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, 1996
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 25, 1997, the aggregate
market value of the shares of voting stock held by non-affiliates
of the registrant, based upon the sales price for a share of the
registrant's Common Stock as reported on the Nasdaq National
Market tier of the Nasdaq Stock Market, was approximately
$27,160,000.
As of March 25, 1997, 4,388,117 shares of the registrant's
Common Stock, par value $0.01 per share, 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 the 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
1997 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, 1996
Table of Contents
PART I Page
Items 1 and 2 Business and Properties 1
General History 1
Overview of Oil and Gas Operations 1
Selected Fields and Areas of Interest 2
Acreage 3
Proved Reserves 4
Drilling Activity 4
Productive Wells 5
Production and Sales 5
Laguna Gold Company 5
General Matters 6
Item 3 Legal Proceedings 10
Item 4 Submission of Matters to a Vote of Security Holders 10
PART II
Item 5 Market for the Registrant's Common Equity and
Related Stockholder Matters 11
Price Range of Common Stock 11
Holders 11
Dividend Policy 11
Item 6 Selected Financial Data 12
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Overview 13
Liquidity and Capital Resources 14
Results of Operations 15
Hedging Activities 18
Miscellaneous 18
Item 8 Financial Statements and Supplementary Data 18
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 19
PART III
Item 10 Directors and Executive Officers of the Registrant 19
Item 11 Executive Compensation 19
Item 12 Security Ownership of Certain Beneficial Owners
and Management 19
Item 13 Certain Relationships and Related Transactions 19
PART IV
Item 14 Exhibits, Financial Statements and Reports on
Form 8-K 19
SIGNATURES 21
EXHIBIT INDEX 22
GLOSSARY OF TERMS 23
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 Shareholders' Equity F-6
Consolidated Statements of Cash Flows F-8
Notes to Consolidated Financial Statements F-10
PART I
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
<S> <C> <C> <C> <C>
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)
<S> <C> <C> <C>
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
<S> <C> <C> <C> <C> <C> <C>
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 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.
Gross Wells Net Wells
___________ _________
Oil Natural Gas Total Oil Natural Gas Total
118 109 227 39.7 34.7 74.4
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
<S> <C> <C> <C>
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.
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
<S> <C> <C> <C>
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.
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 3: LEGAL PROCEEDINGS
None.
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
Price Range of Common Stock
The Common Stock is traded on the Nasdaq National Market tier of
the Nasdaq Stock Market under the symbol "MLRC." The following
table sets forth, for the periods indicated, the high and low
sale prices of the Common Stock as reported on the Nasdaq
National Market. All of the following quotations have been
adjusted to reflect the four-to-one reverse stock split of the
Common Stock that occurred on September 9, 1996.
<TABLE>
<CAPTION>
High Low
<S> <C> <C>
Year Ended December 31, 1995:
First Quarter $ 8.00 $ 5.00
Second Quarter 8.50 5.50
Third Quarter 10.00 6.00
Fourth Quarter 11.00 4.00
Year Ending December 31, 1996:
First Quarter $ 8.25 $ 5.50
Second Quarter 11.00 6.00
Third Quarter 8.50 5.00
Fourth Quarter 9.63 6.50
Year Ending December 31, 1997
First Quarter (through March 25) $10.50 $ 7.13
</TABLE>
Holders
As of March 25, 1997, there were approximately 660 shareholders
of record of the Common Stock.
Dividend Policy
The Company does not intend to pay cash dividends on the Common
Stock in the foreseeable future. The Company instead intends to
retain its earnings to support the growth of the Company. 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. Under the terms of
the Company's primary credit facility, the Company may not pay
dividends without the consent of the bank. For a description of
the credit facility, see Item 7.
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)
<S> <C> <C> <C> <C> <C>
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 & 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 shareholders
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
Selected Data Excluding Laguna (4):
Revenues $ 6,390 $ 5,387 $ 4,909 $ 2,210 1,652
Costs and Expenses 7,334 6,076 6,044 2,890 1,829
Net Loss (1,104) (942) (1,135) (680) (177)
Net loss attributable to common
shareholders (1,480) (1,302) (1,393) (680) (177)
Net loss per share attributable to
common shares (0.59) (0.67) (0.73) (0.50) (0.15)
EBITDA (2) 2,167 2,028 1,335 381 134
Capital expenditures 2,474 2,645 2,221 20,306 184
</TABLE>
<TABLE>
<CAPTION>
At December 31,
1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
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 income 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.
(3) Long-term debt includes long-term debt net of current
maturities, notes payable-other and capital lease obligations net
of current portion.
(4) As discussed elsewhere in this report, in early 1996, the
Company determined that the level of capital and management
resources required to fully develop both its oil and gas
interests and its mining interests made it inadvisable 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. Amounts presented exclude the impact of Laguna and
represent the Company's core oil and gas operations.
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)
Results of Operations, Consolidated:
<S> <C> <C> <C>
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
Results of Operations, Excluding Laguna (3):
Revenues $6,390 $5,387 $4,909
Costs and expenses 7,334 6,076 6,044
Net loss (1,104) (942) (1,135)
Net loss attributable to
common shareholders (1,480) (1,302) (1,393)
Net loss per share attributable
to common shares (0.59) (0.67) (0.73)
EBITDA (2) 2,167 2,028 1,335
Capital expenditures 2,474 2,757 2,221
</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 income 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.
(3) Reflects oil and gas operations.
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. Excluding
Laguna, total revenues for the year ended December 31, 1996
increased 19% to $6,390,000 from $5,387,000, primarily due to
higher oil and gas prices.
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.
Excluding Laguna, net loss attributable to common shareholders
for the year ended December 31, 1996 increased 12% to $1,480,000
from $1,302,000 due to higher general and administrative,
production and interest expenses, offset by higher oil and gas
sales.
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. Excluding Laguna, total revenues for the year
ended December 31, 1995 increased 10% to $5,387,000 from
$4,909,000 due to a gain on the termination of a volumetric
production payment.
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. Excluding
Laguna, net loss attributable to common shareholders for the year
ended December 31, 1995 decreased 7% to $1,302,000 from
$1,393,000 due to a gain on the termination of a volumetric
production payment.
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.
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
None.
PART III
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors
The information set forth under the caption "Election of
Directors" in the Company's Proxy Statement for its June 6, 1997
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.
Executive Officers
Information concerning executive officers is set forth in Item 1
of Part I of this report. Additional information concerning
executive officers set forth in the Company's Proxy Statement for
its June 6, 1997 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 11: EXECUTIVE COMPENSATION
The information set forth under the caption "Executive
Compensation" in the Company's Proxy Statement for its June 6,
1997 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 June 6,
1997 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 June 6, 1997 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
Exhibits
See the Exhibit Index that follows the signature page to this
report and is incorporated herein by this reference.
Financial Statements
See the accompanying "Index to Consolidated Financial Statements"
at page F-1, which lists the documents that are filed as a part
of this report. All other schedules for which provision is made
in the applicable accounting regulations of the Securities and
Exchange Commission are not required under the related
instructions, are inapplicable and therefore have been omitted or
the information required by the applicable schedule is included
in the notes to the financial statements.
Reports on Form 8-K
Since September 30, 1996, the Company has filed the following
Periodic Reports on Form 8-K:
Date of Report Item(s) Reported
October 17, 1996 "Other Events" - Public offering
commenced
October 23, 1996 "Other Events" - Purchase and retire-
ment of Series A Preferred Stock
October 30, 1996 "Other Events" - Over-allotment Option
exercised
November 14, 1996 "Other Events" - Third Quarter results
November 19, 1996 "Other Events" - Discovery well
January 15, 1997 "Other Events" - Acquisition of acreage
February 27, 1997 "Other Events" - December 31 reserves
March 18, 1997 "Other Events" - 1996 results
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: March 31, 1997 By: /s/ George O. Mallon, Jr.
George O. Mallon, Jr.
Principal Executive Officer
Date: March 31, 1997 By: /s/ Alfonso R. Lopez
Alfonso R. Lopez
Vice President-Finance
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: March 31, 1997 By: /s/ George O. Mallon, Jr.
George O. Mallon, Jr.
Director
Date: March 31, 1997 By: /s/ Kevin M. Fitzgerald
Kevin M. Fitzgerald
Director
Date: March 31, 1997 By: /s/ James A. McGowen
James A. McGowen
Director
Date: March 31, 1997 By: /s/ Roy K. Ross
Roy K. Ross
Director
EXHIBIT INDEX
Exhibit Number Document Description Location
*3.01 Amended and Restated Articles of
Incorporation of the Company (1)
*3.02 Bylaws of the Company (1)
*3.04 Statement of Designations--Series B
Preferred Stock (4)
Material Contracts
*10.58 Bank One--Loan Agreement dated
March 20, 1996 (5)
*10.63 Bank One--Amendment One (6)
*10.64 Bank One--Amendment Two (6)
Executive Compensation Plans and Arrangements
*10.1.3 Equity Participation Plan, amended
November 2, 1990 (2)
*10.1.4 Stock Compensation Plan for Outside
Directors (3)
____________________________
* The exhibit numbers are the exhibit numbers assigned in the
previous filings with the Securities and Exchange Commission
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 Resources Corporation
(Commission File No. 0-17267) Form 10-K for fiscal year ended
December 31, 1990.
(3) 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.
(4) Incorporated by reference from Mallon Resources Corporation
(Commission File No. 0-17267) Form 8-K filed on August 24, 1995.
(5) Incorporated by reference from Mallon Resources Corporation
(Commission File No. 0-17267) Form 8-K filed on March 20, 1996.
(6) Incorporated by reference from Mallon Resources Corporation
(Commission File No. 0-17267) Form 8-K filed on August 15, 1996.
GLOSSARY OF TERMS
Bbl. One stock tank barrel, or 42 U.S. gallons liquid
volume, used herein in reference to crude oil or other liquid
hydrocarbons.
Bcf. Billion cubic feet.
BOE. Barrels of oil equivalent, determined using the ratio
of six Mcf of natural gas (including natural gas liquids) to one
Bbl of crude oil or condensate.
Btu. British thermal unit, which is the heat required to
raise the temperature of a one-pound mass of water from 58.5 to
59.5 degrees Fahrenheit.
Development location. A location on which a development
well can be drilled.
Development well. A well drilled within the proved area of
an oil or gas reservoir to the depth of a stratigraphic horizon
known to be productive in an attempt to recover proved
undeveloped reserves.
Dry hole. A well found to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an
oil or gas well.
Estimated future net revenues. Revenues from production of
oil and gas, net of all production-related taxes, lease operating
expenses and capital costs.
Exploratory well. A well drilled to find and produce oil or
gas in an unproved area, to find a new reservoir in a field
previously found to be productive of oil or gas in another
reservoir, or to extend a known reservoir.
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
MBbl. One thousand barrels of crude oil or other liquid
hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet.
MMBbl. One million barrels of crude oil or other liquid
hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million Btus.
MMcf. One million cubic feet.
Net acres or net wells. The sum of the fractional working
interests owned in gross acres or gross wells.
Pre-tax SEC 10 Value or present value of estimated future
net revenues. Estimated future net revenues discounted by a
factor of 10% per annum, before income taxes and with no price or
cost escalation or de-escalation, in accordance with guidelines
promulgated by the Commission.
Production costs. All costs necessary for the production
and sale of oil and gas, including production and ad valorem
taxes.
Productive well. A well that is producing oil or gas or
that is capable of production.
Proved developed reserves. Reserves that can be expected to
be recovered through existing wells with existing equipment and
operating methods.
Proved reserves. The estimated quantities of crude oil,
natural gas and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped reserves. Reserves that are expected to
be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required
for recompletion.
Recompletion. The completion for production of an existing
wellbore in another formation from that in which the well has
previously been completed.
Undeveloped acreage. Lease acreage on which wells have not
been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas regardless of
whether such acreage contains proved reserves.
Working interest. The operating interest which gives the
owner the right to drill, produce and conduct operating
activities on the property and a share of production.
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 Shareholders' Equity F-6
Consolidated Statements of Cash Flows F-8
Notes to Consolidated Financial Statements F-10
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 operations, of
shareholders' equity and of cash flows present fairly, in all
material respects, the financial position of Mallon Resources
Corporation and its subsidiaries at December 31, 1996 and 1995,
and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1996, 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.
PRICE WATERHOUSE LLP
Denver, Colorado
March 18, 1997
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands)
<TABLE>
<CAPTION>
December 31,
1996 1995
ASSETS
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 2,771 $ 1,269
Short-term investments 2,786 --
Accounts receivable:
Oil and gas sales 1,879 1,065
Joint interest participants, net of allowance of $8 and $0,
respectively 827 376
Related parties 20 22
Other 45 --
Inventories 251 53
Other 104 143
Total current assets 8,683 2,928
Property and equipment:
Oil and gas properties, full cost method 46,175 43,751
Mining properties and equipment 10,114 6,248
Other equipment 559 508
56,848 50,507
Less accumulated depreciation, depletion and amortization (24,406) (22,085)
32,442 28,422
Notes receivable-related parties 17 63
Other, net 258 222
Total Assets $ 41,400 $ 31,635
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable $ 1,614 $ 2,309
Undistributed revenue 1,502 711
Drilling advances 100 271
Accrued taxes and expenses 77 90
Current portion of capital lease obligation 25 23
Total current liabilities 3,318 3,404
Long-term debt 3,269 10,000
Notes payable, other 230 --
Capital lease obligation, net of current portion 12 37
Drilling advances 368 315
Accrued expenses 41 --
Total non-current liabilities 3,920 10,352
Total liabilities 7,238 13,756
Commitments and contingencies -- --
Minority interest 8,358 2,275
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 3,900 3,844
Shareholders' equity:
Series A Convertible Preferred Stock, $0.01 par value, 1,467,890
shares authorized, 0 and 1,100,918 shares issued and
outstanding, respectively; liquidation preference $6,000,000 -- 5,730
Common Stock, $0.01 par value, 25,000,000 shares authorized;
4,384,562 and 1,950,226 shares issued and outstanding,
respectively 44 19
Additional paid-in capital 56,707 38,965
Accumulated deficit (34,847) (32,954)
Total shareholders' equity 21,904 11,760
Total Liabilities and Shareholders' Equity $ 41,400 $ 31,635
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
For the Years Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 5,854 $ 3,380 $ 2,263
Deferred revenue amortization -- 1,420 2,366
Operating service revenue 154 158 174
Gain on termination of volumetric production payment -- 355 --
Gain on sale of subsidiary stock 329 -- --
Interest and other 183 115 106
6,520 5,428 4,909
Costs and expenses:
Oil and gas production 2,249 1,868 2,024
Mining project expenses 1,014 838 459
Depreciation, depletion and amortization 2,095 2,340 2,409
Impairment of oil and gas properties 264 -- --
General and administrative 1,999 1,625 1,516
Interest and other 842 433 132
8,463 7,104 6,540
Minority interest in loss of consolidated subsidiary 266 -- --
Loss before extraordinary item (1,677) (1,676) (1,631)
Extraordinary loss on early retirement of debt (160) (253) --
Net loss (1,837) (1,929) (1,631)
Dividends on preferred stock and accretion (376) (360) (258)
Net loss attributable to common shareholders $(2,213) $(2,289) $(1,889)
Per share:
Loss attributable to common shareholders before
extraordinary item $ (0.82) $ (1.04) $(1.00)
Extraordinary loss (0.06) (0.12) --
Net loss attributable to common shareholders $ (0.88) $ (1.16) $(1.00)
Weighted average common shares outstanding 2,512 1,947 1,916
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In thousands, except share amounts)
<TABLE>
<CAPTION>
Series A Additional
Preferred Stock Common Stock Paid-In Accumulated
Shares Amount Shares Amount Capital Deficit Total
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993 1,100,918 $5,730 1,899,743 $19 $38,604 $(29,324) $15,029
Employee stock options
exercised -- -- 1,250 -- -- -- --
Stock issued to directors -- -- 769 -- 11 -- 11
Stock issued for property
and equipment -- -- 16,675 -- 300 -- 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)
Balance, December 31, 1994 1,100,918 5,730 1,918,437 19 38,785 (30,985) 13,549
Employee stock options
exercised -- -- 1,250 -- -- -- --
Stock issued to directors -- -- 1,539 -- 12 -- 12
Stock issued for property -- -- 14,000 -- 112 -- 112
Stock issued for loan fees -- -- 15,000 -- 112 -- 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)
Balance, December 31, 1995 1,100,918 5,730 1,950,226 19 38,965 (32,954) 11,760
Employee stock options
exercised -- -- 10,570 -- -- -- --
Stock issued to directors -- -- 2,016 -- 12 -- 12
Stock issued to consultants -- -- 121,750 2 792 -- 794
Employee stock options granted -- -- -- -- 306 -- 306
Issuance of common stock in
public offering -- -- 2,300,000 23 13,166 -- 13,189
Purchase of Series A preferred
stock (1,100,918) (5,730) -- -- 3,743 -- (1,987)
Other -- -- -- -- 43 -- 43
Dividends on preferred stock -- -- -- -- (320) -- (320)
Accretion of preferred stock -- -- -- -- -- (56) (56)
Net loss -- -- -- -- -- (1,837) (1,837)
Balance, December 31, 1996 -- $ -- 4,384,562 $44 $56,707 $(34,847) $21,904
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Years Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $ (1,837) $(1,929) $(1,631)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Amortization of deferred revenues -- (1,420) (2,366)
Depreciation, depletion and amortization 2,095 2,340 2,409
Impairment of oil and gas properties 264 -- --
Minority interest in loss of consolidated subsidiary (266) -- --
Gain on sale of subsidiary stock (329) -- --
Stock compensation expense 327 101 43
Termination of volumetric production payment -- (5,586) --
Gain on termination of volumetric production payment -- (355) --
Non-cash portion of extraordinary loss 160 90 --
Write-off of notes receivable-related parties 46 -- --
Other -- (8) --
Changes in operating assets and liabilities:
Increase in:
Accounts receivable (1,443) (328) (257)
Inventory and other current assets (176) (77) (100)
Increase (decrease) in:
Trade accounts payable and undistributed revenue 890 183 1,549
Accrued taxes and expenses 28 28 14
Drilling advances (118) 64 104
Net cash used in operating activities (359) (6,897) (235)
Cash flows from investing activities:
Increase in short-term investments (2,786) -- --
Additions to property and equipment (4,109) (3,820) (2,079)
Proceeds from sale of subsidiary stock 372 -- --
Increase in notes receivable-related parties -- (20) (2)
Net cash used in investing activities (6,523) (3,840) (2,081)
Cash flows from financing activities:
Proceeds from long-term debt 10,570 10,000 --
Payments of long-term debt (17,324) (3) (31)
Payments on net profits interest -- -- (2,075)
Issuance of preferred stock, net of issuance costs -- -- 3,774
Issuance of preferred stock in subsidiary, net of
issuance costs -- 2,275 --
Debt issue costs paid (83) (159) --
Issuance of warrants -- 125 --
Net proceeds from sale of common stock in public
offering 13,189 -- --
Purchase of Series A preferred stock (1,987) -- --
Net proceeds from sale of subsidiary special warrants 4,339 -- --
Payment of preferred dividends (320) (320) (228)
Net cash provided by financing activities 8,384 11,918 1,440
Net increase (decrease) in cash and cash equivalents 1,502 1,181 (876)
Cash and cash equivalents, beginning of year 1,269 88 964
Cash and cash equivalents, end of year $ 2,771 $ 1,269 $ 88
Supplemental cash flow information:
Cash paid for interest $ 837 $ 525 $ 175
Non-cash transactions:
Issuance of common stock in exchange for:
Property and equipment $ -- $ 112 $ 300
Loan origination fee $ -- $ 112 $ --
Consultants' accounts payable $ 794 $ -- $ --
Issuance of warrants for loan origination fee $ -- $ 50 $ --
Acquisition of equipment under capital lease $ -- $ 63 $ --
Acquisition of Red Rock Ventures, Inc. for subsidiary
common stock and notes payable $ 2,230 $ -- $ --
</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 and Nature of Operations:
Mallon Resources Corporation (the "Company") was
incorporated on July 18, 1988 under the laws of the State of
Colorado. The Company engages in oil and gas exploration and
production through its wholly-owned subsidiary, Mallon Oil
Company ("Mallon Oil"). The Company also has interests in gold
and silver exploration through its majority-owned subsidiary,
Laguna Gold Company ("Laguna"). 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. Mining operations, conducted through Laguna in Costa
Rica, are in the pre-production stage.
Reverse Stock Split:
On September 9, 1996, a four-to-one reverse stock split of
the Company's issued and outstanding shares of common stock was
effected. Common stock, paid-in capital and earnings per share
information have been restated to give retroactive effect to the
reverse stock split.
Principles of Consolidation:
The consolidated financial statements include the accounts
of Mallon Oil, Laguna, and all of their wholly owned
subsidiaries. All significant intercompany transactions and
accounts have been eliminated from the consolidated financial
statements.
Cash, Cash Equivalents and Short-term Investments:
Cash and cash equivalents include investments that are
readily convertible into cash and have an original maturity of
three months or less. All short-term investments are held to
maturity and are reported at cost. Short-term investments
include U.S. Treasury bills and notes with maturities greater
than ninety days, but not exceeding one year.
Fair Value of Financial Instruments:
The Company's on-balance sheet financial instruments consist
of cash, cash equivalents, short-term investments, 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, 1996 and
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 derivative instruments which are intended
to manage commodity price risk (see Note 12).
Inventories:
Inventories, which consist 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 two cost centers,
the continental United States and offshore Belize.
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, 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 using one barrel of
oil as an equivalent to six thousand cubic feet of natural gas.
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. At December 31, 1996
and 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, deferred costs will be amortized using the units-of-
production method. 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 is 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.
Other Property and Equipment:
Other property and equipment is recorded at cost and
depreciated over the estimated useful lives (three to seven
years) using the straight-line method. The cost of normal
maintenance and repairs is charged to expense as incurred.
Significant expenditures that 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
be 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 net cash flows is less than
the carrying amount of the asset. Impairment is recorded based
on an estimate of future discounted net 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:
As an operator of jointly owned oil and gas properties, the
Company sells oil and gas production to numerous oil and gas
purchasers and pays vendors for oil and gas services. The risk
of non-payment by the purchaser is considered minimal and the
Company does not obtain collateral for sales to them. Joint
interest receivables are subject to collection under the terms of
operating agreements which provide lien rights, and the Company
considers the risk of loss likewise to be minimal.
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.
Deferred Revenues:
Revenues received in advance of production are classified as
deferred revenue. The deferred revenue is amortized as
production and delivery occur.
Stock-Based Compensation:
As required, the Company adopted SFAS No. 123, "Accounting
for Stock-Based Compensation" in 1996. 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." The Company has made 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 (see Note 10).
Foreign Currency Translation:
Management has determined that the U.S. dollar is 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.
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 the hedged commodity is sold
(see Note 12).
Per Share Data:
Per share data is calculated using the weighted average
number of common shares outstanding during each period. Common
share equivalents are excluded from the calculation in loss years
because they are anti-dilutive.
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 long-lived 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 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.
Reclassifications:
Certain prior years' amounts in the consolidated financial
statements have been reclassified to conform to the presentation
used in 1996.
Note 2. OIL AND GAS PROPERTIES
During 1995, the Company's oil and gas activities were
conducted entirely in the United States. In 1996, Mallon Oil
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 capitalized costs of approximately
$264,000. Subsequent to December 31, 1996, the joint venture
drilled a dry hole. Accordingly, the Company reduced the
carrying amount of its capitalized costs by $264,000 at
December 31, 1996. This amount is reflected as impairment of oil
and gas properties in the Company's consolidated statements of
operations.
Note 3. LAGUNA GOLD COMPANY
Laguna's principal precious metals property is the Rio
Chiquito project located in Guanacaste Province, Costa Rica,
where it holds exploration and exploitation concessions. The
project was initially owned 90% by Laguna and 10% by Red Rock
Ventures, Inc. ("Red Rock"). As discussed below, Laguna
purchased Red Rock in 1996 and now owns 100% of the project.
At December 31, 1995, the Company owned all of the issued
and outstanding shares of Laguna's common stock. In June 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. After the Laguna Series A Stock
placement, the Company's share of Laguna was reduced from 100% to
80%.
In May 1996, Laguna sold 5,000,000 Special Warrants for
$1.00 per Warrant in a private placement for proceeds of
$4,339,000, net of offering costs of $661,000. As discussed
below, in September 1996, the Special Warrants were registered
with the Ontario (Canada) Securities Commission.
In June 1996, Laguna acquired Red Rock for 2,000,000 shares
of Laguna's common stock, valued at $1.00 per share, and
Convertible Secured Promissory Notes in the aggregate principal
amount of $230,000, for a total consideration of $2,230,000. The
notes bear interest at 5% per annum. Principal and accrued
interest are due December 31, 2000. The notes are convertible
into shares of Laguna's common stock, at the holder's option.
The initial conversion price, which is subject to anti-dilution
adjustments, is $1.10. The note is collateralized by a general
security agreement encumbering all of the assets of Laguna. Red
Rock's sole asset at the time of the merger was a 10% interest in
the Rio Chiquito gold project, in which Laguna held a 90%
interest and now holds 100%. After the issue of the 2,000,000
shares of Laguna's common stock to Red Rock, the Company's share
of Laguna was reduced from 80% to 72%. The acquisition was
accounted for as a purchase.
In September 1996, Laguna completed the registration of the
sale of the Special Warrants with the Ontario (Canada) Securities
Commission. The completion of this registration caused the
conversion of all of the 25,000 outstanding shares of the Laguna
Series A Stock into 3,600,000 shares of common stock. Also in
September 1996, the Company sold 400,000 of its shares of Laguna
common stock and realized a gain of $329,000. After the
conversion of the Special Warrants into Laguna common stock and
the sale by the Company of Laguna common stock, the Company owned
14,000,000 of Laguna's 25,000,000 shares of issued and
outstanding common stock, or 56%. Laguna's common stock is
listed on The Toronto Stock Exchange. Approximately 8,400,000 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.
Note 4. NOTES PAYABLE AND LONG-TERM DEBT
In February 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%. In
August 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 previous $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
early retirement of debt for the year ended December 31, 1995.
As a part of the fee for the $15,000,000 facility, the Company
issued warrants, valued at $2.00 each, to purchase 25,000 shares
of the Company's common stock at a price of $10 per share. At
December 31, 1995, the total amount outstanding under the
facility was $10,000,000.
In March 1996, the Company established a $35,000,000 credit
facility (the "Facility") with Bank One, Texas, N.A. (the
"Bank'). The significant terms of the Facility, as it has been
amended, are as follows:
- - 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, at June 30 and December 31, or
at such other times as the Bank may determine.
- - The interest rate on amounts drawn under the Revolver is, at
the Company's election, either the Bank's base rate plus 0.75%,
or LIBOR plus 2.5% (7.875% as of December 31, 1996). Amounts
outstanding under the Drilling Line bear interest at the greater
of 12.5% or the Bank's base rate plus 4%.
- - A monthly reduction in the commitment under the Revolver,
subject to borrowing base redeterminations, is required.
However, debt service payments equal to the amount of the monthly
reduction are not required unless the balance outstanding under
the Facility exceeds the reduced commitment amount.
- - Amounts drawn under the Drilling Line are repayable from 100%
of the net revenues generated by wells drilled with such funds.
If the borrowing base under the Revolver increases, such
additional amounts must be borrowed and used to reduce amounts
outstanding under the Drilling Line. Once repaid, amounts drawn
under the Drilling Line may not be reborrowed.
- - The Company paid the Bank a $50,000 fee in connection with the Facility
and must pay a fee of 0.375% per annum on the daily average of the unused
amount of the borrowing base. If the borrowing base is increased, the Company
will pay a fee of 0.50% per annum of the amount of such increase over the
previously established borrowing base. A commitment fee of 0.75% per annum
was payable on the unused portion of the Drilling Line.
- - 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, minimum net
equity, a debt coverage ratio and a total bank debt ceiling. The Company
is restricted with respect to additional debt, payment of cash dividends
on common stock, loans or advances to others, certain investments, sale
or discount of receivables, hedging transactions, sale of assets and
transactions with affiliates.
- - The Facility expires on March 31, 1999.
Initial amounts drawn under the Revolver were used to retire the
Company's prior line of credit and related accrued interest. The
remaining $160,000 balance of unamortized loan origination fees
on the prior line of credit was written off and is reflected as
extraordinary loss on early retirement of debt for the year ended
December 31, 1996. The initial borrowing base under the Revolver
was $10,500,000. At June 30, 1996, the borrowing base was
redetermined and reduced to $8,820,000. At the time of this
redetermination, the amount outstanding under the Revolver was
$10,231,000, or $1,411,000 in excess of the redetermined
borrowing base. Under the terms of the Facility, as amended, the
Company drew $2,000,000 under the Drilling Line and applied it to
reduce amounts outstanding under the Revolver to an amount less
than 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 Company's common stock
sale (see Note 9). The outstanding balance under the Facility
at December 31, 1996 is $3,269,000. Effective January 1997, the
Borrowing Base was increased to $10,000,000 and the reduction in
the commitment under the Revolver was established at $140,000 per
month, beginning July 31, 1997. The Company is not required to
make debt service payments equal to the amount of the monthly
reduction in the commitment unless the outstanding balance under
the Facility exceeds the reduced commitment amount. At December 31,
1996, the Company was in compliance with the covenants of the Facility.
Note 5. DRILLING ADVANCES
In 1988 the Company sold a portion of its working interest
in certain gas properties located in the East Blanco Field to a
group of investors. In conjunction with the sale, investors
prepaid to the Company their share of future drilling and
completion costs. The Company has not yet expended all of the
prepaid funds, which are included in drilling advances at
December 31, 1996 and 1995. The Company plans to recomplete four
existing wells and install a gas sweetening plant in 1997, which
will reduce the balance of prepaid funds. Most of the advances
have been included in non-current liabilities at December 31,
1996 and 1995.
Note 6. DEFERRED REVENUE
In connection with its September 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 $10,000,000. 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 and the Company paid
a settlement of $5,586,000 to Enron Reserve Acquisition Corp.
This settlement resulted in a $355,000 gain to the Company for
the year ended December 31, 1995.
Note 7. COMMITMENTS AND CONTINGENCIES
Operating Leases:
The Company leases office space, vehicles and software under
non-cancelable leases which expire in 2002. Rental expense is
recognized on a straight-line basis over the terms of the leases.
The total minimum rental commitments at December 31, 1996 are as
follows:
<TABLE>
(In thousands)
<S> <C>
1997 $130
1998 170
1999 141
2000 141
2001 141
Thereafter 23
$746
</TABLE>
Rent expense was $125,000, $83,000 and $74,000 for the years
ended December 31, 1996, 1995 and 1994, respectively.
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
contested certain deficiencies. In March 1997, the matter was
resolved in the operator's favor.
Note 8. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK
In April 1994, the Company completed the private 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 $11.31 per share.
Mandatory redemption of this stock begins on April 15, 1997, when
20% of the total outstanding shares is redeemable. An additional
20% per year will be redeemed on each April 15 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
$320,000, $320,000 and $228,000 were paid in 1996, 1995 and 1994,
respectively. Accretion of preferred stock issue costs was
$56,000, $40,000 and $30,000 in 1996, 1995 and 1994,
respectively.
Mandatory redemption of the Company's Series B Stock was to
begin in April 1997, when 20% of the outstanding shares, or
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.
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.
In October 1996, the Company purchased all of the 1,100,918
shares outstanding at December 31, 1995 of the Company's Series A
Convertible Preferred Stock from Bank of America National Savings
and Trust Association for a purchase price of approximately
$1,886,000. In connection with the purchase, the Company also
paid fees and expenses of $101,000. The difference between the
carrying value of the Series A Stock and the purchase price was
credited to additional paid-in capital.
Common Stock:
The Company has reserved approximately 353,670 shares of
common stock for issuance upon possible conversion of the Series
B Stock.
In October 1996, the Company sold 2,300,000 shares of its
common stock in a public offering at $6.50 per share. The
Company received proceeds of approximately $13,189,000, net of
offering costs of $1,761,000. The net proceeds will be used
primarily to finance the drilling and development of the
Company's New Mexico oil and gas properties and a portion was
used to retire all outstanding shares of its Series A Convertible
Preferred Stock (see above). In connection with the public
offering, the Company issued to the underwriters a warrant to
purchase an aggregate of 184,000 shares of the Company's common
stock at $7.80 per share at any time between October 16, 1997 and
October 16, 1999.
As discussed in Note 3, Laguna issued 25,000 shares of
Series A Stock in June 1995. Each share of Laguna Series A Stock
included detachable warrants to purchase shares of the Company's
common stock. At December 31, 1996, the Company had reserved
approximately 76,590 shares of common stock, at an adjusted
exercise price of $8.16 per share, for issuance upon possible
exercise of the warrants. The warrants expire in June 2000.
Note 10. STOCK COMPENSATION
At December 31, 1996, the Company had three stock-based
compensation plans, including one for Laguna. As permitted under
SFAS No. 123, the Company has elected to continue to measure
compensation costs using the intrinsic value method of accounting
prescribed by APB Opinion No. 25, "Accounting for Stock Issued to
Employees". Under that method, the difference between the
exercise price and the estimated market value of the shares at
the date of grant is charged to compensation expense, ratably
over the vesting period, with a corresponding increase in
shareholders' equity. Compensation costs charged against income
for all plans were $327,000, $101,000 and $43,000 for 1996, 1995
and 1994, respectively.
Under the Mallon Resources Corporation 1988 Equity
Participation Plan (the "Equity Plan"), 250,000 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. The options vest over a period of up to four years
and expire over a maximum of ten years from the date of grant.
Under the Laguna Gold Company Equity Participation Plan (the
"Laguna Equity Plan"), shares of Laguna common stock have been
reserved for issuance in order to provide for incentive
compensation and awards to employees and consultants. The number
of shares reserved is the lesser of 10% of the number of shares
of Laguna common stock outstanding from time to time, or
8,000,000 shares. The Laguna 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. The options vest over a period of up to
four years, and expire over a maximum of ten years from the date
of grant. 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 by a
majority of the members of the Board. To date, no options have
been exercised.
The following table summarizes activity with respect to the
outstanding stock options under the Equity Plan and the Laguna
Equity Plan:
<TABLE>
<CAPTION>
Company Laguna
_________________ __________________
Weighted Weighted
Average Average
Exercise Exercise
Shares Price Shares Price
<S> <C> <C> <C> <C>
Outstanding at December 31, 1993 45,155 $0.04 -- $ --
Granted 17,250 0.04 -- --
Exercised (1,250) 0.04 -- --
Forfeited (60) 0.04 -- --
Outstanding at December 31, 1994 61,095 0.04 -- --
Granted -- -- 1,620,000 0.01
Exercised (1,250) -- -- --
Forfeited -- -- -- --
Outstanding at December 31, 1995 59,845 0.04 1,620,000 0.01
Granted 21,944 0.04 880,000 1.00
Exercised (10,570) 0.04 -- --
Forfeited (1,643) -- -- --
Outstanding at December 31, 1996 69,576 $0.04 2,500,000 $0.36
Options exerciseable:
December 31, 1994 29,095 $0.04 -- $ --
December 31, 1995 30,595 $0.04 1,035,000 $0.01
December 31, 1996 45,326 $0.04 1,845,000 $0.35
</TABLE>
The weighted average remaining contractual life of the
options outstanding under the Equity Plan and the Laguna Equity
Plan at December 31, 1996 is approximately 7 years and 8.5 years,
respectively.
Included in the amounts above are 19,500 options exercisable
at $.04 per share and expiring in 10 years, granted under the
Equity Plan in June 1990, that do not vest until the market price
of the Company's common stock exceeds certain prices ranging from
$32.00 to $48.00, for more than 120 consecutive days. When the
stock reaches the required price levels for vesting, the
Company will accrue 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, 1996, 1995 and 1994.
In 1992, the Company granted to a consultant options to
purchase 12,500 of the Company's common shares at $26 per share,
exercisable from November 1993 through October 1997. In 1994,
the Company granted this individual an additional 6,250 options
to purchase the Company's shares at $16 per share, exercisable
from January 1995 to December 1998. All of the 18,750 options
granted are outstanding at December 31, 1996. These options are
not part of the Equity Plan.
The Stock Compensation Plan for Outside Directors provides
that the Company's outside directors 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, $12,000 and $11,000 for the years 1996,
1995 and 1994, respectively, in relation to the Stock
Compensation Plan.
Had compensation expense for the Company's 1996 and 1995
grants of stock-based compensation been determined consistent
with the fair value based method under SFAS No. 123, the
Company's net loss, net loss attributable to common shareholders,
and the net loss per share attributable to common shareholders
would approximate the pro forma amounts below:
<TABLE>
<CAPTION>
1996 1995
As As
Reported Pro Forma Reported Pro Forma
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
Net loss $(1,837) $(1,869) $(1,929) $(1,840)
Net loss attributable to
common shareholders (2,213) (2,245) (2,289) (2,200)
Net loss per share
attributable to
common shareholders (0.88) (0.89) (1.16) (1.13)
</TABLE>
The fair value of each option is estimated as of the grant
date, using the Black-Scholes option-pricing model, with the
following assumptions:
<TABLE>
<CAPTION>
1996 1995
Company Laguna Company Laguna
<S> <C> <C> <C> <C>
Risk-free interest rate 5.8% 6.5% N/A 7.6%
Expected life (in years) 4 4 N/A 4
Expected volatility 61.0% 76.0% N/A 0.0%
Expected dividends 0.0% 0.0% N/A 0.0%
Weighted average fair value
of options granted $1.66 $0.52 N/A $0.11
</TABLE>
Note 11. 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"). The Company and its affiliates
match contributions to the 401(k) Plan in an amount up to 25% of
each employee's 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, at the sole
discretion of the Compensation Committee, are adequate to justify
a corporate contribution. For the years ended December 31, 1996,
1995 and 1994, the Company made matching contributions of
$16,000, $13,000 and $8,000, respectively. No discretionary
contributions were made during any of the three years ended
December 31, 1996.
The Company maintains a program which provides bonus
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, 1996, 1995 and 1994,
a total of $74,000, $69,000 and $59,000, respectively, was
distributed to employees.
Note 12. HEDGING ACTIVITIES
The Company is exposed to off-balance-sheet risks associated
with energy swap agreements at December 31, 1996 arising from
movements in the prices of oil and natural gas and from the
unlikely event of non-performance by the counterparty to the swap
agreements.
In order to hedge against the effects of declines in oil and
natural gas prices, the Company enters into energy swap
agreements with third parties and accounts for the agreements as
hedges based on analogy to the criteria set forth in SFAS No. 80,
"Accounting for Futures Contracts". In a typical swap agreement,
the Company receives the difference between a fixed price per
unit of production and a price based on an agreed-upon third
party index if the index price is lower. If the index price is
higher, the Company pays the difference. The Company's current
swaps are settled on a monthly basis.
The following table indicates the Company's outstanding
energy swaps at December 31, 1996:
Market Price
Product Production Fixed Price Duration Reference
Oil 9,000 Bbls/month $23.36-$19.99 1/97-12/97 NYMEX WTI
Gas 60,000 MMBtu/month $ 2.54-$ 1.62 1/97-12/97 El Paso
Natural Gas
(Permian)
Gas 30,000 MMBtu/month $ 2.42-$ 1.50 1/97-12/97 El Paso
Natural Gas
(San Juan)
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, and are included
in oil and gas sales in the Company's consolidated statements of
operations. At December 31, 1996, the estimated net amount the
Company would have had to pay to terminate the agreements was
approximately $299,000.
Note 13. MAJOR CUSTOMERS
Sales to customers in excess of 10% of total revenues for
the years ended December 31, 1996, 1995 and 1994 were:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Customer A $ -- $2,213 $2,579
Customer B -- -- 298
Customer C -- 1,319 573
Customer D 1,750 -- --
Customer E 1,513 -- --
</TABLE>
Note 14. INCOME TAXES
The Company incurred a loss for book and tax purposes in all
periods presented. There is no income tax benefit or expense for
the years ended December 31, 1996, 1995 or 1994.
Deferred tax assets (liabilities) are comprised of the following
as of December 31, 1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
(In thousands)
<S> <C> <C>
Deferred Tax Assets (Liabilities):
Net operating loss carryforward $ 6,019 $ 4,996
Other 308 170
Total deferred tax assets 6,327 5,166
Mining properties basis differences (1,686) (1,784)
Oil, gas and other properties basis
differences (1,285) (1,600)
Total deferred tax liabilities (2,971) (3,384)
Net deferred tax assets 3,356 1,782
Less valuation allowance (3,356) (1,782)
Net deferred tax assets (liabilities) $ -- $ --
</TABLE>
At December 31, 1996, for U.S. Federal income tax purposes,
the Company had a net operating loss ("NOL") carryforward of
approximately $16,100,000, which expires in varying amounts
between 2005 and 2011. 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 Laguna's
future taxable income.
Note 15. SEGMENT INFORMATION
The Company operates in two business segments: oil and gas
exploration and production primarily in the United States, and
gold and silver mining primarily in Costa Rica. Information
regarding total assets by business segment and geographic
location for the Company as of December 31, 1996, 1995, and 1994
is as follows:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Total assets:
Oil and gas $29,044 $24,791 $23,746
Mining 12,356 6,844 4,480
$41,400 $31,635 $28,226
United States $31,824 $25,867 $23,777
Costa Rica and other 9,576 5,768 4,449
$41,400 $31,635 $28,226
</TABLE>
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, 1996, 1995, and 1995:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Revenues:
Oil and gas $ 6,390 $ 5,428 $ 4,909
Mining 130 -- --
$ 6,520 $ 5,428 $ 4,909
Operating loss:
Oil and gas $ (304) $(1,176) $(1,427)
Mining (1,130) (500) (204)
$(1,434) $(1,676) $(1,631)
Depreciation, depletion and amortization:
Oil and gas $ 2,016 $ 2,288 $ 2,373
Mining 79 52 36
$ 2,095 $ 2,340 $ 2,409
Capital expenditures:
Oil and gas $ 2,473 $ 2,736 $ 2,242
Mining 3,866 1,259 137
$ 6,339 $ 3,995 $ 2,379
</TABLE>
The following tables summarize the Company's revenues and
net loss by geographic area for the years ended December 31,
1996, 1995 and 1994:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Revenues:
United States $ 6,520 $ 5,428 $ 4,909
Costa Rica and other -- -- --
$ 6,520 $ 5,428 $ 4,909
Net loss:
United States $ (702) $(1,800) $(1,427)
Costa Rica and other (1,135) (129) (204)
$(1,837) $(1,929) $(1,631)
</TABLE>
Note 16. RELATED PARTY TRANSACTIONS
The accounts receivable from related parties consists
primarily of joint interest billings to directors, officers,
shareholders, employees and affiliated entities for drilling and
operating costs incurred on oil and gas properties in which these
related parties participate with Mallon Oil and Mallon Oil
partnerships as working interest owners. These amounts will
generally be settled in the ordinary course of business, without
interest.
Notes receivable of $63,000 at December 31, 1995 consist of
loans to employees, which bear interest at prime plus 2%. Notes
receivable and accrued interest of $46,000 were written off in
1996.
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, less than 3%
of the Company's outstanding common stock at December 31, 1996,
but in excess of 5% of such stock at December 31, 1995. As of
December 31, 1996 and 1995, the Company had a payable to the
related company of $35,000 and $25,000, respectively, which is
included in other long-term accrued expenses and accounts payable
at December 31, 1996 and 1995, respectively. In addition, at
December 31, 1996, the Company has a receivable of $135,000 from
this company, which is recorded in other long-term assets in the
consolidated balance sheet.
Red Rock was owned, in part, by an estate that owned,
beneficially, less than 5% of the Company's outstanding common
stock at December 31, 1996 but in excess of 5% of such stock at
December 31, 1995. The Company had payables to the shareholder
of $-0- and $100,000 as of December 31, 1996 and 1995,
respectively, which are included in accounts payable in the
consolidated balance sheet. See Note 3 regarding the acquisition
of Red Rock by Laguna.
During the years ended December 31, 1996 and 1995, the
Company paid legal fees of $2,000 and $31,000, respectively, to a
law firm of which a director of the Company is a senior partner.
Additionally, in 1994, consulting fees valued at $300,000 were
paid to a member of the same firm in the form of 16,675 shares of
the Company's common stock. In January 1995, an additional
14,000 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.
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.
The Company had a consulting agreement with an investment
banking firm in which a director is a partner for investment
banking services of $240,000 in 1995, of which $90,000 was
payable at December 31, 1995 and paid in 1996. In addition, in
1996, the Company paid the firm a commission and other expenses of
$101,000 in connection with the Company's purchase of its Series A
Preferred Stock.
Note 17. SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS
Certain historical costs and operating information relating
to the Company's oil and gas producing activities for the years
ended December 31, 1996, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Capitalized Costs Relating to Oil and Gas Activities:
Oil and gas properties $ 46,175 $ 43,751 $ 41,127
Accumulated depreciation, depletion
and amortization (23,361) (21,173) (19,011)
22,814 22,578 22,116
Deferred revenues attributable to the
volumetric production payment -- -- (7,452)
$22,814 $ 22,578 $ 14,664
Costs Incurred in Oil and Gas Producing Activities:
Property acquisition costs $ 60 $ 131 $ 648
Termination of volumetric
production payment -- 5,586 --
Exploration costs 264(1) 180 --
Development costs 2,138 2,379 1,736
Full cost pool credits (38) (66) (142)
$ 2,424 $ 8,210 $ 2,242
Results of Operations from Oil and Gas Producing Activities:
Oil and gas sales $ 5,854 $ 3,380 $ 2,263
Deferred revenue amortization -- 1,420 2,366
Lease operating expense (2,249) (1,868) (2,024)
Depletion (1,924) (2,162) (2,330)
Impairment of oil and gas
properties (264)(1) -- --
Results of operations from oil and
gas producing activities $ 1,417 $ 770 $ 275
</TABLE>
Estimated Quantities of Proved Oil and Gas Reserves (unaudited):
Set forth below is a summary of the changes in the net
quantities of the Company's proved crude oil and natural gas
reserves estimated by an independent consulting petroleum
engineering firm for the years ended December 31, 1996, 1995 and
1994. All of the Company's reserves are located in the
continental United States.
<TABLE>
<CAPTION>
Oil Gas
(MBbls) (MMcf)
<S> <C> <C>
Proved Reserves
Reserves, December 31, 1993 859 22,336
Extensions, discoveries and additions 664 448
Production (98) (687)
Revisions 119 (5,803)
Reserves, December 31, 1994 1,544 16,294
Acquisition of reserves in place 136 2,246
Extensions, discoveries and additions 163 1,129
Production (147) (546)
Revisions 117 798
Reserves, December 31, 1995 1,813 19,921
Extensions, discoveries and additions 75 667
Production (174) (1,286)
Revisions (7) 4,983
Reserves, December 31, 1996 1,707 24,285
Pro forma reserves at December 31, 1996 (2) 1,707 28,388
Proved Developed Reserves
December 31, 1994 811 11,733
December 31, 1995 1,238 14,702
December 31, 1996 1,225 18,403
Pro forma at December 31, 1996 (2) 1,225 20,521
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
(unaudited):
The following summary sets forth the Company's unaudited
future net cash flows relating to proved oil and gas reserves,
based on the standardized measure prescribed in Statement of
Financial Accounting Standards No. 69, for the years ended
December 31, 1996, 1995 and 1994:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Future cash in-flows $129,963 $ 66,178 $ 50,964
Future production and development
costs (46,374) (30,522) (28,435)
Future income taxes 18,150) -- --
Future net cash flows 65,439 35,656 22,529
Discount at 10% (29,428) (14,618) (8,771)
Standardized measure of discounted future
net cash flows, end of year $ 36,011 $ 21,038 $13,758
Pro forma standardized measure of
discounted future net cash
flows, end of year (2) $ 38,320
</TABLE>
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 Company's oil and gas hedging
agreements at December 31, 1996, described in Note 12, do not
have a material effect on the determination of future oil and gas
sales. In 1995 and 1994, the tax basis of the oil and gas
properties plus the NOL carryforward exceeded future net
revenues. Consequently, no income taxes were provided for in
those years.
The following are the principal sources of changes in the
standardized measure of discounted future net cash flows for the
years ended December 31, 1996, 1995 and 1994:
<TABLE>
<CAPTION>
1996 1995 1994
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of
year $21,038 $13,758 $18,188
Net revisions to previous
quantity estimates and other 3,266 (1,852) (4,523)
Extensions, discoveries, additions,
and changes in timing of production,
net of related costs 2,204 1,631 3,959
Purchase of reserves in place -- 5,701 --
Net change in future development
costs 580 (127) (1,065)
Sales of oil and gas produced, net
of production costs (3,605) (1,512) (239)
Net change in prices and
production costs 20,487 2,063 (5,341)
Accretion of discount 2,029 1,376 1,819
Net change in income taxes (9,988) -- 960
Standardized measure, end of
year $ 36,011 $21,038 $13,758
Pro forma standardized measure,
end of year (2) $ 38,320
</TABLE>
(1) Offshore Belize - all other items relate to U.S.
operations.
(2) In December 1996, the Company entered into a purchase and
sale agreement to acquire certain oil and gas properties for cash
consideration of $1,300,000 (see Note 18). The Company assumed
operations of those properties on December 31, 1996 and the
ownership changed on January 1, 1997. Pro forma proved reserves
include 4,103 Mmcf and pro forma proved developed reserves
include 2,118 Mmcf, and pro forma standardized measure includes
$2,309,000 as if the ownership had changed on December 31, 1996.
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 18. SUBSEQUENT EVENT
In January 1997, the Company acquired certain oil and gas
properties for a total consideration of $1,300,000 and conveyance
of its interest in certain other oil and gas properties. The
cash consideration will be paid as follows: $500,000 at closing
in January 1997 and $400,000 each at January 1, 1998 and
January 1, 1999.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 2,771
<SECURITIES> 2,786
<RECEIVABLES> 2,779
<ALLOWANCES> 8
<INVENTORY> 251
<CURRENT-ASSETS> 8,683
<PP&E> 56,848
<DEPRECIATION> 24,406
<TOTAL-ASSETS> 41,400
<CURRENT-LIABILITIES> 3,318
<BONDS> 0
<COMMON> 44
3,900
0
<OTHER-SE> 21,860
<TOTAL-LIABILITY-AND-EQUITY> 41,400
<SALES> 5,854
<TOTAL-REVENUES> 6,520
<CGS> 0
<TOTAL-COSTS> 5,622
<OTHER-EXPENSES> 2,003
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 838
<INCOME-PRETAX> (1,677)
<INCOME-TAX> 0
<INCOME-CONTINUING> (1,677)
<DISCONTINUED> 0
<EXTRAORDINARY> (160)
<CHANGES> 0
<NET-INCOME> (2,213)
<EPS-PRIMARY> (.88)
<EPS-DILUTED> (.88)
</TABLE>
