989
Ray E. Jones 43 Vice President-Engineering
of Mallon Oil 1994
Randy Stalcup 42 Vice President-Land
of Mallon Oil 1995
Wendell A. Bond 50 Vice President-Geology
of Mallon Oil 1996
Donald M. Erickson, Jr. 41 Vice President-Operations
of Mallon Oil 1997
Duane Winkler 42 Operations Manager
of Mallon Oil 1993
</TABLE>
George O. Mallon, Jr., formed Mallon Oil in 1979 and was a co-
founder of Laguna in 1980. He became Chairman of the Board of the
Company upon its formation in December 1988. 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. He was named
Executive Vice President of the Company in 1990. Mr. Fitzgerald
earned a B.S. degree in Petroleum Engineering from the University
of Oklahoma in 1978.
Roy K. Ross joined the Company as Executive Vice President and
General Counsel 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. 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.
Alfonso R. Lopez joined the Company in July 1996 as Vice
President-Finance and Treasurer. He was Vice President-Finance
for Consolidated Oil & Gas, Inc. (now Hugoton Energy Corporation)
from 1993 to 1995. Mr. Lopez was a consultant from 1991 to 1992.
From 1981 to 1990, he was Controller for Decalta International
Corporation, a Denver based oil and gas exploration and production
company. Mr. Lopez, a certified public accountant, earned his
B.A. degree in Accounting and Business Administration from Adams
State College in Colorado in 1970.
Carolena F. Chapman is Secretary and Controller of the Company.
She joined Mallon Oil in 1979. She was named to her present
positions with the Company in October 1989.
Ray E. Jones is Vice President-Engineering of Mallon Oil. Before
joining the Company in January 1994, Mr. Jones spent eight years
with Jerry R. Bergeson & Associates (now GeoQuest), an independent
consulting firm, where he did reservoir engineering, field studies
and reserve evaluations, and taught industry courses in basic
reservoir engineering, reservoir simulation and well testing.
Mr. Jones graduated from the Colorado School of Mines in 1979, and
is a registered professional engineer.
Randy Stalcup joined Mallon Oil as Vice President-Land in
April 1995. Prior to joining the Company, Mr. Stalcup was
employed by Beard Oil Company for 13 years, where he was
Acquisition and Unitization Manager from 1989. Mr. Stalcup, a
Certified Professional Landman, earned his B.B.A. degree in
Petroleum Land Management from the University of Oklahoma in 1979.
Wendell A. Bond, Vice President-Geology of Mallon Oil, joined the
Company on a full time basis in 1996. He had served as an
independent geological consultant to the Company since July 1994
through Wendell A. Bond, Inc., a company specializing in petroleum
geological consulting services that he formed in 1988. Prior to
1988, Mr. Bond had been employed in a variety of positions for
several independent and major oil and gas companies, including
Project Geologist for Webb Resources, District Geologist for Sohio
Petroleum and Chief Geologist for Samuel Gary Jr. & Associates.
Mr. Bond earned his B.S. degree in geology from Capital
University, Columbus, Ohio, and his M.S. degree in geology from
the University of Colorado.
Donald M. Erickson, Jr., joined Mallon Oil as Vice President-
Operations in February 1997. Mr. Erickson has more than 21 years
of experience in oil field operations. Prior to joining the
Company, he was Operations Manager for Presidio Exploration, Inc.
(which was merged into Tom Brown Inc.) from December 1988. Mr.
Erickson earned a Heating and Cooling Technical Degree from
Central Technical Community College in Hastings Nebraska in 1975,
and has studied Mechanical Engineering at the University of
Denver.
Duane Winkler is Operations Manager of Mallon Oil, working out of
the Carlsbad, New Mexico office. Before joining the Company in
October 1993, he was employed by Natural Gas Processing as
Production Superintendent from 1986 to 1993. Mr. Winkler, who has
24 years of experience in drilling, completion and production
operations, completed his Associates of Engineering Certificate
from Central Wyoming College in 1996.
At March 25, 1997, the Company had 19 full-time employees in its
Denver office and 7 full-time employees in its Carlsbad, New
Mexico, office. The Company believes it has good relations with
its employees.
Marketing
The Company's oil and liquids are generally 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, the Company 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. The Company nevertheless believes that hedging is
prudent in certain circumstances in order to minimize the risk of
falling prices.
Cautionary Statement Regarding Forward-Looking Statements
The discussion in this report contains certain forward-looking
statements that involve risks and uncertainties. The Company's
actual results could differ significantly from those discussed
herein. Factors that could cause or contribute to such
differences include, but are not limited to, those discussed in
"Special Considerations," and "Management's Discussion and
Analysis of Financial Condition and Results of Operations," as
well as those discussed elsewhere in this report. Statements
contained in this report that are not historical facts are
forward-looking statements that are subject to the safe harbor
created by the Private Securities Litigation Reform Act of 1995.
Special Considerations
In evaluating the Company and its Common Stock, readers should
consider carefully, among other things, the following special
considerations.
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, which can be extremely volatile. In general, hydrocarbon
prices are affected by numerous factors such as economic,
political and regulatory developments. Prices have risen recently
but there can be no assurance that such price levels will be
sustained. 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, makes 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 could have a
material adverse effect on the Company's financial condition,
liquidity and results of operations. Additionally, substantially
all of the Company's sales of oil and natural gas are made in the
spot market or pursuant to contracts based on spot market prices
and not pursuant to long-term fixed price contracts. With the
objective of reducing price risk, the Company enters into hedging
transactions with respect to a portion of its expected future
production. There can be no assurance, however, that such hedging
transactions will reduce risk or mitigate the effect of any
substantial or extended decline in oil or natural gas prices.
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. The Company conducts substantially all of its operations
in the Delaware and San Juan Basins in the State of New Mexico
and, consequently, is particularly subject to marketing
constraints that exist or may arise in the future in those areas.
Historically, due to the San Juan Basin's relatively isolated
location and the resulting limited access its natural gas
production has to the natural gas marketplace, natural gas
produced in the San Juan Basin has tended to command prices that
are lower than natural gas prices that prevail in other areas.
Uncertainty of Estimates of Reserves and Future Net Revenues
This report contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based
upon the GeoQuest Report, that relies upon various assumptions,
including assumptions required by the Commission as to oil and gas
prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. The process of estimating oil
and gas reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. As
a result, such estimates are inherently imprecise. Actual future
production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil
and gas reserves may vary substantially from those estimated in
the GeoQuest Report. Any significant variance in these
assumptions could materially affect the estimated quantity and
value of reserves set forth in this report. In addition, the
Company's reserves may be subject to downward or upward revision
based upon production history, results of future development and
exploration, prevailing oil and gas prices and other factors, many
of which are beyond the Company's control. Actual production,
revenues, taxes, development expenditures and operating expenses
with respect to the Company's reserves will likely vary from the
estimates used, and such variances may be material.
Approximately 28% of the Company's total proved reserves at
December 31, 1996, were undeveloped, which are by their nature
less certain. Recovery of such reserves will require significant
capital expenditures and successful drilling operations. The
reserve data set forth in the GeoQuest Report assumes, based on
the Company's estimates, that aggregate capital expenditures by
the Company of approximately $6.4 million through 1998 will be
required to develop such reserves. Although cost and reserve
estimates attributable to the Company's oil and gas reserves have
been prepared in accordance with industry standards, no assurance
can be given that the estimated costs are accurate, that
development will occur as scheduled or that the results will be as
estimated.
The present value of future net revenues referred to in this
report should not be construed as the current market value of the
estimated oil and gas reserves attributable to the Company's
properties. In accordance with applicable requirements of the
Commission, the estimated discounted future net cash flows from
proved reserves are generally based on prices and costs as of the
date of the estimate, whereas actual future prices and costs may
be materially higher or lower. Actual future net cash flows also
will be affected by changes in consumption and changes in
governmental regulations or taxation. The timing of actual future
net cash flows from proved reserves, and thus their actual present
value, will be affected by the timing of both the production and
the incurrence of expenses in connection with development and
production of oil and gas properties. In addition, the 10%
discount factor, which is required by the Commission to be used in
calculating discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks
associated with the Company or the oil and gas industry in
general.
Need for Additional Capital
Due to its active development and exploration program, the Company
has substantial working capital requirements. The Company
believes its current capital and cash flow from operations will
allow the Company to successfully implement its present business
strategy. Additional financing may be required in the future to
fund the Company's developmental and exploratory drilling. No
assurances can be given as to the availability or terms of any
such additional financing that may be required. In the event such
capital resources are not available to the Company, its drilling
activity may be curtailed.
Replacement of Reserves
The Company's future success will depend upon its ability to find,
develop or acquire additional oil and gas reserves at prices that
permit profitable operations. Unless the Company conducts
successful exploitation or exploration activities or acquires
properties containing reserves, the proved reserves of the Company
will decline. There can be no assurance that the Company's
acquisition, exploitation and exploration activities will result
in additional reserves, or that the Company will be able to drill
productive wells at acceptable costs.
Operating Hazards; Uninsured Risks
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
activities 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 activities are subject
to a wide variety of federal, state, local and foreign
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 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, 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. 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 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 governmental agencies and
third parties, and may require the Company to incur costs to
remedy such discharges. Oil, natural gas and other pollutants
(including salt water brine) 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 other facilities. Discharged
hydrocarbons and other 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 oil and natural
gas exploration, production and transportation and may, in
addition to other laws and regulations, impose liability in the
event of discharges (whether or not accidental), failure to notify
the proper authorities of a discharge, and other failures to
comply with those laws and regulations. Compliance with
environmental quality requirements and reclamation laws imposed by
governmental authorities may necessitate significant capital
outlays, may materially affect the acquisition or operating costs
of a given property, or may cause material changes or delays in
the Company's intended activities. Management of the Company does
not believe that its environmental, health, and safety risks are
materially different from those of comparable companies engaged in
similar businesses. Nevertheless, new or different environmental
standards imposed in the future may adversely affect the Company's
activities and 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.
Ownership Interest in Laguna
The Company currently owns approximately 14 million shares of
Laguna common stock. The Company has no current plans for
disposing of such shares, and approximately 8.4 million of the
shares owned by the Company are subject to an escrow agreement
with The Toronto Stock Exchange that restricts the ability of the
Company to sell such shares for up to three years. No assurance
can be given as to the value that might be received by the Company
in the future from any transaction in which such interest is sold.
Furthermore, although the common stock of Laguna is publicly
traded in Canada on The Toronto Stock Exchange, trading prices on
that exchange are not necessarily representative of the
consideration the Company could obtain for such shares currently
or in the future.
The value of the Company's investment in Laguna will be affected
by the business results of Laguna. There are many uncertainties
in any mineral exploration and development program, such as the
location of economic ore bodies, the receipt of necessary
government permits and the construction of mining and processing
facilities, as well as widely fluctuating prices of minerals.
Because Laguna's properties are in Costa Rica, additional
uncertainties include currency risks, risks of changes in foreign
laws and the risk of expropriation. Substantial expenditures will
be required to pursue Laguna's exploration and development
activities, and substantial time may elapse from the initial
phases of development until Laguna's activities are fully
operational.
Statement of Financial Accounting Standards No. 121 ("SFAS 121")
requires that an impairment loss be recognized in the event that
facts and circumstances indicate that the carrying amount of an
asset may not be recoverable. Estimated future undiscounted net
cash flow projections developed by Laguna to assess the
recoverability of its properties include consideration of the
following factors, among others: projected mineable reserves
based upon third party engineering reports; estimated capital
expenditures required to put the mine on production; projected
rates of gold and silver production; estimated waste handling and
stripping costs; projected mine life; recovery rates for gold and
silver; and estimated gold and silver prices. The timing of
projected cash flows is based on the estimated mine life and the
estimated cost to bring the mine into production. The testing
takes into account the type of processing proposed -- either a
mill or a heap leach - and the timing of the capital expenditures
required, which vary. The budgeted capital expenditures are also
varied depending on the type of process assumed. The SFAS 121
impairment testing at December 31, 1996 concluded that no
impairment loss was required to be recognized. While impairment
testing is designed to assure that recorded costs are recoverable
under assumed, ordinary course operations at a particular point in
time, such testing cannot assure that such costs will be recovered
in the event of a sale or other disposition of the property or of
the Company's interest in Laguna as a whole. Moreover, many of
the factors assumed in performing the testing (including prices
and costs) are matters outside Laguna's control and are subject to
change over time.
Reliance on Key Personnel
The Company is dependent upon its executive officers, key
employees and certain consultants. The unexpected loss of
services of one or more of these individuals could have a
detrimental effect on the Company. The Company does not maintain
key man insurance on any of its executive officers or key
employees. In addition, the continued growth and expansion of the
Company will depend upon, among other factors, the successful
retention of skilled and experienced management and technical
personnel.
Competition
The oil and gas industry and the mining industry are both 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.
Item 6 of the 1996 Form 10-K is hereby amended to read in its
entirety as follows:
ITEM 6: SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial
data for each of the years in the five-year period ended
December 31, 1996. 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>
Year Ended December 31,
1996 1995 1994 1993 1992
(In thousands, except per share data)
<C> <S> <S> <S> <S> <S>
Selected Statements of Operations Data:
Revenues:
Oil and gas sales $ 5,854 $ 4,800 $ 4,629 $ 2,061 $ 1,408
Other 666 628 280 230 568
6,520 5,428 4,909 2,291 1,976
Costs and expenses:
Oil and gas production 2,249 1,868 2,024 976 800
Mining project expenses 1,014 838 459 390 380
Depreciation, depletion and
amortization 2,095 2,340 2,409 937 306
Impairment of oil and gas properties 264 -- -- -- --
General and administrative 1,999 1,625 1,516 926 682
Interest and other 842 433 132 249 76
8,463 7,104 6,540 3,478 2,244
Minority interest in loss of
consolidated subsidiary 266 -- -- -- --
Loss before extraordinary item (1,677) (1,676) (1,631) (1,187) (268)
Extraordinary loss on early retirement
of debt (160) (253) -- -- --
Net loss (1,837) (1,929) (1,631) (1,187) (268)
Dividends on preferred stock and
accretion (376) (360) (258) -- --
Net loss attributable to common
shareholders $(2,213) $(2,289) $(1,889) $(1,187) $ (268)
Selected Per Share Data (1):
Loss attributable to common share-
holders before extraordinary item $ (0.82) $ (1.04) $ (1.00) $ (0.87) $ (0.22)
Extraordinary loss (0.06) (0.12) -- -- --
Net loss attributable to common
shareholders $ (0.88) $ (1.16) $ (1.00) $ (0.87) $ (0.22)
Weighted average shares outstanding 2,512 1,947 1,916 1,368 1,195
Selected Cash Flow and Other Data:
EBITDA (2) $ 1,520 $ 1,093 $ 876 $ (79) $ 56
Capital expenditures 6,339 3,883 2,379 20,612 190
</TABLE>
<TABLE>
<CAPTION>
At December 31,
1996 1995 1994 1993 1992
<C> <S> <S> <S> <S> <S>
Selected Balance Sheet Data:
Total assets $41,400 $31,635 $28,226 $28,773 $7,675
Long-term debt (3) 3,511 10,037 -- 20 30
Mandatorily redeemable preferred stock 3,900 3,844 3,804 -- --
Shareholders' equity 21,904 11,760 13,549 15,029 6,738
</TABLE>______________
1) As adjusted for four-to-one reverse stock split.
2) EBITDA is earnings before income taxes, interest expense,
depreciation, depletion and amortization, impairment, and
extraordinary loss. EBITDA is a financial measure commonly used
in the Company's industry and should not be considered in
isolation or as a substitute for net income, cash flow provided by
operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a
measure of a company's profitability or liquidity. The Company
believes that EBITDA may provide additional information about the
Company's ability to meet its future requirements for debt
service, capital expenditures and working capital. When
evaluating EBITDA, investors should consider, among other factors,
(i) increasing or decreasing treads in EBITDA, (ii) whether EBITDA
has remained at positive levels historically and (iii) how EBITDA
compares to levels of interest expense. Other companies may
define EBITDA differently, and as a result, such measures may not
be comparable to the Company's EBITDA.
3) Long-term debt includes long-term debt net of current
maturities, notes payable-other and capital lease obligations net
of current portion.
Item 7 of the 1996 Form 10-K is hereby amended to read in its
entirety as follows:
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding
the Company's historical consolidated financial position at
December 31, 1996, 1995 and 1994, and results of operations and
cash flows for each of the three years in the period ended
December 31, 1996. The Company's historical Consolidated
Financial Statements and notes thereto included elsewhere herein
contain detailed information that should be referred to in
conjunction with the following discussion. The financial
information discussed below is consolidated information, which
includes the accounts of Laguna.
Overview
Historically, the Company has engaged in two separate and distinct
facets of the natural resources business. Through Mallon Oil, the
Company has pursued its core oil and gas business. Through
Laguna, the Company has engaged in mining activities. By early
1996, the Company concluded that the level of capital and
management resources required to fully develop each of these
businesses made it inadvisable for the Company to continue to
pursue both. Accordingly, the Company separated the businesses by
establishing the financial independence of Laguna and having the
Company focus its efforts on the oil and gas business. Laguna's
recent Canadian financing and listing on The Toronto Stock
Exchange were the key steps toward accomplishment of that goal and
should permit Laguna to operate independently without further
reliance on the Company for financial support. The Company does
not have any obligation or intention to finance Laguna's future
operations.
In light of the recent implementation of this fundamental change
in the manner in which the Company will henceforth pursue its
business, the Company's past financial performance is not
necessarily indicative of its future operations.
The Company's revenues, profitability and future rate of growth
will be substantially dependent upon prevailing prices for oil and
gas, which are in turn dependent upon numerous factors that are
beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of
energy. The energy markets have historically been volatile, and
there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future. A substantial or
extended decline in oil or gas prices could have a material
adverse effect on the Company's financial position, results of
operations and access to capital, as well as the quantities of oil
and gas reserves that the Company may economically produce.
Liquidity and Capital Resources
In October 1996, the Company sold 2,300,000 shares of the
Company's common stock in a public offering. The Company received
proceeds of approximately $13,189,000, net of offering costs of
$1,761,000. Until its October 1996 equity offering, the Company
had, since inception, been significantly constrained by a
continued shortage of capital. The October 1996 equity offering
remedied that problem, at least for the foreseeable future. For
the first time in the Company's history, the Company has funds
available to develop and exploit the Company's substantial
inventory of oil and gas properties. Management is of the view
that the Company's chronic liquidity problem can now be solved, on
a long term basis, by the Company's development of its oil and gas
properties. Management believes that such operations will
increase cash flow and improve liquidity, and thereby allow the
Company to avoid future working capital short-falls. The Company
had a working capital surplus of $5,365,000 at December 31, 1996
compared to a deficit of $476,000 at December 31, 1995. The
increase in working capital at December 31, 1996 is primarily due
to higher cash balances as a result of the equity offerings by the
Company and Laguna in 1996.
In March 1996, the Company established a $35,000,000 credit
facility (the "Facility") with Bank One, Texas, N.A. (the "Bank').
The Facility establishes two separate lines of credit: a primary
revolving line of credit (the "Revolver") and a line of credit to
be used for development drilling approved by the Bank (the
"Drilling Line'). The borrowing base under the Revolver is
subject to redetermination every six months, or at such other
times as the Bank may determine. The Company is obligated to
maintain certain financial and other covenants, including a
minimum current ratio, minimum net equity, a debt coverage ratio
and a total bank debt ceiling. The Facility is collateralized by
substantially all of the Company's oil and gas properties. The
Facility expires March 31, 1999. The initial borrowing base under
the Revolver was $10,500,000. Initial amounts drawn under the
Revolver were used to retire the amount outstanding under the
Company's prior line of credit of approximately $10,000,000 and
related accrued interest. At June 30, 1996, the borrowing base
was redetermined and reduced to $8,820,000. At that time, the
amount outstanding under the Revolver was $10,231,000, or
$1,411,000 in excess of the redetermined borrowing base. Per the
amended terms of the Facility, the Company drew $2,000,000 under
the Drilling Line and applied it to reduce amounts outstanding
under the Revolver to an amount below the redetermined borrowing
base. The $2,000,000 drawn under the Drilling Line and $5,301,000
under the Revolver were repaid in October 1996 upon the completion
of the public stock sale, discussed below. Once repaid, the
Company can no longer borrow against the Drilling Line. At
December 31, 1996, the borrowing base under the Revolver was
$8,820,000, and the principal amount outstanding was $3,269,000,
leaving the amount available under the Revolver at $5,551,000.
Effective January 1997, the Borrowing Base was increased to
$10,000,000. At March 25, 1997, the principal amount outstanding
was $3,269,000, leaving the amount remaining available under the
Revolver at $6,731,000. The Company is currently in compliance
with the covenants of the Facility. For additional information
concerning the Facility, see Note 4 to the Consolidated Financial
Statements.
Approximately $1,987,000 of the net proceeds from the Company's
October 1996 offering were used to purchase and retire all
outstanding shares of the Company's Series A Convertible Preferred
Stock.
In May 1996, Laguna sold 5,000,000 Special Warrants for $1.00 per
Warrant in a private placement for net proceeds of $4,339,000. In
September 1996, Laguna completed the registration of the sale of
the Special Warrants with the Ontario (Canada) Securities
Commission.
Mandatory redemption of the Company's Series B Mandatorily
Redeemable Convertible Preferred Stock (the "Series B Stock") was
to begin in April 1997, when 20% of the outstanding shares (i.e.,
80,000 shares) were to be redeemed for $800,000. The Company has
extended an offer to all holders of the Series B Stock to convert
their shares into shares of the Company's common stock at a
conversion price of $9.00, rather than the $11.31 conversion price
otherwise in effect. On March 25, 1997, a holder of 200,000
shares of Series B Stock accepted the offer to convert. When
completed, this conversion will satisfy the Company's obligation
to redeem any shares in April.
Historically, the Company's involvement in both oil and gas and
mining activities has hampered its ability to raise capital due to
the complexity of the Company's financial structure and apparent
market perceptions that the Company was too small to effectively
pursue two such disparate businesses. By establishing independent
financing arrangements for Laguna, management hopes to overcome
these problems, and place the Company in a position to exploit its
oil and gas acreage. The elimination of the Company's commitment
to fund Laguna's operations should assist the Company in these
efforts.
To implement its planned drilling and development programs, the
Company expended $2,462,000 in 1996 and plans to spend
approximately $10 million in 1997. With the net proceeds of the
equity offering, the Company's working capital and credit facility
and the operating cash flows that are expected to be generated by
the application of such funds to the Company's drilling program,
management anticipates that the Company will have sufficient
capital to fund the continued development of its current
properties and to meet the Company's liquidity requirements for
the foreseeable future.
Results of Operations
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995(1) 1994(1)
(In thousands, except per unit data)
<C> <S> <S> <S>
Results of Operations:
Revenues $ 6,520 $ 5,428 $ 4,909
Costs and expenses 8,463 7,104 6,540
Net loss (1,837) (1,929) (1,631)
Net loss attributable to common
shareholders (2,213) (2,289) (1,889)
Net loss per share attributable
to common shares (0.88) (1.16) (1.00)
EBITDA (2) 1,520 1,093 876
Capital expenditures 6,339 3,995 2,379
Operating Results from Oil and Gas Operations:
Oil and gas revenues $ 5,854 $ 4,800 $ 4,629
Oil and gas production expenses 2,249 1,868 2,024
Depletion 1,924 2,162 2,337
Net Production:
Oil (MBbl) 174 173 146
Natural gas (MMcf) 1,286 1,238 1,648
BOE 388 379 421
Average Sales Price Realized:
Oil (per Bbl) $ 18.05 $ 16.45 $ 14.81
Natural gas (per Mcf) $ 2.11 $ 1.58 $ 1.50
Per BOE $ 15.09 $ 12.66 $ 11.00
Average production costs and taxes
(per BOE): $ 5.80 $ 4.93 $ 4.81
Average depletion (per BOE): $ 4.96 $ 5.70 $ 5.53
</TABLE>
_________________
1) Includes 692 MMcf and 961 MMcf and 26 MBbls and 48 MBbls
delivered in 1995 and 1994, respectively, pursuant to the terms of
the volumetric production agreement which was retired in August
1995.
2) EBITDA is earnings before income taxes, interest expense,
depreciation, depletion and amortization, impairment, and
extraordinary loss. EBITDA is a financial measure commonly used
in the Company's industry and should not be considered in
isolation or as a substitute for net income, cash flow provided by
operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a
measure of a company's profitability or liquidity. The Company
believes that EBITDA may provide additional information about the
Company's ability to meet its future requirements for debt
service, capital expenditures and working capital. When
evaluating EBITDA, investors should consider, among other factors,
(i) increasing or decreasing treads in EBITDA, (ii) whether EBITDA
has remained at positive levels historically and (iii) how EBITDA
compares to levels of interest expense. Other companies may
define EBITDA differently, and as a result, such measures may not
be comparable to the Company's EBITDA.
Year Ended December 31, 1996 Compared with Year Ended December 31,
1995
Revenues. Total revenues for the year ended December 31, 1996
increased 20% to $6,520,000 from $5,428,000 for the year ended
December 31, 1995. Oil and gas sales for the year ended
December 31, 1996 increased 22% to $5,854,000 from $4,800,000
(including amortization of deferred revenues from a volumetric
production payment in the year ended December 31, 1995.) The
increase was primarily due to higher oil and gas prices. Average
oil prices for the year ended December 31, 1996 increased 10% to
$18.05 per Bbl from $16.45 per Bbl for the year ended December 31,
1995. Average gas prices for the year ended December 31, 1996
increased 34% to $2.11 per Mcf from $1.58 per Mcf for the year
ended December 31, 1995. The $329,000 gain on the sale of Laguna
common stock for the year ended December 31, 1996 compares to the
$355,000 gain on the termination of a volumetric production
payment for the year ended December 31, 1995. There were no sales
of gold or silver in 1996 or 1995, and no such sales are expected
in the immediate future.
Oil and Gas Production Expenses. Oil and gas production expenses
for the year ended December 31, 1996 increased 20% to $2,249,000
from $1,868,000 for the year ended December 31, 1995. The
increase was primarily attributable to increased operating costs
related to new wells drilled in 1996 and increased workover
expenses.
Mining Project Expenses. Mining project expenses for the year
ended December 31, 1996 increased 21% to $1,014,000 from $838,000
for the year ended December 31, 1995. The increase was primarily
due to Laguna's drilling program in new exploration areas and
business development expenses related to reviewing other mineral
concessions.
Depreciation, Depletion and Amortization. Depreciation, depletion
and amortization for the year ended December 31, 1996 decreased
11% to $2,095,000 from $2,340,000 for the year ended December 31,
1995. Depletion per BOE for the year ended December 31, 1996
decreased 13% to $4.96 from $5.70 for the year ended December 31,
1995, primarily due to an increase in oil and gas reserves.
General and Administrative Expenses. General and administrative
expenses for the year ended December 31, 1996 increased 23% to
$1,999,000 from $1,625,000 for the year ended December 31, 1995
due primarily to increased stock compensation costs.
Impairment of Oil and Gas Properties. Impairment of oil and gas
properties was $264,000 during the year ended December 31, 1996
compared to $-0- for the year ended December 31, 1995. In fiscal
1996, the Company acquired a 2.25% working interest in an
exploration venture to drill one or more wells offshore Belize.
As of December 31, 1996, the Company had incurred and capitalized
$264,000 related to this venture. The joint venture drilled a dry
hole subsequent to December 31, 1996. Accordingly, the Company
reduced the carrying amount of its capitalized costs by $264,000.
During fiscal 1995, the Company's oil and gas activities were
conducted entirely in the United States.
Interest and Other Expenses. Interest and other expenses for the
year ended December 31, 1996 increased 95% to $842,000 from
$433,000 for the year ended December 31, 1995. The increase was
primarily due to higher outstanding borrowings under the Company's
credit facility.
Minority Interest. Minority interest in loss of consolidated
subsidiary of $266,000 represents the minority interest share in
the Laguna loss.
Income Taxes. The Company incurred net operating losses ("NOLs")
for U.S. Federal income tax purposes in 1996 and 1995, which can
be carried forward to offset future taxable income. Statement of
Financial Accounting Standards No. 109 requires that a valuation
allowance be provided if it is more likely than not that some
portion or all of a deferred tax asset will not be realized. The
Company's ability to realize the benefit of its deferred tax asset
will depend on the generation of future taxable income through
profitable operations and the expansion of the Company's oil and
gas producing activities. The market and capital risks associated
with achieving the above requirement are considerable, resulting
in the Company's decision to provide a valuation allowance equal
to the net deferred tax asset. Accordingly, the Company did not
recognize any tax benefit in its consolidated statement of
operations for the years ended December 31, 1996 and 1995. At
December 31, 1996, the Company had an NOL carryforward for U.S.
Federal income tax purposes of approximately $16,100,000, which
will begin to expire in 2005.
Extraordinary Loss. The Company incurred extraordinary losses of
$160,000 and $253,000 during the years ended December 31, 1996 and
1995, respectively, as a result of the refinancing of its credit
facilities with new lenders.
Net Loss. Net loss for the year ended December 31, 1996 decreased
5% to $1,837,000 from $1,929,000 for the year ended December 31,
1995 as a result of the factors discussed above. The Company paid
the 8% dividend of $320,000 on its $4,000,000 face amount Series B
Mandatorily Redeemable Convertible Preferred Stock ("Series B
Preferred Stock") in each of the years ended December 31, 1996 and
1995, and realized accretion of $56,000 and $40,000, respectively.
Net loss attributable to common shareholders for the year ended
December 31, 1996 decreased 3% to $2,213,000 from $2,289,000 for
the year ended December 31, 1995.
Year Ended December 31, 1995 Compared with Year Ended December 31,
1994
Revenues. Total revenues for the year ended December 31, 1995
increased 11% to $5,428,000 from $4,909,000 for the year ended
December 31, 1994. The increase was primarily due to a gain of
$355,000 on termination of a volumetric production payment. For
the year ended December 31, 1995 oil and gas sales, including
amortization of deferred revenue from a volumetric production
payment, increased 4% to $4,800,000 from $4,629,000 for the year
ended December 31, 1994. Total oil production increased 19% to
173 MBbls and total gas production decreased 25% to 1,238 MMcf for
the year ended December 31, 1995. The increase in oil sales was
due to the completion of eight productive wells during 1995, and
the decrease in gas sales was due in part to a decrease in
production from one of the Company's producing properties, which
has a steep decline curve, accounting for 267 MMcf of the
production decrease. Average oil prices for the year ended
December 31, 1995 increased 11% to $16.45 per Bbl from $14.81 per
Bbl for the year ended December 31, 1994. Average gas prices for
the year ended December 31, 1995 increased 5% to $1.58 per Mcf
from $1.50 per Mcf for the year ended December 31, 1994. During
the years ended December 31, 1995 and 1994, there were no sales of
gold or silver.
Oil and Gas Production Expenses. Oil and gas production expenses
for the year ended December 31, 1995 decreased 8% to $1,868,000
from $2,024,000 for the year ended December 31, 1994. The
decrease was primarily due to a reduction in repair costs in some
of the Company's older fields.
Mining Project Expenses. Mining project expenses for the year
ended December 31, 1995 increased 83% to $838,000 from $459,000
for year ended December 31, 1994. The increase was due primarily
to increased general and administrative costs relating to expanded
operations.
General and Administrative Expenses. General and administrative
expenses for the year ended December 31, 1995 increased 7% to
$1,625,000 from $1,516,000 for the year ended December 31, 1994.
The increase was primarily due to an increase in investment
banking fees related to a contract which expired in 1995 and
additional salary expense for two officers hired April 1, 1994,
which was included for a full year in 1995. These increases were
partially offset by a reduction in legal fees and office expenses.
Depreciation, Depletion and Amortization. Depreciation, depletion
and amortization for the year ended December 31, 1995 decreased 3%
to $2,340,000 from $2,409,000 for the year ended December 31,
1994. Depletion per BOE for the year ended December 31, 1995
increased 3% to $5.70 from $5.53 for the year ended December 31,
1994, primarily due to lower gas production.
Interest and Other Expenses. Interest and other expenses for the
year ended December 31, 1995 increased 228% to $433,000 from
$132,000 for the year ended December 31, 1994. The increase was
primarily due to higher outstanding borrowings under the Company's
credit facility, which were used primarily to terminate a
volumetric production payment in August 1995.
Income Taxes. The Company incurred NOLs for U.S. Federal income
tax purposes in 1995 and 1994, which can be carried forward to
offset future taxable income. Statement of Financial Accounting
Standards No. 109 requires that a valuation allowance be provided
if it is more likely than not that some portion or all of a
deferred tax asset will not be realized. The Company's ability to
realize the benefit of its deferred tax asset will depend on the
generation of future taxable income through profitable operations
and the expansion of the Company's oil and gas producing
activities. The market and capital risks associated with
achieving the above requirement are considerable, resulting in the
Company's decision to provide a valuation allowance equal to the
deferred tax asset. Accordingly, the Company did not recognize
any tax benefit in its consolidated statement of operations for
the years ended December 31, 1995 and 1994. At December 31, 1995,
the Company had an NOL carryforward for U.S. Federal income tax
purposes of approximately $13,400,000, which will begin to expire
in 2005.
Extraordinary Loss. The Company incurred an extraordinary loss of
$253,000 during 1995 as a result of the refinancing of its credit
facility with a new lender.
Net Loss. Net loss for the year ended December 31, 1995 increased
18% to $1,929,000 from $1,631,000 for the year ended December 31,
1994 as a result of the factors discussed above. The Company paid
the 8% dividend totaling $320,000 and $228,000 on its Series B
Preferred Stock during 1995 and 1994, respectively, and realized
accretion of $40,000 and $30,000, respectively. Net loss
attributable to common shareholders for the year ended
December 31, 1995 increased 21.2% to $2,289,000 from $1,889,000
for the year ended December 31, 1994.
Hedging Activities
The Company uses hedging instruments to manage commodity price
risks. The Company has used energy swaps and other financial
arrangements to hedge against the effects of fluctuations in the
sales prices for oil and natural gas. Gains and losses on such
transactions are matched to product sales and charged or credited
to oil and gas sales when that product is sold. Management
believes that the use of various hedging arrangements can be a
prudent means of protecting the Company's financial interests from
the volatility of oil and gas prices.
At December 31, 1996, the Company had natural gas swaps in place
covering an aggregate of 90,000 MMBtu per month of 1997 production
at fixed prices ranging from $2.54 to $1.50 per MMBtu on an
"Inside FERC" basis, and oil swaps in place covering an aggregate
of 9,000 Bbls per month of 1997 production at fixed prices ranging
from $23.36 to $19.99 on a "NYMEX" basis. For the years ended
December 31, 1996, 1995 and 1994, the Company's gains (losses)
under its swap agreements were ($490,000), $34,000, and $43,000,
respectively. For further information about the Company's energy
swaps, see Note 12 to the Consolidated Financial Statements.
Miscellaneous
The Company's oil and gas operations are significantly affected by
certain provisions of the Internal Revenue Code of 1986, as
amended (the "Code"), that are applicable to the oil and gas
industry. Current law permits the Company to deduct currently,
rather than capitalize, intangible drilling and development costs
incurred or borne by it. The Company, as an independent producer,
is also entitled to a deduction for percentage depletion with
respect to the first 1,000 Bbls per day of domestic crude oil
(and/or equivalent units of domestic natural gas) produced (if
such percentage depletion exceeds cost depletion). Generally,
this deduction is 15% of gross income from an oil and gas
property, without reference to the taxpayer's basis in the
property. The percentage depletion deduction may not exceed 100%
of the taxable income from a given property. Further, percentage
depletion is limited in the aggregate to 65% of the Company's
taxable income. Any depletion disallowed under the 65%
limitation, however, may be carried over indefinitely.
Inflation has not historically had a material impact on the
Company's financial statements, and management does not believe
that the Company will be materially more or less sensitive to the
effects of inflation than other companies in the oil and gas
industry.
