Item 3 Legal Proceedings 10 Item 4
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5:
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.
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:
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.
______
(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:
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 _____________________ (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:
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:
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10:
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:
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:
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:
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:
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, 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 Consolidated Balance Sheets Consolidated Statements of Operations Consolidated Statements of Shareholders' Equity Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements
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)
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)
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)
The accompanying notes are an integral part of these consolidated financial statements.
MALLON RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
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:
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:
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:
The fair value of each option is estimated as of the grant date, using the Black-Scholes option-pricing model, with the following assumptions:
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:
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:
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:
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:
The following tables summarize the Company's revenues and net loss by geographic area for the years ended December 31, 1996, 1995 and 1994:
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:
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.
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:
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:
(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.