Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
THE COMPANY
The Company was formed in 1980 by a group of executive, professional and technical personnel who had previously been employees of Reserve Oil and Gas Company. In 1981, the Company raised approximately $7.4 million in its initial public stock offering. These proceeds were used to acquire leasehold acreage and engage in exploration for, and development, production and marketing of, oil and gas and other hydrocarbons. From 1985 through 1990, much of the Company's progress was aided by its institutional partner associations with John Hancock Mutual Life Insurance Company ("Hancock") and Midwest Capital Group, Inc., a wholly owned diversified business subsidiary of an Iowa-based public utility holding company ("Midwest"). Hancock and Midwest both participated through limited partnerships with the Company in its drilling activities, as well as equity investments. The Company raised $9.24 million in its secondary public offering in March 1993 (the "Offering"). Proceeds of the Offering were used to repay a portion of bank borrowings to permit greater utilization of the Company's cash flow and revolving credit facility to finance drilling and exploitation activities and potential acquisitions. During its fifteen-year history, the Company has consistently increased its reserve base through a strategic combination of cost effective acquisitions, timely exploitation of those acquisitions, and low-risk development drilling. References to the "Company" and the description of the Company's business herein includes the business of Alexander Energy Corporation and its subsidiaries unless the context otherwise indicates.
The Company's business activities include property acquisition and exploitation; geological and geophysical evaluation of prospective acreage; selection, negotiation and purchase of oil and gas prospects; participation in drilling exploratory and development wells; and operation of producing oil and gas prospects. The Company diversifies its exploration efforts between oil and gas with particular emphasis in the Mid-Continent region of the United States.
The Company's net proved reserves estimated as of December 31, 1994 consisted of approximately 145 billion cubic feet ("Bcf") of gas and 3.9 million barrels ("MMBbls") of oil with an aggregate present value of estimated future net revenues of approximately $108 million based on average prices of $1.62 per thousand cubic feet ("Mcf") and $16.25 per barrel ("Bbl"). Net daily production averaged 22,057 Mcf and 614 Bbls, or a total of 25,741 equivalent thousand cubic feet ("Mcfe") in 1994, up 17% from 1993. The Company's strategy is to increase reserves and enhance production and cash flow by (i) acquisition of properties, (ii) exploitation of acquired properties to increase reserves and production, (iii) controlling and obtaining reimbursement for general and administrative expenses and (iv) exploration and development. Each year since inception in 1980, the Company has added at least the amount of reserves it produced. For 1994, the Company's reserve addition cost through drilling and development activities, including estimated future development costs, was $.64 per Mcfe.
POOLING OF INTERESTS
On July 19, 1994, the Company acquired through merger American Natural Energy Corporation ("ANEC"), an Oklahoma corporation, formerly headquartered in Tulsa, Oklahoma. The merger is being accounted for under the pooling of interests method of accounting. See 1994 ACQUISITION ACTIVITIES --- Acquisition of American Natural Energy Corporation. Accordingly, the merger has been given retroactive effect on all information reported herein, including the Company's financial statements. The combined financial statements, reserves and information concerning the operations of the two separate entities for periods prior to the merger have been pooled and restated, with adjustments conforming ANEC's accounting policies to those used by the Company.
PUBLIC OFFERING OF ANEC SHARES
On September 28, 1993, ANEC sold 1.l million shares of its common stock in a public offering at $4.75 per share and received $4 million after underwriters commission and costs of the offering. Net proceeds of the offering were used to repay indebtedness (i) in the principal amount of $2.6 million by retiring ANEC's convertible subordinated notes and (ii) by applying $400,000 to retire ANEC's Series B preferred stock. The remaining amount of the proceeds were used for working capital and general corporate purposes.
ACQUISITIONS
Since 1984, the Company has continually evaluated potential acquisitions of producing and nonproducing properties, with an emphasis on producing properties. Potential acquisitions are evaluated to analyze existing reserve estimates, whether the Company believes it can reduce expenses associated with the properties and whether there are
new drilling and enhancement prospects associated with the properties. In the past ten years the Company has made acquisitions directly or indirectly through limited partnership formed with institutional partners. The following table summarizes certain estimated proved reserve data with respect to material acquisitions:
SUMMARY OF RESERVE ENHANCEMENT ON ACQUISITIONS PROVED RESERVES MMCFE (1)
(1) Million cubic feet of gas equivalents acquired by the Company or affiliated entity using a conversion factor of 6 Mcf of gas per Bbl of oil.
(2) Proved reserves based on reserve reports existing at the time of acquisition. The estimates of proved reserves identified at time of acquisition for Brooks Hall Energy Corporation ("BHEC") and Bradmar Petroleum Corporation ("Bradmar") were prepared by independent petroleum engineers. The remaining estimates of proved reserves identified at time of acquisition were prepared by the Company's engineers.
(3) Estimated quantities of proved reserves as of a particular date are affected by, among other things, further drilling and development, prevailing oil and gas prices and future development expenditures. Proved producing reserves are based on reserve reports by independent petroleum engineers and proved undeveloped reserves based on reports prepared by Company engineers.
(4) Based upon the Company's reserve reports as of December 31, 1994. See Note 15 of Notes to Consolidated Financial Statements.
(5) Includes reserve losses due to the impact of low 1994 year-end prices on well economic limits.
(6) Determined by adding reserves produced or sold to remaining reserves at December 31, 1994, less reserves identified at acquisition.
(7) Excludes the value of approximately 405,000 shares reserved for underwriters warrants and stock options held by former ANEC employees and directors at December 31, 1994.
(8) Data is stated as of January 1, 1994 to reflect pooling of interest.
(9) Reflects the limited partner's interest rather than the Company's net interest.
(10) MFS Properties were sold effective September 1, 1994 to Hugoton Energy Corporation for $3.5 million. Reserves are as of that date.
(11) Consists of the $17.7 million cost of oil and gas properties acquired together with other assets, exclusive of liabilities assumed. See Note 2 of Notes to Consolidated Financial Statements of the Company.
The Company primarily attributes the increase in estimated proved reserves for the acquisitions reflected in the table above to the Company's evaluation and analysis of potential acquisitions and its exploitation program. The exploitation program includes identifying development prospects, drilling increased density locations, performing
workovers, initiating water floods, performing "catch-up" maintenance on acquired properties that had not been fully maintained, adding production equipment and renegotiating gas contracts.
When evaluating possible acquisitions, the Company's geologists and engineers analyze various means by which production may be increased or related operating expenses may be decreased. In addition, the Company's personnel will attempt to identify the existence of any previously unreported proved undeveloped reserves. For example, Bradmar did not report proved undeveloped reserves with respect to its properties primarily because of its lack of sufficient capital to identify and develop these reserves; accordingly, proved undeveloped reserves were not included in the estimated proved reserves identified at the time of execution of the Bradmar acquisition agreement. However, the Company's familiarity with the areas in which Bradmar operated allowed the Company to assume in its acquisition analysis that an unspecified quantity of proved undeveloped reserves existed. Of the estimated 31.0 billion cubic feet of natural gas equivalents ("Bcfe") of proved reserves remaining on December 31, 1994 reflected in the table for Bradmar, approximately 7.2 Bcfe are classified as proved undeveloped reserves.
1994 ACQUISITION ACTIVITIES
Acquisition of American Natural Energy Corporation. At special meetings held on July 19, 1994, the stockholders of the Company and ANEC approved the acquisition by the Company of all the common shares of ANEC in a transaction that has been accounted for as a pooling of interests. Pursuant to an Agreement and Plan of Merger dated as of April 21, 1994, and as amended on June 10, 1994 (the "Merger Agreement"), the Company acquired ANEC in a merger. ANEC became a wholly owned subsidiary of the Company and each issued and outstanding share of ANEC's common stock was converted into the right to receive 1.62 shares of the Company's common stock ("Common Stock"). In addition, the Company agreed to assume all outstanding options granted under the stock option plans maintained by ANEC. As a result of the transaction, the Company issued approximately 5.8 million shares of Common Stock and reserved approximately 250,000 shares of Common Stock for issuance upon exercise of ANEC's options. The Company also reserved approximately 158,000 shares of its Common Stock for issuance pursuant to a warrant held by the underwriters of ANEC's public stock offering held in September 1993.
The ANEC merger added approximately 400 gross wells, 200 of which are now operated by the Company, and nearly doubled the Company's reserve base. The majority of the properties are concentrated in the same areas as the Company's operations, particularly in the Anadarko Area of Central Oklahoma. Many of ANEC's proved reserves, however, are located in the Cotton Valley Trend of East Texas where ANEC has enjoyed excellent success drilling infill wells since 1985. Subsequent to the merger, the Company conducted workovers on the Cotton Valley Trend properties.
JMC Properties Acquisition. Effective October 1, 1994, the Company acquired 78 natural gas properties located in the Arkoma Basin in Oklahoma and Arkansas from JMC Exploration, Inc. of Fort Smith, Arkansas, ("JMC Properties") for total consideration of $18.2 million. The 78 properties, one-half of which will be operated by the Company, contributed 25.7 Bcfe of estimated natural gas to the Company's reserve base as of December 31, 1994, and are expected to add approximately $3.0 million in cash flow. The JMC Properties reestablished the Company in the Arkoma Basin in Oklahoma and Arkansas, a significant area of development for the Company in its early years, with a strong position of proved reserves, one-third of which remain to be developed. Planned exploitation efforts and expected development of proved developed reserves are expected to add substantially to the ultimate value of the acquisition.
The JMC acquisition greatly increased the Company's proved reserves, production and cash flow. As a result of the JMC Properties acquisition, the Company's proved reserve base has increased 16% from 146 Bcfe to 169 Bcfe. The natural gas component of the Company's reserve base increased from 84% at 1993 year end to 86% at December 31, 1994. In addition, approximately 53% of the Company's reserve base is undeveloped (or behind pipe), providing the Company with an excellent inventory of low risk development drilling opportunities. This transaction increased the Company's production from 22.0 MMcfe per day in 1993 to 25.7 MMcfe per day in 1994.
OTHER SIGNIFICANT ACQUISITIONS
Acquisition of Bradmar Petroleum Corporation. On March 19, 1992, Bradmar became a wholly owned subsidiary of the Company. Each outstanding share of Bradmar common stock (1,890,064 shares) was exchanged for $2.57 in cash and .48 shares of the Company's Common Stock for an aggregate direct purchase price of approximately $8.3 million. The Bradmar acquisition resulted in the combination of oil and gas operations in many of the same fields and formations as the Company's, elimination of duplicate facilities, reduction in aggregate personnel and reduction in professional fees and expenses. See Note 2 of Notes to Consolidated Financial Statements of the Company.
At the time of acquisition, the Bradmar properties increased the proved reserves of the Company by approximately 72%. Based upon a reserve report prepared by Edinger Engineering Incorporated ("Edinger") dated as of January 1, 1993 and proved undeveloped reserve estimates developed by the Company's engineers, the Company's estimated proved reserves were increased from 24.5 Bcf of gas and 2.6 MMBbls of oil at the time of acquisition to 49.8 Bcf of gas and 3.16 MMBbls of oil at December 31, 1992, approximately nine months after the effective date of the merger. This acquisition also increased the Company's net acres of undeveloped leaseholds from 2,979 to 4,479 at the time of acquisition. Since the acquisition, the Company has reviewed the Bradmar properties, identified those marginal properties with no apparent enhancement prospects and sold them. During 1992, the Company sold interests in approximately 247 wells accounting for proved developed and proved undeveloped reserves of 4.8 MMcf of gas and 151 MBbls (as of December 31, 1991), for net cash proceeds of approximately $2.1 million and reductions of net gas balancing liabilities of approximately $0.4 million.
During 1994, the Company added significant reserves as a result of exploitation of the Bradmar properties. Bradmar reserves on December 31, 1993 totaled 25.7 Bcf of gas and 624,000 Bbls of oil [29.5 Bcfe]. At December 31, 1994, the Bradmar properties had reserves totaling 26.2 Bcf of gas and 803,000 Bbls of oil (31.0 Bcfe). This increase in the reserves attributable to the Bradmar properties reflected an increase of 9.9 Bcfe, when adjusted for reserves produced in 1994.
MFS Properties. In June 1990, the Company purchased a working net profits interest in approximately 230 producing oil and gas properties located primarily in Oklahoma (the "MFS Properties") for a net purchase price of approximately $3.0 million from MFS Production Co., Inc., an affiliate of Mellon Bank, N.A. The purchase was financed, in part, by certain bank borrowings and the Company's sale to MWR of approximately 89,209 shares of Common Stock for $250,000 and 100,000 shares of Series A Preferred Stock for $1.0 million. The Company also issued to MWR the option to purchase 100,000 shares of Common Stock at an exercise price of $3.00 per share (the "Investor Option"). In 1993, MWR exercised in full its Investor Option to purchase 100,000 shares, and the 100,000 shares were sold by MWR in the Offering. The Series A Preferred Stock was converted to 333,333 shares of Common Stock and sold to the underwriters as part of the over-allotment option. See "--- Secondary Public Offering."
In September 1994, the Company sold all of its interest in the MFS Properties to Hugoton Energy Corporation, with offices in Wichita, Kansas, for a purchase price of $3.5 million. This transaction was a part of the settlement of certain litigation between the Company and Bill J. Barbee, S. Keith Tuthill, and Tuthill & Barbee which affected the MFS Properties.
Zilkha Properties. In April 1989, the Company and Hancock formed AEJH 1989 Limited Partnership ("AEJH 1989") to acquire and exploit leasehold interests in a group of 48 producing oil and gas properties located in Oklahoma and Texas from Zilkha Energy Corporation ("Zilkha"). AEJH 1989 financed the $3.1 million purchase price for these properties by issuing to Hancock a 10.5% senior secured note of AEJH 1989 due December 31, 1999, with a principal amount of approximately $2.2 million, which is non-recourse to the Company, and by a $468,000 capital contribution received from each of the Company and Hancock.
All costs and revenues from the Zilkha properties (other than principal and interest payments made pursuant to the 10.5% senior secured note and related agreements) are allocated 52.5% to Hancock and 47.5% to the Company. All costs of acquiring and drilling additional properties, reworking or plugging any of the Zilkha properties and payments of principal and interest on the 10.5% senior secured note are allocated 50% to the Company and 50% to Hancock. The Company receives a management fee from AEJH 1989 of a maximum of $10,000 per month. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations -- Operator and Management Fees."
The net proceeds of AEJH 1989 (consisting of oil and gas revenues less lease operating costs, capital expenditures, out-of-pocket expenses, interest payments and the management fee) are disbursed monthly after funding optional operations not covered by capital contributions by Hancock and the Company. AEJH 1989 distributes (I) 80.75% from each month's remaining net revenues to Hancock as a principal payment on the 10.5% senior secured note until it is paid in full, and (ii) the 19.25% balance to Hancock and the Company on a 63%/37% respective basis. As of December 31, 1994, the outstanding principal balance on the AEJH 1989 10.5% senior secured note was $1.85 million ($925,452 net to the Company's interest). AEJH 1989 may be required to prepay a portion of the 10.5% senior secured note or pledge additional property as collateral if it is determined that the note is undercollateralized. Hancock may recover the outstanding balance on the 10.5% senior secured note only from net proceeds of AEJH 1989 even if future net proceeds are insufficient to repay the note.
Brooks Hall Properties. In June 1984, the Company acquired certain oil and gas properties from BHEC and related entities for approximately $18.6 million of total consideration. The acquired properties included 421 producing
oil and gas wells located in Alabama, Arkansas, Colorado, Kansas, Louisiana, New Mexico, Oklahoma and Texas; interests in three natural gas processing plants in Oklahoma; and 2,122 undeveloped net acres in Oklahoma. Independent reserve estimates indicated that the properties had proved developed producing reserves of 13,625 MMcfe. The Company assumed operations for 54 of the acquired producing wells.
Financing of the acquisition was comprised of a $1,000,000 90-day note, a $6,314,000 five-year note, a $1,804,000 two-year note, a $7,500,000 7% convertible seven-year debenture and shares of Common Stock valued at $2,000,000. The Company repurchased the convertible debentures and Common Stock in 1988 with the proceeds of the Company's 10% senior unsecured notes issued in the aggregate principal amount of $5.0 million. As part of this transaction, the Company issued the Stock Purchase Warrant to Hancock. See ITEM 3. LEGAL PROCEEDINGS and Notes 4 and 13 of Notes to Consolidated Financial Statements of the Company.
The BHEC acquisition exemplifies the results of the Company's exploitation program. The Company has identified significant recompletion opportunities, including proved behind pipe reserves exceeding 83 MBbls of oil and 2.3 Bcf of natural gas, and future drilling prospects with proved undeveloped reserves of more than 110 MBbls of oil and 1.7 Bcf of natural gas at December 31, 1994. In addition to these proved reserves, AEJH 1985 and AEER 1985 Limited Partnerships have drilled a substantial number of wells on the BHEC acreage. See "--- Drilling Programs." Workovers and gas contract renegotiations that increased prices on several wells have also generated significant increases in both reserves and values by enhancing the economic life of the subject wells.
DRILLING PROGRAMS
The Company generates its own in-house prospects and rarely participates in an outside drilling prospect presented by a third party. The majority of generated prospects are located in the Oklahoma Anadarko Shelf and Anadarko Basin areas. The Company believes it is able to achieve better results by concentrating in these areas with which the Company's geological, engineering and land staffs are more familiar.
The Company currently has a large drilling location inventory, of which 145 locations are included in the reserve report as proved undeveloped. Although the Company also drills a number of exploration wells each year, its drilling activity has been, and is expected to continue to be, concentrated in the development of established production. This low-risk strategy has helped the Company achieve reserve addition costs below the industry averages. The Company's ability to drill all of these locations will depend on its cash flow and the availability of acceptable financing. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
The Partnerships. In August 1985, the Company and Hancock formed the AEJH 1985 Limited Partnership ("AEJH 1985") to acquire, drill and develop interests in 125 (subsequently increased to 176) oil and gas wells. The Company, as sole general partner of AEJH 1985, agreed to contribute up to $6.3 million, and Hancock, as sole limited partner of AEJH 1985, agreed to contribute up to $16.5 million. Funding of these commitments occurs as the wells are proposed. At December 31, 1994, Hancock and the Company had funded 100% of their respective commitments. The Company funds 25% of the drilling and completion costs in initial wells (127 of which have been drilled or proposed to date) and 36% of the drilling and completion costs of secondary wells (49 of which have been drilled or proposed to date). The Company has a 36% net revenue interest in all of the wells.
In connection with the formation of AEJH 1985, Hancock purchased from the Company 104,911 shares of Common Stock and was granted certain registration rights with respect to such shares. The Company has a right of first refusal to purchase these shares if offered for sale by Hancock.
In December 1985, the Company and Energy Reserves, Inc., a wholly subsidiary of Midwest ("Energy") formed AEER 1985 Limited Partnership ("AEER 1985") to acquire, drill and develop interests in 107 (subsequently increased to 128) oil and gas wells. The Company, as the sole general partner of AEER 1985, agreed to contribute $2.6 million, and Energy, as the sole limited partner of AEER 1985, agreed to contribute $7.4 million. Certain development offset locations have been drilled since the formation of AEER 1985. The Company funded 25% of the drilling and completion costs in 107 initial wells and 36% of the drilling and completion costs of the 21 secondary wells. The Company had a 36% net revenue interest in all of the wells. The Company and Energy funded $3.7 million and $9.5 million, respectively, in AEER 1985, representing 100% of their respective commitments. On June 18, 1993, the Company acquired all of Energy's interest in AEER 1985 for an adjusted purchase price of approximately $1.0 million. Reserves attributable to Energy's interest at the time of acquisition was approximately 2 Bcf of gas and 300,000 barrels of oil, with historical cash flow in excess of $500,000 per year. The Company terminated AEER 1985 on September 8, 1993.
In 1987, the Company and Hancock formed two limited partnerships to acquire oil and gas properties from two companies which had defaulted on loans to Hancock. The assets of one of the partnerships were divested and the partnership was terminated during December 1994. The Company continues to serves as general partner and receives a management fee from the remaining 1987 drilling program.
MARKETS AND CUSTOMERS
The Company operates exclusively in the oil and gas industry. Its revenues are derived from its proportionate interest in domestic oil and gas producing properties. The Company does not consider its business seasonal; however, market demand (and the resulting prices received for crude oil and natural gas) can be affected by weather conditions, economic conditions, import quotas, the availability and cost of alternative fuels, the proximity to, and capacity of, natural gas pipelines and other systems of transportation, the effect of state regulation of production, and federal regulation of oil and gas sold in intrastate and interstate commerce. All of these factors are beyond the control of the Company.
The Company sells its crude oil at posted field prices in effect in the producing fields within which its operations are conducted. During the years ended December 31, 1993 and 1994, the price for the Company's oil ranged from $19.44 per Bbl to $10.75 per Bbl and from $20.59 per Bbl to $10.65 per Bbl, respectively. Because of restrictions on flaring natural gas, wells which produce both oil and gas may be shut-in when there is not a market for the gas, even though a market is otherwise available for the oil.
Natural gas production of the Company is sold under long-term and spot market contracts to intrastate and interstate pipeline companies and natural gas marketing companies. Prices received by the Company for gas production during the years ended December 31, 1993 and 1994 varied from $.29 per Mcf to $4.71 per Mcf and from $.65 per Mcf to $4.90 per Mcf, respectively.
Approximately 42% of the Company's natural gas is sold on the spot market or under short-term contracts (one year or less) providing for variable or "market-sensitive" prices. Approximately 58% of the Company's natural gas is marketed under various long-term contracts which dedicate the natural gas to a purchaser for an extended period of time, but which still involve variable or market-sensitive pricing of the Company's natural gas.
The Company's gas production is sold under contracts with various purchasers. Gas sales to each of GPM Gas Corporation and Cowboy Pipeline Service Company individually approximated 11%, 12% and 13% of total revenues for the years ended December 31, 1992, 1993 and 1994, respectively.
During each of the three years in the period ended December 31, 1994, the Company sold approximately 28%, 20% and 24%, respectively, of its oil production through an entity ("IEM") in which the Company owned a limited partner interest recorded on the equity method. Net distributable income of IEM was allocated 60% to the limited partners and 40% to the general partner. For the two years ended December 31, 1993 and the eight months ended August 31, 1994, the Company received 100% of the amount allocable to the limited partners based on the percentage of volumes the Company sold to IEM of the total by all limited partners. Effective August 31, 1994, the Company terminated its marketing arrangement with IEM and thus, withdrew as a limited partner. As a result, the indirect marketing fees and the Company's equity interest in IEM's operating profit or loss ceased as of August 31, 1994. The Company received the highest posted price for all such production, an indirect marketing fee from the ultimate purchaser and a percentage of operating profit of IEM, if any. In 1992, 1993 and the eight months ended August 31, 1994, the Company recorded pass-through marketing fees of $80,000, $96,000 and $96,000, respectively, and operating profits (losses) of $46,000, $1,500 and $(9,700), respectively. The partnership was mutually terminated in August 1994.
The Company does not believe that the loss of any of its customers would have a material adverse effect on the results of operations of the Company.
REGULATION
General. The oil and gas industry is extensively regulated by federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion. In October 1992, President Bush signed into law, comprehensive national energy legislation was enacted which focuses on electric power, renewable energy sources and conservation. The legislation, among other things, guarantees equal treatment of domestic and imported natural gas supplies, mandates expanded use of natural gas and other alternative fuel vehicles, funds natural gas research and development, permits continued offshore drilling and use of natural gas for electric generation and adopts various conservation measures designed to reduce consumption of imported oil.
Numerous governmental departments and agencies, both federal and state, have issued rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for the failure to comply. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.
Exploration and Production. The Company's exploration and development operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. The Company's operations are also subject to various conservation matters and rules to protect the correlative rights of subsurface owners. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of land and leases. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and gas the Company can produce from its wells and to limit the number of wells or the locations at which the Company can drill. Recently enacted legislation in Oklahoma and regulatory action in Texas modifies the methodology by which the regulatory agencies establish permissible monthly production allowables. Such action has generated substantial controversy, especially at the federal level, and has been labeled as being intended to reduce the total production of natural gas in order to increase gas prices. A recent attempt to enact a federal prohibition of these recent state proration rule initiatives was defeated, but various members of Congress and some federal regulators have declared an intent to monitor the states' actions very carefully. The Company cannot predict what effect these new prorationing regulations will have on its production and sales of gas.
Certain of the Company's oil and gas leases are granted by the federal government and administered by various federal agencies. Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on these leases and calculation and disbursement of royalty payments to the federal government. The Mineral Lands Leasing Act of 1920 (the "MLLA") places limitations on the number of acres under federal leases that may be owned in any one state. Additionally, the MLLA and related regulations also may restrict a corporation from holding federal onshore oil and gas leases if stock of such corporation is owned by citizens of foreign countries which are not deemed reciprocal under the MLLA. Reciprocity depends, in large part, on whether the laws of the foreign jurisdiction discriminate against a United States citizen's ownership of rights to minerals in such jurisdiction. The purchase of shares in the Company by citizens of foreign countries with laws which are not deemed to be reciprocal under the MLLA could have an impact on the Company's ownership of federal leases.
Environmental and Occupational Regulations. The Company has an engineer who also serves as an environmental compliance officer with the responsibility to implement an environmental compliance program and to monitor environmental compliance and potential environmental liabilities of the Company. Operations of the Company are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, limit or prohibit drilling activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from drilling operations. Such laws and regulations may also restrict air or other pollution resulting from the Company's operations. Moreover, many commentators believe that the state and federal environmental laws and regulations will become more stringent in the future. For instance, legislation has been proposed in Congress in connection with the pending reauthorization of the federal Resource Conservation and Recovery Act ("RCRA"), which would amend RCRA to reclassify oil and gas production wastes as "hazardous waste." If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. State initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states and these various initiatives could have a similar impact on the Company. Management believes that compliance with current applicable environmental laws and regulations will not have a material adverse impact on the Company. However, many of these laws and regulations increase the Company's overall operating expenses, and future changes to environmental laws and regulations could have a material adverse impact on the Company.
The Company is also subject to laws and regulations concerning occupational safety and health. While it is not anticipated that the Company will be required in the near future to expend amounts that are material in the aggregate to the Company's overall operations by reason of occupational safety and health laws and regulations, the Company is unable to predict the ultimate cost of compliance.
Marketing and Transportation. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). From 1978 until January 1, 1993, maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. The NGPA established various categories of natural gas and provided for graduated deregulation of price controls of several categories of natural gas and the deregulation of sales of certain categories of natural gas.
Several major regulatory changes have been implemented by the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purposes of many of these regulatory changes is to promote competition among the various sectors of the gas industry. The ultimate impact of these complex and overlapping rules and regulations, many of which are repeatedly subjected to judicial challenge and interpretation, cannot be predicted.
Various rules, regulations and orders, as well as statutory provisions, may affect the price of natural gas production and the transportation and marketing of natural gas.
No Price Controls on Liquid Hydrocarbons. Sales of crude oil, condensate and natural gas liquids can be made at uncontrolled prices. Although in the past there have been regulations of the sales price of liquid hydrocarbons, there are currently no price controls on crude oil, condensate or natural gas liquids.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the exploration for and production of oil and gas, such as blowouts, cratering, abnormally pressured formations, explosions, uncontrollable flows of oil, gas or well fluids into the environment, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can result in substantial losses to the Company due to personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage or suspension of operations.
The Company maintains insurance of various types to cover its operations. The Company has $1.0 million of general liability insurance and an additional $7.0 million of excess liability insurance. In addition, the Company maintains operator's extra expense coverage which applies to care, custody and control of drilling wells and to completed wells within city limits. The Company's insurance does not cover every potential risk associated with the drilling and production of oil and gas. In particular, coverage is not obtainable for certain types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on the Company's financial condition and results of operations. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable.
The Company maintains levels of insurance customary in the industry to limit its financial exposure in the event of a substantial environmental claim resulting from sudden and accidental discharges; however, 100% coverage is not maintained. Unreimbursed expenditures in 1992, 1993 and 1994 were immaterial.
COMPETITION
The Company operates in a highly competitive environment, particularly with respect to the acquisition of producing properties and proved undeveloped acreage, contracting for drilling equipment and securing trained personnel. Major integrated and independent oil and gas companies actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. The Company believes that the locations of its leasehold acreage, its exploration, drilling, exploitation and production capabilities and the experience of its management generally enable it to compete effectively in its principal producing areas. A number of the Company's competitors, however, have financial resources and exploration and development budgets that substantially exceed those of the Company, and may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future exploration and development. In addition, intense competition occurs with respect to marketing, particularly of natural gas, primarily due to the oversupply of gas available for sale.
EMPLOYEES
As of March 24, 1995, the Company employed 50 full-time employees, none of which was subject to a collective bargaining agreement. The Company's professional staff includes three landmen, four geologists, five engineers, five accountants, three division order analysts and a marketing specialist. The Company considers relations with its employees to be good.
ITEM 1A.

ITEM 1A. EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of the Company are identified below. The officers serve at the pleasure of the Board of Directors. Roger G. Alexander is the son of Bob G. Alexander. No other officer is related to any other officer or to any director of the Company.
BOB G. ALEXANDER, a founder of the Company, has been a director and the President and Chief Executive Officer of the Company since inception in 1980. From 1976 to 1980, Mr. Alexander was Vice President and General Manager of the Northern Division of Reserve Oil, Inc. and President of Basin Drilling Corp. (subsidiaries of Reserve Oil and Gas Company). Mr. Alexander attended the University of Oklahoma and graduated in 1959 with a bachelor of science degree in geological engineering. He has extensive experience in exploration, drilling and production in the Mid-Continent, West Texas and Gulf Coast regions and Utah for major and independent oil and gas companies. Professional memberships include the Independent Petroleum Association of America ("IPAA"), of which he currently serves as a member of the Executive and Economic Committees, and the Oklahoma Independent Petroleum Association, of which he serves as a director. He is currently Vice Chairman of the Natural Gas Task Force of Oklahoma and former chairman and current member of The Commission on Natural Gas Policy. Mr. Alexander was appointed by the Oklahoma Governor to serve as a member of the Independent Energy Resources Board for the State of Oklahoma, the Governor's Council on Energy and to the Gas Research Institute, a joint effort of the State of Oklahoma and the IPAA.
DAVID E. GROSE joined the Company at its inception in March 1980 as a financial accountant and served as Assistant Treasurer from October 1983 until his election in February 1987 as Vice President, Treasurer and Chief Financial Officer. From 1977 to 1980 he held a position in the corporate accounting department of Reserve Oil, Inc. and was rig accountant for Basin Drilling Corporation. Mr. Grose received a bachelor of arts degree in political science from Oklahoma State University in 1974 and a masters degree in business administration from Central State University in 1977. Professional memberships include the Petroleum Accountants Society of Oklahoma City and the IPAA. Mr. Grose formerly served on the Tax Committee of the IPAA.
JIM L. DAVID, a founder of the Company, has served as Vice President since its inception in March 1980. Mr. David began his career in oil and gas exploration with Mobil Oil Corporation as an exploration and development geologist. He worked in this capacity in Shreveport, Louisiana; Corpus Christi, Texas; New Orleans, Louisiana;
Denver, Colorado; and Anchorage, Alaska. From October 1973 to October 1976, Mr. David served as Alaska chief geologist and senior staff geologist for Texas International in Oklahoma City. Thereafter, he was employed as exploration manager for Reserve Oil, Inc., Northern Division, in Oklahoma City from January 1977 until formation of the Company. Mr. David graduated with a bachelor of arts degree in geology from Louisiana Tech University in 1962 and obtained a master of arts in geology from the University of Missouri in 1964. Professional memberships include the American Association of Petroleum Geologists and the Oklahoma City Geological Society. Mr. David is a certified petroleum geologist.
ROGER G. ALEXANDER, a certified professional landman, has served as Vice President (Land) and director of the Company since February 1987. Mr. Alexander joined the Company as a landman in August 1983 and became senior landman in August 1984. In July 1985, he was named Land Manager. He was employed as a landman by Texas Oil & Gas Corporation in its West Texas District, Midland, Texas, from June 1981 to August 1983. Mr. Alexander graduated with a bachelor of business administration degree, with a major in petroleum land management, from the University of Oklahoma in 1981. Professional memberships include the American Association of Petroleum Landmen and the Oklahoma City Association of Petroleum Landmen.
JAMES S. WILSON has served as Vice President (Operations) since June 1987. Prior to joining the Company in 1987, he served as President of Primary Petroleum Development, Inc., Oklahoma City, Oklahoma, a petroleum operating and consulting firm. Mr. Wilson holds a petroleum engineering degree from the University of Oklahoma, and was named one of the top ten senior men in 1974. He held several engineering and management positions with Amoco Production from 1974 to 1981. From 1981 to 1985, Mr. Wilson held positions as Vice President of Operations for Coloma Petroleum, Inc. and HG&G, Inc. in Denver and Oklahoma City, respectively. He was named to the American Petroleum Institute Committee on Reserves in 1977 and has served in numerous committee and officer capacities for The Society of Petroleum Engineers. Mr. Wilson has taught as an adjunct professor for The University of Oklahoma Graduate School of Business since 1983.
LARRY L. TERRY joined the Company as Vice President (Corporate Development) after the merger with ANEC in July 1994. Mr. Terry served as ANEC's Chief Financial Officer from March 1993 to July 1994. Mr. Terry was a consultant with the consulting firm of Woodrum, Shoulders & Kemendo of Tulsa, Oklahoma from 1990 to 1993. He began his career on the audit staff of Ernst & Young, a national accounting firm, (formerly Arthur Young & Company) concentrating primarily on oil and natural gas clients. He served for ten years as Chief Financial Officer for Andover Oil Company, a large independent oil and gas exploration and production company. Mr. Terry received a degree in business administration with a major in accounting from Oklahoma State University and is a certified public accountant.
SUE BARNARD has served as Corporate Secretary since July 1985 and director of investor relations since June 1988. Additionally, since 1986 she has served the Company in the capacities of Risk Manager and Manager of Human Resources. Ms. Barnard joined the Company in June 1982 as assistant to the Vice President - Administration and as Assistant Corporate Secretary. Professional memberships include the American Society of Corporate Secretaries.
ITEM 2.


ITEM 2. PROPERTIES
Real Estate. The Company owns a 19,000 square foot office building located at 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma where it maintains its corporate headquarters. In August 1994, the Company purchased approximately 1.5 acres adjacent to its corporate headquarters. The purchase price of the land was $216,000.
OIL AND GAS PROPERTIES
As of December 31, 1994, the Company owned working interests in approximately 814 gross wells, 447 of which it operates. The Company also owned interests in 86 wells in which the Company has a revenue interest other than as a working interest owner. The majority of these interests are located in Oklahoma, Texas and Arkansas. See "-- Productive Wells and Acreage."
As of December 31, 1994, the Company owned working interests in 307 gross (120.6 net) producing oil wells and 450 gross (120.8 net) producing gas wells, as well as 27 gross (15.5 net) oil and 30 gross (10.8 net) gas wells that were shut-in. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.
The Company's activities in Oklahoma are generally located in the Anadarko Shelf and the Anadarko Basin, as well as the central and southern portions of the state. At December 31, 1994, the Company had working interests in approximately 689 gross (226.7 net) wells located in Oklahoma, of which 386 are operated by the Company.
The majority of the Company's interests in Texas are located in Harrison, Rusk, Fayette, Jones, Burleson, Coke and Lee Counties which are primarily in the central and west central portions of the state. At December 31, 1994, the Company's holdings in Texas consisted of working interests in approximately 53 gross (22.8 net) wells, 35 of which are operated by the Company.
The JMC Properties acquisition in November 1994 significantly increased the Company's holding in the Arkoma Basin in Arkansas. See 1994 ACQUISITION ACTIVITIES --- JMC Properties Acquisition. As of December 31, 1994, the Company's position in Arkansas consisted of working interests in 44 gross (13.4 net) producing gas wells, as well as 2 gross (1.7 net) gas wells that were shut-in. The Company serves as operator of 16 of the wells.
The remainder of the Company's holdings and operations are located in Colorado (3), Kansas (6), Nebraska (1) and Wyoming (7).
The following table sets forth estimated proved reserves, the estimated future net revenues therefrom and the present value thereof as of December 31, 1994 for the Company based upon the Summary Reserve and Appraisal Report of Edinger. In the preparation of such report, Edinger estimated the Company's proved developed producing reserves as of December 31, 1994. The proved undeveloped reserves as of December 31, 1994 were estimated by the Company and reviewed by Edinger as specified in their letter dated March 29, 1995. This review should not be construed to be an audit as defined by the Society of Petroleum Engineers' audit guidelines. The calculations used in preparation of such reports were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines (as described in the notes below). These correspond with the method used in presenting the supplemental information on oil and gas operations in the Notes to the Consolidated Financial Statements of the Company, except that income taxes otherwise attributable to such future net revenues have been disregarded in the presentation below. For supplemental disclosure of the estimated net quantities of oil and natural gas reserves, see Note 15 of Notes to Consolidated Financial Statements of the Company.
(1) Oil production is converted to Mcfe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. The respective prices of oil and gas are affected by market and other factors in addition to relative energy content.
(2) Estimated future net revenue represents estimated future gross revenues to be generated from the production of proved reserves, net of estimated production and future development costs, using costs and prices in effect as of December 31, 1994. In certain circumstances, the actual gas price received was less than the December 31, 1994 contract price, in which case the lower actual price was used. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices of $1.62 per Mcf of natural gas and $16.25 per Bbl of oil over the life of the properties. The amounts shown do not give effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization.
(3) Present value is calculated by discounting estimated future net revenue by 10% per annum.
No estimates of the Company's proved reserves have been included in reports to any federal agency other than the SEC.
The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil and gas production subsequent to December 31, 1994. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations -- Oil and Gas Prices." There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
The process of estimating oil and gas reserves contains numerous inherent uncertainties and requires significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and material revisions to existing reserve estimates may occur in the future.
PRODUCTION AND PRICE HISTORY
The following tables set forth certain historical information concerning the Company's oil and natural gas production and prices, net of all royalties, overriding royalties, and other third party interests.
(1) Oil production is converted to Mcfe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. The respective prices of oil and gas are affected by market and other factors in addition to relative energy content.
(2) Production cost consists of lease operating expenses and production taxes.
DRILLING ACTIVITIES
In each of the years ended December 31, 1992, 1993 and 1994, the Company incurred net exploration and development costs of $2.1 million, $11.3 million and $12.3 million, respectively. The decrease in net exploration and development costs for 1992 is attributable to the Company allocating its resources to review, evaluate and consummate the Bradmar acquisition while the increase in 1993 is largely due to the availability of funds resulting from the Offering. The following table sets forth the Company's historical drilling activities for each of the years ended December 31, 1992, 1993 and 1994:
(1) The decrease in drilling activity during this period was due to the Company allocating its resources to review, evaluate and consummate the Bradmar acquisition.
The table above only reflects those interests attributable to the Company either through direct working interests or through the Company's proportionate share of its partnership's participation; i.e., the interests shown do not include overriding royalty interests, carried working interests, reversionary interests or partners' proportionate share of participation.
PRESENT ACTIVITIES
As of December 31, 1994, the Company held working interests in 5 gross (2.077 net) wells which were in the process of being drilled at such date. The Company also held interests in a total of 2 gross (1.125 net) wells on which operations had been temporarily suspended.
FUTURE DRILLING ACTIVITIES
The Company currently has plans to drill during 1995 approximately 34 gross wells in which the Company would have an average working interest of 45%. The Company anticipates that approximately 32 of these wells will be proved undeveloped locations and 2 will be exploratory locations. Estimated completed well cost to the Company's current interest in such wells is $12.2 million, of which approximately 93% would be expended on proved undeveloped locations and 7% on exploratory drilling. The future net revenues for the proved undeveloped locations estimated by the Company as of December 31, 1994 aggregate approximately $75 million after recovering associated capital costs of approximately $37 million. The capital costs associated with the 145 planned development wells are approximately $37 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
PRODUCTIVE WELLS AND ACREAGE
The following table reflects the wells and acreage in which the Company owned a working interest, directly or indirectly, as of December 31, 1994. The table shows producing oil (including casinghead gas) and natural gas wells, including shut-in oil and gas wells capable of producing gas which are (I) awaiting the construction or completion of gas plants or gathering facilities, (ii) shut-in until sufficient reserves of gas are established to justify construction of such facilities or (iii) shut-in due to the absence of a market. The table does not include 86 gross wells in which the Company has a revenue interest other than as a working interest owner. The Company additionally owns overriding royalty interests or other revenue interests in approximately 225 of the gross wells reflected below.
Undeveloped acres are those 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 or not such acreage contains proved reserves. The amount of acreage held by the Company increases or decreases in the normal course of business as interests in new acreage are acquired (including acreage by pooling), as interests are sold or contributed to others, as wells are drilled, as properties are abandoned (if determined not to warrant exploration or development) or as leases expire. It is the Company's policy to formulate drilling plans for the orderly development of undeveloped acreage within the primary terms of the leases involved.
CHEMICAL SUPPLY COMPANY
In May 1991, the Company became a limited partner of Energy and Environmental Services Limited Partnership ("EES"), of which Energy and Environmental Services, Inc. ("EES, Inc.") serves as general partner. EES was organized for the primary purpose of providing the oil and gas industry with chemicals, drilling mud, additives, well stimulation fluids and other oil field services. The Company acquired 90% of the limited partner interests at a cost of $900. Additionally, the EES partnership agreement required that the limited partners loan EES $200,000 ($150,000 by the Company) with interest currently payable at the rate of 7.5% per annum. The loans are guaranteed by the general partner and its officers and are due upon demand. Additionally, in connection with its investment in EES, the Company guaranteed the remaining indebtedness of EES, Inc., which was paid off during 1994. During 1992 and 1993, $60,000 and $30,000 of repayments were funded by the Company, respectively, which payments have been added to the note receivable, the aggregate balance of which was $200,000 at December 31, 1994. Terms of this related party's debt require monthly payments of $10,000 plus accrued interest. See Note 3 of Notes to Consolidated Financial Statements of the Company.
TITLE TO PROPERTIES
Substantially all of the Company's property interests are held pursuant to leases from third parties. Title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, liens incident to operating agreements, liens relating to amounts owed to the operator, liens for current taxes not yet due and other encumbrances. The Company believes that such burdens neither materially detract from the value of such properties nor from the respective interests therein, or materially interfere with their use in the operation of the business. Substantially all of the Company's oil and gas properties and proceeds therefrom and partnership distributions are and will continue to be mortgaged to secure borrowings under the Company's bank credit facility.
As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made prior to the consummation of an acquisition of a producing property and before commencement of drilling operations.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
In 1988, in connection with the issuance of certain unsecured notes payable to Hancock, the Company entered into a related investment agreement which provided Hancock with warrants ("the Stock Purchase Warrants") to purchase 223,333 shares of the Company's common stock at $3.00 per share. Any of the shares of the Company's stock acquired pursuant to an exercise of the warrants, could have been "put" back to the Company, at Hancock's discretion, at any time from December 31, 1992, through December 31, 1993, at $12.99 per share or the unexercised option could have been "put" to the Company at $9.99 per share upon 60 days prior written notice and surrender of the warrants. See Notes 7 and 13 of Notes to Consolidated Financial Statements of the Company.
The Stock Purchase Warrants expired by their terms on December 31, 1993. Hancock failed to exercise the Stock Purchase Warrants, and, the Company contends, failed to properly exercise its warrant put option. On February 3, 1994, the Company filed a Complaint for Declaratory Judgment in the United States District Court for the Western District of Oklahoma requesting that the Court declare that the Warrants expired at December 31, 1993 and have no continued legal effect thereafter and that Hancock has no rights thereunder. It is the Company's opinion that Hancock failed to properly exercise the Stock Purchase Warrants or the warrant put option. Hancock filed an Answer and Counterclaim to the Complaint for Declaratory Judgment asserting breach of contract and misrepresentation and seeks the Court to order a judgment against the Company to pay Hancock $2,231,100. The Company reclassified the amount accrued through December 31, 1993 on the consolidated balance sheets pending the ultimate resolution of this contingency. During the fourth quarter of 1994, the Company settled this contingency with Hancock for $1.1 million.
In July 1991, ANEC participated as a 25% working interest owner in a re-entry and completion project of an existing wellbore designated as the Douglas 13-1 Gas Well located in the Arkoma Basin Geological Region in Pittsburgh County, Oklahoma. In May 1992, Unit Drilling Company ("Unit"), et al (which includes Midwest Energy Corporation ("MEC") creditors), the drilling contractor, and other service contractors on the Douglas 13-1 filed an action against MEC, operator of the well, for unpaid drilling costs. In its action, Unit sought to foreclose a lien on the entire well, which included ANEC's 25% working interest in the well. In September and October 1994, the Company acquired MEC's creditors outstanding judgements against the well for cash consideration of approximately $409,000 in an effort to protect its interest in the well.
In June 1992, ANEC filed an action in the District Court of Tulsa County, State of Oklahoma against MEC for an accounting of expenditures on the Douglas 13-1. The action was amended to include a claim for actual and punitive damages against MEC for misrepresentation of the prospect as well as improper conduct as operator of such well. In that action, MEC filed a counterclaim against ANEC for $344,000 in drilling, completion and operating costs on the well. In its counterclaim, MEC also named Endowment Energy Partners, L.P. ("EEP") as a defendant claiming damages for business interference and sought consequential damages. On November 9, 1992, the District Court of Tulsa County allowed an Answer to Amended Petition, Counterclaim and Third-Party Claim to be filed pursuant to which Martin A. Vaughan and Nancy S. Vaughan, husband and wife, individually, and Nancy S. Vaughan and J. Steven Swab as Co-Trustees of the John T. Swab Revocable Inter Vivos Trust B (hereinafter collectively referred to as the "Vaughans") were permitted to become additional Third-Party Plaintiffs. The Vaughans, who were the stockholders of MEC at the time of the events in question, filed a claim against ANEC for breach of an alleged merger agreement wherein they sought to recover $3.3 million in damages.
In December 1994, ANEC, MEC, the Vaughans, and EEP entered into a settlement agreement in which ANEC agreed to pay MEC the sum of $625,000, release the judgments which it acquired from the MEC creditors, cross-
assign interests in certain properties valued at less than $60,000, and dismiss all of the claims against each other. The aggregate effect of this negotiated settlement resulted in a charge to 1994 operations, including legal fees, of approximately $734,000.
The Company and its subsidiaries are named defendants in lawsuits and are involved from time to time in governmental proceedings, all arising in the ordinary course of business. Although the outcome of these lawsuits and proceedings cannot be predicted with certainty, management does not expect these matters will have a material adverse effect on the financial position of the Company.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is traded on the NASDAQ National Market System under the symbol "AEOK". The following table sets forth the high and low closing sales price for each of the periods indicated as quoted by NASDAQ.
As of March 24, 1995, there were 2,094 stockholders of record.
DIVIDENDS
The Company has never paid cash dividends on its Common Stock and does not expect to pay any cash dividends in the foreseeable future. It intends to retain its earnings to provide funds for operations and expansion of its business. Moreover, pursuant to the terms of certain of the Company's debt agreements, the Company is prohibited from declaring or paying any cash dividends on its Common Stock. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and Note 4 of Notes to Consolidated Financial Statements of the Company.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected historical financial data with respect to the Company as of and for each of the five years in the period ended December 31, 1994, as restated to give effect to the 1994 pooling of interests between the Company and ANEC as described in Note 2 of Notes to Consolidated Financial Statements. The financial data was derived from the consolidated financial statements of the Company. This information is not necessarily indicative of the Company's future performance. The Company has never declared or paid dividends on its Common Stock. The financial data set forth below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the notes thereto of the Company. The information reflects the accounts of the Company, its wholly-owned subsidiaries, American Natural Energy Corporation, Bradmar Petroleum Corporation, Edwards & Leach Oil Company and Boomer Marketing Corporation, and their proportionate share of the assets, liabilities, revenues and costs and expenses of oil and gas limited partnerships in which they act as general partner.
(1) Includes the Bradmar acquisition, which was consummated March 18, 1992. See Note 2 of Notes to Consolidated Financial Statements. (2) Includes the JMC acquisition, which was consummated November 14, 1994. See Note 2 of Notes to Consolidated Financial Statements. (3) Includes $2.4 million of costs related to the merger with ANEC as discussed in Note 2 of Notes to Consolidated Financial Statements. (4) Includes a loss from discontinued operations of $681,142 ($.13 per share) in 1992. Includes a loss from an extraordinary item of $510,000, net of taxes,($.05 per share) associated with the early extinguishment of debt in 1993 and a gain from an extrordinary item of $1,051,760 ($.09 per share) associated with the extinguishment of a long-term obligation in 1994. Also includes the cumulative effect of adopting SFAS 109, "Accounting For Income Taxes," the effect of which was to increase net income by $425,000 ($.04 per share) in 1993. See Notes 1, 12 and 13 of Notes to Consolidated Financial Statements. (5) Includes non-recourse debt and the Stock Warrant Purchase Obligation, including $2.2 million in 1993 which was reclassified to contingencies. See "Management's Discussion and Analysis of Financial Condition and Results of Operations --- Liquidity and Capital Resources" and Notes 4 and 5 of Notes to Consolidated Financial Statements of the Company.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
On July 19, 1994, Alexander Energy Corporation completed the Merger with American Natural Energy Corporation ("ANEC"). The Merger was accounted for under the pooling of interests method of accounting. Accordingly, the Merger has been given retroactive effect and the Company's financial statements for periods prior to the merger represent the combined financial statements of the previously separate entities adjusted to conform ANEC's accounting policies to those used by the Company. The recurring adjustments affecting 1992, 1993 and 1994 consisted principally of conforming ANEC's revenue recognition policy related to gas balancing and overhead reimbursements on Company operated properties and amortization of oil and gas properties and equipment.
RESULTS OF OPERATIONS
Total Revenues; Oil and Gas Sales. Total revenues decreased for 1994 compared to 1993. The decrease in total revenues consisted of decreased oil and natural gas sales and a nonrecurring item in other revenues in 1993 of approximately $1.25 million from the proceeds of settlement of a lawsuit. The decreased oil and natural gas sales are attributable to higher production volumes for natural gas as a result of the wells drilled during 1994, offset by lower product prices for both oil and natural gas.
Oil revenues decreased by 28% due to a 21% decrease in production quantities and an 9% decrease in the average price per Bbl of production for the year ended December 31, 1994 as compared to 1993. Natural gas revenues increased by 8% due to a 27% increase in production quantities, offset by a 15% decrease in the average price per Mcf of natural gas produced for the year ended December 31, 1994 as compared to 1993.
Total revenues increased for 1993 compared to 1992. The increase in total revenues consisted of increased oil and natural gas sales and a nonrecurring item in other revenues of approximately $1.25 million from the settlement of a lawsuit. The increased oil and natural gas sales are attributable to higher production volumes for oil and natural gas as a result of the Bradmar acquisition and new wells drilled in 1993. Oil revenues increased by 20% due to a 32% increase in production quantities and a 9% decrease in the average price per Bbl of production for the year ended December 31, 1993 as compared to 1992. Natural gas revenues increased by 42% due to a 20% increase in production quantities and a 18% increase in the average price per Mcf of natural gas produced for the year ended December 31, 1993 as compared to 1992.
During the first and second quarters of 1992, the Company entered into futures contracts to hedge the market risk caused by fluctuations in the price of crude oil and natural gas. Approximately 23% of the Company's monthly natural gas production and approximately 53% of the Company's monthly oil production were subject to these hedges. The effect of these hedges for the year ended December 31, 1992 was to reduce oil and natural gas sales by approximately $147,000 and $238,000, respectively, representing a reduction to the average price per Bbl and Mcf of $.69 and $.04, respectively. As of December 31, 1992, all future contracts had been settled.
Well Operator and Management Fees. Well operator and management fees remained fairly constant for the year ended December 31, 1994 compared to the same period in 1993. Included in the management fees were reimbursements of overhead expense of $10,000 per month from each of the AEJH 1987 and AEJH 1989 Limited Partnerships and an average of $4,750 per month for six months from the AEJH 1987-A Limited Partnership, which ceased operations during mid 1994.
Well operator and management fees remained fairly constant for the year ended December 31, 1993 compared to the same period in 1992. Included in the management fees were reimbursements of overhead expense of $10,000 per month from each of the AEJH 1987 and AEJH 1989 Limited Partnerships and an average of $6,000 per month from the AEJH 1987-A Limited Partnership.
Interest and Other Revenues. The increase in interest and other revenue (excluding the settlement of a lawsuit of approximately $1.25 million in 1993) during the year December 31, 1994 compared to 1993 resulted from gains on the sale of real estate and the settlement of a take-or-pay contract recorded as deferred revenue in 1993.
The increase in interest and other revenue during the year December 31, 1993 compared to 1992 resulted from the Company's settlement of a lawsuit over the prices received by Bradmar under certain gas contracts for which the Company received net proceeds of approximately $1.25 million.
Oil and Gas Prices. Oil prices received by the Company decreased 9% during 1994, resulting in an average price of $15.44 per Bbl compared to the average price per Bbl of $16.99 for 1993. Revenues and operating results for future periods will continue to be impacted by price fluctuations which are largely influenced by market conditions and the quantity of the oil sold by OPEC.
During 1994, the Company experienced a decrease in natural gas prices. In recent years, the Company has sold a substantial portion of its natural gas under short-term (typically month-to-month) contracts. Natural gas prices received by the Company decreased 15% during 1994, resulting in an average price of $1.73 per Mcf compared to an average price per Mcf of $2.04 for 1993. During the first quarter of 1995, the Company received a lower average price for natural gas produced than that received in the corresponding period in 1994. While the Company anticipates a slight increase in price for April 1995 contracts from that received in the first quarter of 1995, there can be no assurances that this will occur. Future sales prices will be dependent upon the future supply and demand of natural gas in the market and the quantities of gas sold under short-term contracts as opposed to quantities sold under long-term contracts, which currently command higher prices.
Oil prices received by the Company decreased 9% during 1993, resulting in an average price of $16.99 per Bbl compared to the average price per Bbl of $18.70 for 1992. Average gas price received by the Company during 1993 was $2.04 per Mcf, up 18% compared to an average gas price received in 1992 of $1.73 per Mcf.
Oil and Gas Production. Production and average prices received per Bbl and Mcf for each of the last three years are as follows:
Oil and natural gas production volumes for 1994 on an Mcf equivalent (Mcfe) basis exceeded such volumes for 1993 by 17% and oil and natural gas production volumes for 1993 on an Mcfe equivalent basis exceeded such volumes for 1992 by 23%. These increases in production were from participation in new wells drilled in 1994 and 1993 through the Company and the AEJH 1985 and AEJH 1989 Limited Partnerships and from recompletions in the Cotton Valley properties in 1994 by the Company. Additionally, the merger between Bradmar and the Company during March 1992 increased the production volumes for each of the three years in the period ended December 31, 1994. The JMC Acquisition also increased production volumes after closing in mid-November 1994. Although the Company experienced some curtailments of gas production, these curtailments have not been material. The curtailments were primarily attributable to excess supply and price competitiveness with oil. There can be no assurance that the Company will not experience future curtailments.
Oil and natural gas production volumes for the year ended December 31, 1995 are expected to be higher than those for 1994. This expected increase in production is forecast from new wells to be drilled in 1995 through the Company and the AEJH 1985 and AEJH 1989 Limited Partnerships, from additional production attributable to properties in the JMC Acquisition completed in mid November 1994 and from additional production attributable to well recompletions performed during 1994 on the Cotton Valley properties.
Total Expenses; Oil and Gas Operating Expenses. Total costs and expenses increased for 1994 compared to 1993 due in part to nonrecurring costs of $2.4 million for expenses associated with the ANEC merger and $734,000 related to costs of settlement of the ANEC lawsuit. Oil and gas operating expenses increased for 1994 compared to 1993, due to additional operating expenses attributable to a greater number of producing wells, which were drilled and completed during 1994 and the latter part of 1993 and due to workover costs performed on certain properties in 1994. Oil and gas operating expenses continue to decrease on an Mcfe basis to $.65 for 1994, compared to $.66 per Mcfe for 1993 and $.71 per Mcfe for 1992.
Oil and gas operating expenses increased for 1993 compared to 1992, due to additional operating expenses and increased gross production tax attributable to a greater number of producing wells resulting from the Bradmar acquisition and increased gross production taxes resulting from higher gas prices.
Amortization and Depreciation. The oil and gas property amortization and depreciation rate per dollar of oil and gas sales for 1994 increased to $.41 compared to $.32 for 1993. The increased rate for 1994 was due to the decreased estimated future gross revenues resulting from lower product prices in 1994. The amortization and depreciation rates for future periods will increase or decrease corresponding with the fluctuations in oil and gas prices, reserve volumes and production.
The oil and gas property amortization and depreciation rate per dollar of oil and gas sales for 1993 decreased to $.32 compared to $.33 for 1992. The decreased rate for 1993 was due to the increased estimated future gross revenues resulting from an increase in product price for natural gas, from the Bradmar acquisition, relative to the acquisition cost, and the net extensions, discoveries and other reserve additions during 1993.
General and Administrative Expenses. General and administrative expenses increased for 1994 compared to 1993. This increase was primarily related to management bonuses and increased personnel costs associated with the Company's growth. Well operator and management fees offset 65% of net general and administrative expenses during 1994 compared to 69% during 1993.
General and administrative expenses increased for 1993 compared to 1992. This increase related to increased personnel costs from the Bradmar acquisition and staff and management bonuses. Well operator and management fees offset 69% of net general and administrative expenses during 1993 compared to 82% during 1992. This decrease was due in part to the acquisition of the limited partner's interest in the AEER 1985 Limited Partnership in June 1993 and the related reduction of well operator fees collected from this third party.
Interest Expense. Interest expense increased for 1994 compared to 1993 due to an increase in the outstanding borrowings associated with property development and the JMC Acquisition. The Company completed the negotiation of a new credit facility during the fourth quarter which provides for a revolving line of credit with a borrowing base of $52 million. At December 31, 1994, all outstanding borrowings under this facility were based on the LIBOR rate and the applicable margin, an aggregate rate of 7.625%.
Interest expense decreased for 1993 compared to 1992 due to the reduction of outstanding borrowings following the application of proceeds from the Secondary Public Offering in March 1993.
Nonrecurring Merger Expenses. In connection with the Merger between the Company and ANEC, the Company incurred nonrecurring charges to operations in 1994 of $2.4 million. These costs include legal, accounting, investment banking, printing and other costs.
Litigation Settlement. In the fourth quarter of 1994, in an effort to resolve ANEC's litigation with various parties which had been ongoing since 1992, the Company acquired certain creditor claims against the operator of a well in which ANEC had an interest and agreed to mediation with the primary plaintiffs of the outstanding litigation. Although management believed its actions against the well operator were meritorious and believed the counterclaims of this party were without merit, after having mediated this matter in December 1994, management of the Company believe it was in the Company's best interest to resolve such litigation and terminate the costs associated therewith. Accordingly, in late December 1994, the Company agreed to a negotiated settlement, the effect of which resulted in a charge to 1994 operations, including legal fees, of approximately $734,000.
Taxes. As a result of the Company's and ANEC's secondary public offerings in 1993, both entities had an ownership change pursuant to Section 382 of the Internal Revenue Code. Accordingly, in 1994, the Company is providing income taxes at near statutory rates after considering permanent differences related primarily to nondeductible merger costs and the extraordinary gain on extinguishment of a long-term obligation.
In 1993, the Company sustained a nonrecurring non-cash charge to operations of $1.2 million due to an increase in the valuation allowance associated with the change in ownership in the first quarter of 1993 discussed above. The Company also recorded a deferred tax provision of approximately $1.1 million on pre-tax income of $4.9 million, representing an effective rate of 23%. The lower tax rate for 1993 was primarily attributable to the reduction of a valuation allowance previously established on pre-acquisition net operating loss carryforwards of ANEC.
In February 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 109, "Accounting for Income Taxes" ("SFAS 109"). The Company adopted SFAS 109 on January 1, 1993. Among other changes, SFAS 109 relaxed the recognition and measurement criteria for deferred tax assets and alternative minimum tax from that provided for under its previous method of accounting for income taxes under Statement of Financial Accounting Standards No. 96 ("SFAS 96"). Adoption of this standard resulted in the elimination of deferred income taxes payable of $425,000, related entirely to alternative minimum tax, which is reflected in the 1993 statement of operations as the cumulative effect of a change in accounting principle.
The Company's provision for taxes in 1992 represents state income taxes for which net operating losses were not available to eliminate the need for a provision.
LIQUIDITY AND CAPITAL RESOURCES
General. The Company's capital requirements relate primarily to exploitation, development, exploration and acquisition activities. In general, because the Company's oil and gas reserves are depleted by production, the success of its business strategy is dependent upon a continuous exploitation, development, exploration and acquisition program.
Historically, the Company has funded its capital requirements through cash flow from operations, bank borrowings, various carried interest arrangements (whereby other parties paid a portion of the Company's share of costs) and equity sales. The Company and ANEC used the net proceeds from the Secondary Public Offerings in 1993 to repay existing indebtedness and the Series B preferred stock. During 1994, the Company entered into a new credit facility with a bank to provide additional borrowing capacity under a revolving line of credit. See LIQUIDITY AND CAPITAL RESOURCES -- Long-Term Debt.
The Company's capital resources consist primarily of cash flow from operations and available borrowing capacity under the New Credit Facility. Although it has no specific plans to do so, the Company may supplement its working capital through the establishment of new financing arrangements or the sale of certain properties.
Cash Flows. In 1994, the Company's cash provided by operating activities was $1.5 million compared to $12.1 million for the year ended December 31, 1993. This decrease was primarily attributable to $3.2 million of nonrecurring expenses associated with the ANEC merger and the settlement of ANEC litigation, the nonrecurence of the 1993 $1.25 million gas contract settlement proceeds and the net change in assets and liabilities resulting from operating activities of $4.8 million. The $4.8 million net change in assets and liabilities resulting from operating activities in 1994 is the result of reduced drilling activities, the availability of additional borrowing capacity associated with the new credit facility and the nonrecurrence of a natural gas prepayment agreement at December 31, 1994, compared with December 31, 1993, all of which caused a reduction in accounts payable, oil and gas proceeds due others and other liabilities at December 31, 1994 compared with the related balances at December 31, 1993. At December 31, 1994, the Company has a $3.5 million gas balancing liability attributable to 2.5 Bcf of natural gas production in excess of the Company's entitled natural gas volumes. The majority of these excess sales are from properties that have gas balancing agreements which provide for recoupments by the underproduced owners from 25% of volumes attributable to the Company's interest. At December 31, 1994, approximately $912,000 was included in current liabilities associated with such excess sales liability.
The Company's cash flow provided by operating activities in 1993 was $12.1 million compared to $4.7 million in 1992. This increase was primarily attributable to the $1.25 million nonrecurring gas contract settlement in 1993 and the change in assets and liabilities resulting from operating activities of $1.9 million.
Net cash used by investing activities in 1994 increased approximately $15.3 million to $32.3 million from $17.0 million in 1993. Additions to oil and gas properties increased by approximately $18.1 million to $36.0 million due to the JMC acquisition of $18.2 million and the continued redirection of activities toward exploration and development of reserves after completing the Secondary Public Offerings in 1993. The acquisition added 25 billion cubic feet of natural gas reserves to the Company's asset base. The properties acquired are located in the Arkoma Basin in Oklahoma and Arkansas. During 1994, the Company also sold its interest in the MFS Properties for approximately $3.2 million which were acquired in 1990 for $3.0 million.
Net cash used by investing activities in 1993 increased by $11.5 million to $17.0 million in 1993 compared to $5.5 million in 1992, primarily attributable to the increase in additions to oil and gas properties of $14.5 million to $17.9 million.
Net cash provided by financing activities was $30.3 million for 1994 compared to $5.3 million for 1993. Net cash provided in 1994 resulted primarily from borrowings on long-term debt of $31.0 million and the exercise of stock options which aggregated $1.0 million, partially offset by payments on long-term debt to a stockholder and others of $1.3 million.
Net cash provided by financing activities in 1993 was $5.3 million compared to $25,007 used in 1992. The cash provided in 1993 resulted primarily from borrowings on long-term debt of $18.5 million and proceeds from the sale of common stock of $13.7 million partially offset by payments on long-term debt of $26.3 million.
At December 31, 1994, the Company had a working capital deficit of $5.6 million and had approximately $10 million available under its revolving line of credit.
Long Term Debt. The Company negotiated a new credit facility (the "Credit Agreement") with a bank in the fourth quarter of 1994 which provides for a revolving line of credit. The borrowing base on the revolving line of credit was $52 million at December 31, 1994. The borrowing base, which principally relates to the Company's oil and gas reserve base, is subject to a semi-annual redetermination each April and October until January 1, 1997, at which time the borrowing base is reduced quarterly by 1/16th through December 31, 2000. In addition to the foregoing semi-annual redeterminations, the lender has the right, at its discretion, to redetermine the borrowing base, subject to certain limitations, at any time until the stated maturity of December 31, 2000.
Under the terms of the Credit Agreement, outstanding borrowings bear interest based upon three variable indices plus applicable margins. The Company has the ability to choose the index the rate will be based on and can fix the rate for a period of up to six months. At December 31, 1994, all outstanding borrowings under the line bear interest based upon the London Interbank Offering Rate plus the applicable margin (aggregate rate of 7.625%) and is fixed until April 21, 1995. The Credit Agreement requires the Company to pay a commitment fee of .25% per annum on the average daily balance of unused borrowings.
Borrowings under the Credit Agreement are unsecured with a negative pledge, as specified in the Credit Agreement, on all oil and gas properties. Terms of the Credit Agreement include, among other things, requirements to maintain minimum amounts of tangible net worth (as defined) and a minimum ratio of current assets to current liabilities; and limitations on investments, indebtedness, capital expenditures, sales of oil and gas properties and equipment, liquidations, mergers, consolidations, acquisitions, gas balancing and gas prepayment liabilities and the payment of dividends on common stock.
Future Events. On March 14, 1995, the Company announced that its Board of Directors approved an agreement to enter into negotiations with Abraxas Petroleum Corporation ("Abraxas") with respect to the combination of the two companies. Under the terms of the agreement, the Company and Abraxas would have 45 days to complete their due diligence investigations and attempt to reach a definitive agreement on the terms of a transaction. The Company will incur fees for legal, accounting, investment banking and other costs related to the due diligence process. In the event a merger is accomplished, costs as mentioned above will be substantially increased.
Since the Company is pursuing due diligence and has experienced a lower product price for natural gas in the past several months, the Company has focused its current efforts on the due diligence process. The Company has budgeted approximately $11 million for development of proved undeveloped locations in 1995. While these projects may be temporarily delayed due to the above mentioned factors, the Company can easily accomplish this development program in the last half of 1995 after a determination is made whether or not to pursue the combination.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders Alexander Energy Corporation
We have audited the accompanying consolidated balance sheet of Alexander Energy Corporation as of December 31, 1994, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the 1994 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Alexander Energy Corporation at December 31, 1994 and the consolidated results of its operations and its cash flows for the year then ended, in conformity with generally accepted accounting principles.
We previously audited and reported on the consolidated balance sheet as of December 31, 1993 and the related consolidated statements of operations, stockholders' equity, and cash flows of Alexander Energy Corporation for the years ended December 31, 1992 and 1993, prior to their restatement for the 1994 pooling of interests as described in Note 2. The contribution of Alexander Energy Corporation to total assets, revenues, and net income or loss represented 77%, 65% and $394,212 of net income of the respective 1992 restated totals and 71%, 65% and 50% of the respective 1993 restated totals. Financial statements of the other pooled company included in the 1992 and 1993 restated consolidated statements were audited and reported on separately by other auditors. We also have audited, as to combination only, the accompanying consolidated balance sheet as of December 31, 1993 and the related consolidated statements of operations, stockholders' equity and cash flows for the years ended December 31, 1992 and 1993, after restatement for the 1994 pooling of interests; in our opinion, such consolidated financial statements have been properly combined on the basis described in Note 2 to the consolidated financial statements.
As discussed in Note 1 to the consolidated financial statements, in 1993 the Company changed its method of accounting for income taxes.
ERNST & YOUNG LLP Oklahoma City, Oklahoma March 24, 1995
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders American Natural Energy Corporation
We have audited the consolidated balance sheets of American Natural Energy Corporation and Subsidiaries as of December 31, 1993 and 1992 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years ended December 31, 1993 and 1992. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of American Natural Energy Corporation and Subsidiaries as of December 31, 1993 and 1992 and the consolidated results of their operations and their cash flows for the years ended December 31, 1993 and 1992, in conformity with generally accepted accounting principles.
As discussed in Notes 2 and 4, the Company changed its method of accounting for its oil and gas properties and income taxes.
COOPERS & LYBRAND
Tulsa, Oklahoma February 22, 1994
ALEXANDER ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1993 AND 1994 (NOTES 1 AND 2)
See accompanying notes.
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (NOTES 1 AND 2)
See accompanying notes.
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994 (NOTES 1, 2 AND 8)
See accompanying notes.
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (NOTES 1 AND 2) (CONTINUED ON NEXT PAGE)
ALEXANDER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(CONTINUED)
SUPPLEMENTAL INFORMATION:
Interest paid amounted to $2,584,462, $1,701,127 and $2,174,996 for the years ended December 31, 1992, 1993 and 1994, respectively.
In connection with certain sales of property and equipment, the Company eliminated gas balancing receivables and payables of $312,362 and $889,674, respectively in 1992. In 1993, the Company reclassified to oil and gas properties, $1,680,000 of gas balancing payables recognized in the preliminary Bradmar purchase price allocation.
In 1992, ANEC issued common stock in exchange for cancellation of $183,000 indebtedness and received $183,000 of common stock in connection with the disposition of certain assets. ANEC also converted $1,375,000 of preferred stock to common stock and exchanged oil and gas properties for the discharge of $250,760 of accounts payable.
In December 1993, ANEC also recognized a stock subscription receivable of $645,000 in connection with the issuance of common stock paid for in cash in January 1994.
During 1992, the Company declared a preferred stock dividend of $50,000 included in current liabilities at December 31, 1992.
In 1992, in connection with the Bradmar acquisition, the Company assumed liabilities and issued common stock aggregating $11 million and $3.4 million, respectively.
See accompanying notes.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation - The consolidated financial statements include the accounts of Alexander Energy Corporation (the "Company"), its wholly-owned subsidiaries, American Natural Energy Corporation ("ANEC") (Note 2), Edwards & Leach Oil Company ("ELOC"), Boomer Marketing Corporation and Bradmar Petroleum Corporation ("Bradmar") and their proportionate share of the assets, liabilities, revenues and costs and expenses of oil and gas limited partnerships in which they act as general partner (Note 3). Amounts for periods prior to 1994 have been restated to give effect for the 1994 pooling of interests between the Company and ANEC as described in Note 2.
Oil and gas properties - The Company follows the full cost method of accounting for oil and gas properties prescribed by the Securities and Exchange Commission ("SEC"). Under the full cost method, all acquisition, exploration and development costs are capitalized. The Company capitalizes internal costs including: salaries and related fringe benefits of employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized internal costs were approximately $650,000, $885,000, and $1,232,000, respectively, in each of the three years in the period ended December 31, 1994.
The costs of unproved properties are excluded from costs to be amortized pending a determination of the existence of proved reserves. Such unproved properties are assessed periodically for impairment. The amount of impairment is included in the costs to be amortized.
Amortization and depreciation - Amortization of oil and gas properties is computed using a unit of revenue method based on current gross revenues from production in relation to estimated future gross revenues from production of proved oil and gas reserves (Note 11).
Depreciation of other properties and equipment is computed on the straight-line method over estimated useful lives of 3 to 40 years.
Capitalization of interest - Interest costs related to significant exploratory oil and gas wells and unproved oil and gas leases not being amortized are capitalized until such time as the properties are evaluated and transferred to the full cost amortization base. For the years ended December 31, 1992, 1993 and 1994, total interest costs amounted to $3,042,249, $2,077,890 and $2,423,496 with $13,398, $15,229 and $28,000 being capitalized, respectively.
Income taxes - In February 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 109, "Accounting for Income Taxes" ("SFAS 109"). The Company adopted SFAS 109 on January 1, 1993. Among other changes, SFAS 109 relaxed the recognition and measurement criteria for deferred tax assets and alternative minimum tax from that provided for under its previous method of accounting for income taxes under Statement of Financial Accounting Standards No. 96 ("SFAS 96"). Adoption of this standard resulted in the elimination of deferred income taxes payable of $425,000, related entirely to alternative minimum tax, which is reflected in the 1993 statement of operations as the cumulative effect of a change in accounting principle.
Under SFAS 96 and SFAS 109, deferred income taxes are provided on the tax effect of presently existing temporary differences, net of operating loss carryforwards and statutory depletion carryforwards. The tax effect is measured using the enacted marginal tax rates and laws that will be in effect when the differences and carryforwards are expected to reverse or be utilized.
Net income (loss) per common and common equivalent share - Net income (loss) per common and common equivalent share is computed on the basis of weighted average shares of common stock, stock options and warrants outstanding during each period, as applicable. As discussed in Note 8, in 1992 ANEC converted 1,375 shares of Series A Preferred Stock into 458,333 shares of ANEC's common stock (742,499 shares of the Company's common stock). Assuming conversion had occurred at January 1, 1992, the Company's income before discontinued operations and net loss would have been $.08 and $(.03) per common and common equivalent share, respectively, for the year ended December 31, 1992.
Gas balancing and natural gas prepayments - The Company records gas sales on the entitlement method, recognizing only its net share of all production as revenues. Any amount received in excess of the Company's revenue interest is recorded as a gas balancing liability. The Company has also received non-interest bearing prepayments on future natural gas production which provide for recoupment, most of which are refundable upon the
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
earlier of the end of the productive life of each well or expiration of the gas purchase contract. The natural gas prepayments will be recognized as revenue when, and if, the gas is delivered. In allocating the purchase price of Bradmar in 1992, the gas balancing and gas prepayments were discounted at 8% to an estimated fair value. At December 31, 1993 and 1994, these liabilities have been presented in the accompanying consolidated balance sheet net of discount aggregating $726,000 and $530,000, respectively. The portion of the gas balancing and natural gas prepayment liabilities that may be contractually recouped during the next fiscal year is recorded as due within one year in the accompanying balance sheets. As of December 31, 1993 and 1994 the Company has gas balancing and natural gas prepayment liabilities aggregating $4,652,000 and $4,736,000, respectively, of which $638,000 and $1,035,000 are classified as due within one year.
Futures contracts - In 1992, the Company entered into futures contracts to hedge the market risk caused by fluctuations in the price of crude oil and natural gas. These contracts involved the cash settlement of the differentials between fixed and floating crude oil and natural gas prices. The differentials to be paid or received were accrued and recognized as current-period adjustments to crude oil and natural gas sales.
The effect of these hedges for 1992 was to reduce oil and natural gas sales as received at the wellhead by approximately $147,000 and $238,000, respectively, representing a reduction to the average price per barrel and Mcf of $.69 and $.04, respectively from the price received at the wellhead. As of December 31, 1993 and 1994, the Company had no outstanding commitments with regard to futures contracts.
Cash equivalents - Temporary investments with a maturity at the date of acquisition of 90 days or less are considered to be cash equivalents.
Credit and market risk - The Company conducts the majority of its operations in the states of Oklahoma, Texas and Arkansas and operates exclusively in the oil and natural gas industry. The Company's joint interest and oil and gas sales receivables are generally unsecured; however, the Company has not experienced any significant losses in prior years and is not aware of any significant uncollectible accounts at December 31, 1994.
2. BUSINESS COMBINATIONS
On March 19, 1992, the Company merged with Bradmar whereby each outstanding share of Bradmar common stock (approximately 1,890,000 shares) was exchanged for $2.57 in cash (an aggregate of $4.9 million) and .48 share of the Company's common stock (906,440 shares) for an aggregate purchase price of approximately $8.3 million, excluding associated fees and expenses. This transaction has been accounted for under the purchase method of accounting.
In July 1994, the Company acquired ANEC, an Oklahoma corporation based in Tulsa, Oklahoma, in a merger (the "Merger") accounted for as a pooling of interests. Accordingly, the Merger has been given retroactive effect and the Company's financial statements for periods prior to the Merger represent the combined financial statements of the previously separate entities adjusted to conform ANEC's accounting policies to those used by the Company. ANEC became a wholly owned subsidiary of the Company and each issued and outstanding share of ANEC's common stock was converted into the right to receive 1.62 shares of the Company's common stock ("Common Stock"). In addition, the Company agreed to assume all outstanding options granted under the stock option plans maintained by ANEC. As a result of the transaction, the Company issued approximately 5.8 million shares of Company common stock and reserved approximately 250,000 shares of common stock for issuance upon exercise of ANEC's options. The Company also reserved approximately 158,000 shares of its common stock for issuance pursuant to a warrant held by the underwriters of ANEC's September 1993 public stock offering.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Separate and combined results of Alexander Energy Corporation and ANEC prior to the Merger are as follows (in thousands):
The adjustments consist principally of conforming ANEC's policies to the policies used by the Company. The conformed policies include revenue recognition related to gas balancing, amortization of oil and gas properties and equipment, income taxes and overhead reimbursements on Company operated properties. The Company also reversed the quasi-reorganization effected by ANEC in 1992 to comply with the pooling of interests method of accounting. The cumulative effect of these conforming adjustments increased consolidated accumulated deficit at December 31, 1991 by approximately $950,000.
In connection with the Merger, the Company incurred nonrecurring charges to operations in 1994 of $2.4 million related to the combination of the Company and ANEC. These costs include legal, accounting, investment banking, printing and other costs.
In November 1994, the Company acquired certain producing gas properties, located principally in Oklahoma and Arkansas, from JMC Exploration, Inc. (the "JMC Acquisition") for a net purchase price of approximately $18.2 million, including the assumption of a net gas balancing liability of $320,000. The operations of the JMC Acquisition have been included in the accompanying statements of operations and cash flows beginning November 15, 1994.
The following unaudited pro forma combined data gives effect to the JMC Acquisition as if such transactions had been consummated as of January 1, 1993 and 1994. The pro forma information is based on the historical financial statements of the Company and the JMC Acquisition, giving effect to the transaction under the purchase method of accounting. The unaudited pro forma combined data are presented for illustrative purposes and are not necessarily indicative of the actual results that would have occurred had the acquisition been consummated as of January 1, 1993 or 1994, respectively, or of future results of the combined operations. The data reflect adjustments for (1) amortization and depreciation of the JMC Acquisition's oil and gas properties, (2) incremental general and administrative expenses of the JMC Acquisition, (3) incremental interest expense resulting from the borrowings on the new credit facility used to fund the cash requirements of the acquisition, and (4) certain other pro forma adjustments.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. TRANSACTIONS WITH RELATED PARTIES
In June 1988, the Chief Executive Officer purchased 200,000 shares of the Company's treasury stock for a sum aggregating $322,500. In connection with this transaction, the Company advanced the Chief Executive Officer $77,500 bearing interest at 10% repayable in 10 annual installments. The remaining balance of this advance aggregated $52,801 at December 31, 1993. In November 1994, the Board of Directors approved a resolution to forgive the outstanding receivable from the Chief Executive Officer and also refund the principle and interest previously paid to the Company, resulting in an aggregate charge to 1994 operations of approximately $190,000.
Prior to the Merger with the Company, ANEC made certain unsecured and non-interest bearing advances to its President. The outstanding balance at December 31, 1993 was $50,000. Subsequent to the Merger, ANEC's President resigned and repaid the outstanding balance due to the Company.
The Company and ELOC have interests in three limited partnerships engaged in oil and gas activities. The Company or ELOC acts as general partner of these partnerships and arranges for the exploration, development and subsequent operations of the partnerships' properties. In return, the Company and ELOC are entitled to receive management fees, reimbursement for administrative overhead and share in the partnerships' revenues and costs and expenses according to the respective partnership agreements.
During June 1993, the Company acquired the limited partner's interest in an oil and gas partnership for which the Company served as the general partner. The purchase price of this acquisition was $1,350,000 and was accounted for under the purchase method of accounting. The results of the acquisition is included in the results of operations of the Company since the date of the acquisition.
During each of the three years in the period ended December 31, 1994, the Company sold approximately 28%, 20% and 24%, respectively, of its oil production through an entity (IEM, Ltd.) in which the Company owned a limited partner interest recorded on the equity method (Note 9). Net distributable income of IEM, Ltd. was allocated 60% to the limited partners and 40% to the general partner. For the two years ended December 31, 1993 and the eight months ended August 31, 1994, the Company received 100% of the amount allocable to the limited partners. Effective August 31, 1994, the Company terminated its marketing arrangement with IEM and thus, withdrew as a limited partner. As a result, the indirect marketing fees and the Company's equity interests in IEM's operating profit or loss ceased as of August 31, 1994. The Company received the highest posted price for all such production, an indirect marketing fee from the ultimate purchaser and a percentage of operating profit of IEM, if any. In 1992, 1993 and the eight-month period ended August 31, 1994, the Company recorded pass-through marketing fees of $80,000, $96,000 and $96,000, respectively, and operating profits (losses) of $46,000, $1,500 and $(9,700), respectively. At December 31, 1993 and 1994 the Company had an undistributed net operating profit receivable associated with this interest of approximately $84,000, and a marketing fee receivable of $96,000 at December 31, 1993 (none at December 31, 1994).
The Company also purchases certain well operating chemicals and stimulants from another entity in which the Company owns a limited partner interest. In 1992, 1993 and 1994, oil and gas operating expenses and property development costs include approximately $100,000, $521,000 and $726,000, respectively, related to purchases from this related party. At December 31, 1994 the Company has a 7.5% note receivable from this related party of approximately $200,000 ($240,000 in 1993) and has an account payable to this related party of approximately $92,419 ($199,452 in 1993).
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As a requirement of the acquisition of Bradmar, the Company entered into consulting/non-compete agreements with two former officers and directors of Bradmar, one of which presently serves on the board of directors of the Company. The agreements require total payments of a minimum $1,320,000 (for which the Company has recorded a liability at the discounted present value) to be paid in monthly payments of $36,667 over a thirty-six month period from the date of the acquisition. During 1992, 1993 and 1994, the Company paid $348,376, $440,000 and $440,000, respectively, related to these agreements and at December 31, 1993 and 1994 has included $440,000 and $91,624 in current liabilities due to such related parties.
4. LONG-TERM DEBT
Long-term debt consists of:
-------------------- (A) The Company negotiated a new credit facility (the "Credit Agreement") with a bank in the fourth quarter of 1994 which provides for a revolving line of credit. The borrowing base on the revolving line of credit was $52 million at December 31, 1994. The borrowing base, which principally relates to the Company's oil and gas reserve base, is subject to a semi-annual redetermination each April and October until January 1, 1997, at which time the borrowing base is reduced quarterly by 1/16th through December 31, 2000. In addition to the foregoing semi-annual redeterminations, the lender has the right, at its discretion, to redetermine the borrowing base, subject to certain limitations, at any time until the stated maturity of December 31, 2000.
Under the terms of the Credit Agreement, outstanding borrowings bear interest based upon three variable indices plus applicable margins. The Company has the ability to choose the index the rate will be based on and can fix the rate for a period of up to six months. At December 31, 1994, all outstanding borrowings under the line bear interest based upon the one-month London Interbank Offering Rate plus the applicable margin (aggregate rate of 7.625%) and is fixed until April 21, 1995. The Credit Agreement requires the Company to pay a commitment fee of .25% per annum on the average daily balance of unused borrowings.
Borrowings under the Credit Agreement are unsecured with a negative pledge, as specified in the Credit Agreement, on all oil and gas properties. Terms of the Credit Agreement include, among other things, requirements to maintain minimum amounts of tangible net worth (as defined) and a minimum ratio of current assets to current liabilities; and limitations on investments, indebtedness, capital expenditures, sales of oil and gas properties and equipment, liquidations, mergers, consolidations, acquisitions, gas balancing and gas prepayment liabilities and the payment of dividends on common stock.
(B) The Company and ANEC each had outstanding borrowings under secured revolving credit facilities (replaced by the unsecured credit facility discussed in (A) above).
(C) In June 1988, the Company entered into an agreement with a stockholder whereby the Company issued 10% unsecured notes in the amount of $5,000,000. This note agreement requires semi-annual interest payments, with annual principal payments of $1,000,000 beginning in June 1994 and continuing through 1998. This note agreement requires principal prepayments if less than 50% of the Company's consolidated cash flow is not
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
expended on indebtedness, as defined, and capital expenditures. It also limits the sale or disposition of subsidiaries, partnerships or joint ventures, the sale of Company assets, the incurrence of additional indebtedness, declarations of dividends and requires the Company to maintain cash flow each fiscal year equal to the greater of a) 200% of the aggregate consolidated principal payments during such fiscal year, b) 200% of the aggregate consolidated principal payments during the next succeeding fiscal year, or c) discounted future net revenues equal to 225% of the aggregate consolidated debt (as defined).
As of December 31, 1994, long-term debt, which excludes the non-recourse debt maturities discussed in Note 5, maturing during the subsequent five years and thereafter is as follows (based on the Company's borrowing base and outstanding borrowings at December 31, 1994): 1995 - $1,016,253; 1996 - $1,031,348: 1997 - $4,016,750; 1998 - $14,012,140; 1999 and thereafter - $26,528,042.
5. NON-RECOURSE DEBT
In 1989, AEJH 1989 Limited Partnership ("AEJH 1989"), for which the Company serves as general partner, entered into an agreement with a stockholder of the Company (and limited partner of AEJH 1989), whereby AEJH 1989 issued secured 10 1/2% notes payable in the amount of $2,185,276 ($1,092,638 net to the Company's interest at the date of issuance) to acquire leasehold interests in a group of producing oil and gas properties. These notes require monthly principal and interest payments equal to 80.75% of net proceeds, as defined, from the producing oil and gas properties. The lender may recover the outstanding balance on the notes only from proceeds from the oil and gas properties of AEJH 1989.
Inasmuch as the future payments on these notes will be paid only from net proceeds from these producing oil and gas properties, no amounts are included in current portion of long-term debt in the accompanying balance sheets.
6. INCOME TAXES
A reconciliation of the Company's income tax provision from continuing operations and the amount computed by applying the statutory federal income tax rate of 35% (34% for 1992) to income (loss) before income taxes, discontinued operations, extraordinary items and cumulative effect of change in accounting is as follows:
(1) Provision for deferred income taxes computed under SFAS 109. Includes $2,121,000 and $210,000 in 1993 for federal and state income taxes, respectively.
(2) Provision for deferred income taxes computed under SFAS 96 in 1992.
(3) The 1993 change relates primarily to the nonrecurring change in ownership.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred tax assets and liabilities under SFAS 109 consist of the following at December 31:
In connection with the Offering in March 1993 (Note 8), the Company had an ownership change pursuant to Section 382 of the Internal Revenue Code. The Company sustained a nonrecurring non-cash charge to operations of approximately $1.2 million during the three months ended March 31, 1993 due to an increase in the valuation allowance. The increase in the valuation allowance represents the effects of the annual limitations on the utilization of net operating loss carryforwards resulting from the change in ownership. In addition, ANEC had an ownership change in September 1993 as a result of its 1993 offering (Note 2), which resulted in a limitation on the utilization of its net operating loss carryforwards.
At December 31, 1994, the Company has federal income tax net operating loss ("NOL") carryforwards of approximately $29,400,000 which begin to expire in 1996. For federal income tax purposes, the Company also has investment tax credit (after 35% reduction required under the Tax Reform Act of 1986) and statutory depletion carryforwards of approximately $201,000 and $3,630,000, respectively. At December 31, 1994, the federal income tax NOL includes pre-acquisition NOL carryforwards of ELOC, Bradmar and ANEC of approximately $3,000,000, $1,500,000 and $4,750,000, which begin to expire in 1996, 2005 and 2002, respectively.
7. COMMITMENTS AND CONTINGENCIES
In December 1994, the Company executed employment agreements, special severance agreements and implemented a corporate separation policy for its management, technical support staff and other employees, respectively, which become effective upon a change in control of ownership, as defined. As of December 31, 1994, severance benefits under such agreements, assuming a change in control, would aggregate approximately $4.7 million. A provision for these benefits will not be made until a change in control is probable. See Note 14.
The Company is involved in various legal actions arising in the normal course of business. In the opinion of management, the Company's liability, if any, in these pending actions would not have a material effect on the Company's financial position or the results of operations.
8. PREFERRED AND COMMON STOCK
In April 1990, stockholders authorized the Board of Directors of the Company to issue up to 2,000,000 shares of $.01 par value preferred stock with preferences, qualifications, limitations and designations as deemed appropriate.
On May 30, 1990 the Company issued 100,000 shares of 5% Series A cumulative convertible preferred stock, $.01 par value, to MWR Investments, Inc., a wholly owned subsidiary of Midwest Capital Group, Inc., ("MWR") for $1,000,000. The preferred stock was converted into common stock of the Company in March 1993 at a conversion rate of 1 share of preferred for 3.33 shares of common.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 1992, dividends of $.50 per share ($50,000 which was in arrears at December 31, 1991) and $90.00 per share ($123,632) were paid on the Company's and ANEC's Series A preferred stock, respectively. In 1993, dividends of $.50 per share ($60,273, $50,000 of which was in arrears at December 31, 1992) and $.20 per share ($26,383) were paid on the Company's Series A preferred stock and ANEC's Series B preferred stock, respectively.
In December 1994, the Board of Directors authorized the Company to reserve 300,000 shares of Series A Junior Participating Preferred Stock in connection with establishing a rights plan providing shareholders one right for each share of common stock held. Each right entitles its holder to purchase 1/100 of a share of Series A Junior Participating Preferred Stock for $25.00, subject to adjustment. The rights become exercisable and separately transferable ten business days after a) an announcement that a person has acquired or obtained the right to acquire 20% or more of the common stock or b) commencement of a tender offer that could result in a person owning 20% or more of the common stock.
If any person becomes the beneficial owner of 20% or more of the Company's common stock, each right not beneficially owned by that person entitles its holder to purchase, in lieu of Series A Junior Participating Preferred Stock, Company common stock with a value equal to twice the exercise price of the right, subject to adjustment to prevent dilution. In the event of certain merger or asset sale transactions with another party or transactions which would increase the equity ownership of a shareholder who then owned 20% or more of the Company, each right will entitle its holder to purchase a similar value of the merging or acquiring party's common stock. The rights, which have no voting power, expire on December 15, 2004. The rights may be redeemed for $.01 per right until ten business days after a person has acquired 20% or more of the common stock.
On December 31, 1992, ANEC entered into an agreement with the Series A preferred shareholders of ANEC under which such stock was converted into 458,333 shares of ANEC's common stock (742,499 shares of the Company's common stock).
On December 31, 1992, ANEC issued 133,333 shares of Series B preferred stock and 30,000 shares of ANEC's common stock (48,600 shares of the Company's common stock) for $400,000. In September 1993, ANEC redeemed such preferred stock for $400,000 out of the proceeds of a secondary public offering of equity securities.
In March 1993, the Company registered 2,990,000 shares of the Company's common stock (the "Offering"), of which the Company and a stockholder sold 2,556,667 and 433,333 shares, respectively. In conjunction with the Offering, the Company issued to the underwriters warrants to purchase 75,000 shares of common stock. The warrants are exercisable beginning March 1994 at an exercise price of $5.10 per share and expire in March 1998. The exercise price and the number of shares of common stock for which the warrants are exercisable are subject to adjustment upon the occurrence of certain dilutive events.
In September 1993, ANEC sold 1,100,000 shares of ANEC's common stock (1,782,000 shares of the Company's common stock) and received $4 million, net of underwriters commissions and costs of the offering (the "ANEC Offering"). In connection with this offering, ANEC issued purchase warrants to purchase 97,500 shares of ANEC's common stock (157,950 shares of the Company's common stock) at $5.70 per share ($3.52 for the Company's common stock), expiring in September 1998.
In April 1993, ANEC issued 139,000 shares of ANEC's common stock (225,180 shares of the Company's common stock) in connection with the acquisition of a 7.5% overriding royalty interest in ANEC's oil and gas properties in connection with the early termination of a credit agreement.
Also in April 1993, ANEC issued warrants to purchase 260,000 shares of ANEC's common stock (421,200 shares of the Company's common stock) at $3.00 per share ($1.85 for the Company's common stock), expiring in April 1996, in connection with the issuance of subordinated notes, retired in September 1993 with proceeds from the ANEC Offering. In December 1993, ANEC issued 225,000 shares of common stock (364,500 shares of the Company's common stock) upon the exercise of a like number of warrants in exchange for a stock subscription receivable of $645,000 which was collected in January 1994. The remaining 35,000 warrants at December 31, 1993 were exercised during 1994 for 56,700 shares of the Company's common stock.
The Company initially reserved 66,666 shares of its common stock for issuance to directors and key employees under a nonqualified stock option plan (which terminated in 1991, except for outstanding options at the date of termination). The plan is administered by the Compensation Committee (the "Committee") of the Board of Directors.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The exercise period of the options was determined by the Committee at the date of grant, provided the exercise period is between one and ten years from the date of grant. These options provide for accelerated vesting schedules upon a change in control, as defined (Note 14).
Information regarding the Company's nonqualified stock option plan is summarized as follows:
The Company also has reserved 133,333 shares (10,022 available for future grants at December 31, 1994) of its common stock for issuance to directors and key employees under an incentive stock option plan (the "Plan"). The Plan is administered by the Committee and, with the exception of a time period under which options can be issued, contains similar provisions to the nonqualified stock option plan.
The Company also has reserved 250,000 (130,024 available for future grants at December 31, 1994) shares of its common stock for issuance to directors and key employees under a stock option plan approved at the 1993 annual stockholders' meeting authorizing grants of both nonqualified and incentive stock options (the "1993 Plan"). The 1993 Plan is administered by the Committee and, with the exception of a time period under which options can be issued, contains similar provisions to the nonqualified and incentive stock option plans discussed above. During 1993, ANEC granted options for 51,000 shares (exercise price of $3.25 per share) of its common stock under a plan similar to the Company's 1993 Plan. As a result of the Merger, those options were converted to options to acquire shares of the Company's common stock, under the 1993 Plan.
The Company also has reserved 500,000 shares of its common stock for awards to directors and key employees under a restricted stock award plan approved at the 1993 annual stockholders' meeting (the "Award Plan"). The Award Plan is administered by the Committee. Stock is awarded, issued and held by an escrow agent until such time as a vesting period, which period is determined by the Committee, has been satisfied. Voting rights commence at the time of award. In the fourth quarter of 1993 and 1994, the Company granted 7,500 and 100,000 shares, respectively, under the Award Plan. The market value, at the award date, was $38,000 and $603,000, respectively, for the 1993
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and 1994 awards. Unearned compensation ($572,000 at December 31, 1994) is being amortized over the three year vesting period and amounted to $2,200 and $69,000 in 1993 and 1994, respectively. These awards provide for accelerated vesting schedules upon a change in control, as defined (Note 14).
At December 31, 1994, options granted under ANEC's directors stock option plan were outstanding. Such options are for 36,774 shares of the Company's common stock at prices ranging from $1.35 to $4.09 per share, and expire during 1995.
In 1993, ANEC issued options to purchase 51,000 shares of ANEC common stock (82,620 shares of the Company's common stock) to three business advisors at $3.00 per share; all of which were exercised during 1994.
In 1993, ANEC granted options to certain members of management to purchase 287,500 shares of ANEC's common stock (465,750 shares of the Company's common stock), at prices ranging from $3.25 to $5.00 per share ($2.01 to $3.09 for the Company's shares). These options provided for accelerated vesting schedules upon change in control. At December 31, 1994 options for 162,000 shares of the Company's common stock are outstanding and are exercisable at a price of $2.01 (81,000 shares) and $3.09 (81,000 shares). In 1994, immediately prior to and in connection with the Merger, options were exercised for 187,500 shares of ANEC common stock (303,750 of the Company's common stock) at prices of $5.00 and $3.25 ($2.01 and $3.09 for the Company's common stock).
9. MAJOR PURCHASERS
The Company's oil and gas production is sold under contracts with various purchasers (Note 3). Gas sales to two purchasers individually approximated 11%, 12% and 13% of total revenues, excluding well operator and management fees, for the years ended December 31,1992, 1993 and 1994, respectively.
10. OTHER REVENUES AND LITIGATION SETTLEMENT
In May 1993, the Company settled a lawsuit over the prices received by Bradmar under certain gas contracts. The Company included approximately $1.25 million of proceeds from the settlement in 1993 revenues.
In the fourth quarter of 1994, in an effort to resolve ANEC's litigation with Unit Drilling Company ("Unit") and Midwest Energy Corporation ("MEC"), the Company acquired Unit's claim against MEC and in late December, agreed to mediation with MEC. On December 22, 1994, the Company agreed to a negotiated settlement with MEC, the effect of which was a release of the Company's claim against MEC, the exchange of certain interests in oil and gas properties and a net payment to MEC of $625,000. The aggregate effect of this negotiated settlement resulted in a charge to 1994 operations, including legal fees, of approximately $734,000.
11. AMORTIZATION
Oil and gas properties amortization expense per dollar of oil and gas revenue for the years ended December 31, 1992, 1993 and 1994 were $.33, $.32 and $.41, respectively. Accumulated amortization relating to oil and gas producing activities at December 31, 1993 and 1994 amounted to $30,290,574 and $37,374,264, respectively.
In the fourth quarter of 1994, the Company recorded approximately $1.1 million of incremental amortization on oil and gas properties over that recorded in each of the previous three quarters of 1994. Approximately $320,000 of this increase is attributable to the JMC Acquisition discussed in Note 2, while the majority of the remainder is attributable to the downward revisions in oil and gas reserve estimates and reduced natural gas prices at December 31, 1994.
12. DISCONTINUED OPERATIONS
During the third quarter of 1992, ANEC sold the assets of its saltwater disposal facilities and a subsidiary to the entities which had previously sold these assets to ANEC. ANEC received cash of $492,000, shares of ANEC's common stock valued at $183,000, the forgiveness of a promissory note and related accrued interest aggregating $188,000 and the assumption of liabilities by the purchaser, aggregating $95,000. The common stock and note payable had previously been issued to the sellers of the assets. The shares of ANEC's common stock received from the purchaser of these operations were issued as partial payment of the capital lease relating to the assets sold.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Revenues, loss from operations (net of income taxes of $5,000), loss on disposition and total loss from discontinued operations related to these discontinued operations aggregated $1,820,000, $276,000, $405,000 and $681,000, respectively, during 1992.
13. EXTRAORDINARY ITEMS
On December 31, 1992, ANEC and its lender, Endowment Energy Partners, L. P. ("EEP"), a related party, entered into an agreement for the early repayment of its indebtedness. During April 1993, ANEC terminated its credit agreements with EEP and repaid the indebtedness under the agreement. The early extinguishment of the debt resulted in an extraordinary loss of $510,000, net of applicable income taxes.
In November 1994, the Company settled a dispute with a stockholder to whom the Company had issued unsecured notes payable and warrants (the "Stock Purchase Warrants") to purchase 223,333 shares of the Company's common stock, resulting in a gain of approximately $1.1 million. In anticipation of the lender exercising the Stock Purchase Warrants and a related warrant put option, the Company had accrued $2,231,100 as of December 31, 1993; however, the Company alleged that the lender failed to exercise the Stock Purchase Warrants, and failed to property exercise its warrant put option. After litigating this matter, through the Federal Court, the Company settled this dispute, resulting in a $1.1 million reduction of the $2.2 million liability previously recorded and cancellation of the Stock Purchase Warrants.
14. SUBSEQUENT EVENT
On March 14, 1995, the Company announced that its Board of Directors approved an agreement to enter into negotiations with Abraxas Petroleum Corporation ("Abraxas") with respect to the combination of the two companies. Under the terms of the agreement, the Company and Abraxas would have 45 days to complete their due diligence investigations and attempt to reach a definitive agreement on the terms of a transaction. Abraxas is an oil and gas company with 1994 revenues of approximately $11.3 million.
15. SUPPLEMENTARY OIL AND GAS INFORMATION
FINANCIAL DATA
All of the oil and gas producing activities of the Company are located in the United States and represent substantially all of the business activities of the Company. The following costs include all such costs incurred during each period, except for depreciation and amortization of costs capitalized:
COSTS INCURRED IN OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES:
-------------------- (1) Net of reimbursed costs and the excess of sales proceeds over cost of properties transferred to the limited partnerships.
(2) Net of reimbursed costs, sales proceeds from properties sold and 1993 purchase price reclassification.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CAPITALIZED COSTS:
UNPROVED PROPERTIES NOT BEING AMORTIZED:
The costs of unproved properties not being amortized are related to properties which are not individually significant and on which the evaluation process has not been completed. When evaluated these costs will be transferred to properties being amortized.
OIL AND GAS RESERVE DATA (UNAUDITED)
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES:
The estimates of proved producing reserves of the Company were estimated by independent petroleum engineers, Edinger Engineering Inc., except as noted below for ANEC. Proved nonproducing and proved undeveloped reserves were estimated by Company petroleum engineers, except as noted below for ANEC and the 1994 reserves were reviewed by Edinger Engineering Inc., as specified in their letter dated March 29, 1995. This review should not be construed to be an audit as defined by the Society of Petroleum Engineers' audit guidelines. The estimated proved reserves of ANEC were determined by ANEC petroleum engineers for 1992 and 1993. The estimates of proved reserves for ANEC for 1992 and 1993 are combined with the Company below. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental and arbitrary determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history or as a result of changes in economic conditions. The majority of the Company's reserves are located in Arkansas, Oklahoma and onshore Texas.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A) In 1994, the Company's oil and gas reserves were revised downwards as a result of declines in product prices which shortened the economic lives of the properties. Additionally, gas reserves associated with one field were revised downward by approximately 13 Bcf based upon the performance history of the field (which had previously been estimated using the volumetric method and the limited production data available at that time.) Revisions to this field were somewhat offset by other upward revisions made to certain producing Oklahoma properties based on the performance history of those properties. In 1992, the Company revised the oil reserves downward 240,794 barrels associated with one field to reflect a higher degree of risk of recovering such reserves; gas reserves associated with one field were revised upward by 1,453,520 Mcf based on the performance history of the offset wells. Additionally, other upward revisions were made as a result of increased product prices and the performance history of certain properties purchased in 1991.
Reserves of wells which have performance history were estimated through analysis of production trends and other appropriate performance relationships. Where production and reservoir data was limited, the volumetric method was used and it is more susceptible to subsequent revisions.
OIL AND GAS RESERVE DATA (UNAUDITED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
Future net cash inflows are based on the future production of proved reserves of crude oil, condensate, natural gas and natural gas liquids as estimated by petroleum engineers by applying current prices of oil and gas (with consideration of price changes only to the extent fixed and determinable and with consideration of the timing of gas sales under existing contracts or spot market sales) to estimated future production of proved reserves. Prices used in determining future cash inflows for oil and natural gas for the periods ended December 31, 1992, 1993 and 1994 were as follows: 1992 - $18.13, $1.98; 1993 - $12.75, $2.20; and 1994 - $16.25, $1.62, respectively. Future net cash flows are then calculated by reducing such estimated cash inflows by the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves and by the estimated future income taxes. Estimated future income taxes are computed by applying the appropriate year-end tax rate to the future pretax net cash flows relating to the Company's estimated proved oil and gas reserves. The estimated future income taxes give effect to permanent differences and tax credits and allowances.
The standardized measure of discounted future net cash flows is based on criteria established by Financial Accounting Standards Statement No. 69, "Accounting for Oil and Gas Producing Activities" and is not intended to be a "best estimate" of the fair value of the Company's oil and gas properties. For this to be the case, forecasts of future economic conditions, varying price and cost estimates, varying discount rates and consideration of other than proved reserves (i.e., probable reserves) would have to be incorporated into the valuations.
ALEXANDER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the Company's estimated standardized measure of discounted future net cash flows (in thousands):
OIL AND GAS RESERVE DATA (UNAUDITED)
The following table sets forth changes in the standardized measure of discounted future net cash flows as follows (in thousands):
-------------------- (A) The increase in purchases in 1992 and 1994 consists primarily of the merger with Bradmar and the JMC Acquisition, respectively, which includes proved developed and undeveloped reserves.
(B) The change included in the caption "Other" results principally from net changes in the timing of production of oil and gas reserves and the change in timing related to the development of proved undeveloped reserves.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information relating to the identification, business experience and directorships of each director and nominee for director of the Company required by Item 401 of Regulation S-K and presented in the section entitled "Election of Directors" of the Company's Proxy Statement for the annual meeting of stockholders on May 9, 1995, is hereby incorporated by reference. See Part I, Item 1A, "Executive Officers of the Registrant", for information relating to the identification and business experience of the Company's executive officers.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
The information relating to the remuneration of directors and officers required by Item 402 of Regulation S-K and presented in the section "Compensation" of the Company's Proxy Statement for the annual meeting of stockholders on May 9, 1995, is hereby incorporated by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information relating to security ownership required by Item 403 of Regulation S-K and presented in the section "Voting Securities Outstanding, Security Ownership of Management and Principal Stockholders" of the Company's Proxy Statement for the annual meeting of stockholders on May 9, 1995, is hereby incorporated by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information relating to transactions with management and business relationships required by Item 404 of Regulation S-K and presented in the section entitled "Certain Transactions" of the Company's Proxy Statement for the annual meeting of stockholders on May 9, 1995, is hereby incorporated by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Annual Report on Form 10-K.
1. Financial Statements. See Financial Statements and Supplementary Data under Item 8 for a list of all financial statements filed as a part of this report.
All schedules have been omitted since the schedules are either not required or the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto.
3. Exhibits.
Exhibit Number Description ------- ----------- 3(a) Certificate of Incorporation of the Registrant, and amendments thereto, has been previously filed as Exhibit 3(a) to Form 10-K for the fiscal year ended December 31, 1991, and such certificate is incorporated herein by reference.
3(b) Certificate of Amendment of Certificate of Incorporation of the Registrant as filed with the Oklahoma Secretary of State on May 18, 1993, has been previously filed as Exhibit 3(b) to Form 10-K for the fiscal year ended December 31, 1993, and such certificate is incorporated herein by reference.
3(c) Certificate of Designation of Series A Junior Participating Preferred Stock of the Registrant as filed with the Oklahoma Secretary of State on December 15, 1994, has been previously filed as Exhibit 4.1 to Form 8-K dated December 15, 1994, and such certificate is incorporated herein by reference.
3(d) Restated Bylaws of the Registrant, effective November 1, 1987.
4(a) Share Rights Agreement by and between the Registrant and Liberty Bank and Trust Company of Oklahoma City, N.A. dated December 15, 1994, has been previously filed as Exhibit 4.2 to Form 8-K dated December 15, 1994, and such agreement is incorporated herein by reference.
4(b) Note Agreement between the Registrant and John Hancock Mutual Life Insurance Company dated June 1, 1988.
4(c) Note Agreement dated as of April 25, 1989, by and among AEJH 1989 Limited Partnership, the Registrant and John Hancock Mutual Life Insurance (10 1/2% Senior Secured Notes).
10(a) Agreement and Plan of Merger by and among the Registrant, Alexander Acquisition Company and American Natural Energy Corporation ("ANEC") dated April 21, 1994, has previously been filed as Item 2 to Registration Statement No. 33-78450 dated May 4, 1994, and such agreement is incorporated herein by reference.
10(b) Amendment to Agreement and Plan of Merger by and among the Registrant, Alexander Acquisition Company and ANEC dated June 10, 1994, has previously been filed as Item 2.1 to Registration Statement No. 33-78450 dated June 14, 1994, and such amendment is incorporated herein by reference.
10(c) Credit Agreement dated November 14, 1994 among the Registrant, certain commercial lending institutions and Canadian Imperial Bank of Commerce, as Agent, has previously been filed as Exhibit 10.1 to Form 8-K dated November 14, 1994, and such agreement is incorporated herein by reference.
10(d) Sale and Purchase Agreement dated September 26, 1994 by and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the Registrant has previously been filed as Exhibit 2.1 to Form 8-K dated November 14, 1994, and such agreement is incorporated herein by reference.
10(e) First Amendment to Sale and Purchase Agreement dated October 26, 1994 by and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the Registrant has previously been filed as Exhibit 2.2 to Form 8-K dated November 14, 1994, and such amendment is incorporated herein by reference.
10(f) Alexander Energy Corporation 1986 Incentive Stock Option Plan, as amended, has previously been filed as Exhibit 4.2 to Registration Statement No. 33-20425 dated March 22, 1988, and such plan is incorporated herein by reference.
10(g) Alexander Energy Corporation 1993 Stock Option Plan has previously been filed as Exhibit A to the Registrant's Proxy Statement for the 1993 Annual Meeting of Stockholders, and such plan is incorporated herein by reference.
10(h) 1993 Restricted Stock Award Plan for Alexander Energy Corporation and It's Subsidiaries has previously been filed as Exhibit B to the Registrant's Proxy Statement for the 1993 Annual Meeting of Stockholders, and such plan is incorporated herein by reference.
10(i) Agreement of Limited Partnership of AEJH 1985 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company, together with all amendments thereto, has previously been filed as Exhibit 10(e) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(j) Agreement of Limited Partnership of AEJH 1987 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company, together with all amendments thereto, has previously been filed as Exhibit 10(g) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(k) Agreement of Limited Partnership of AEJH 1987-A Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company dated December 28, 1987.
10(l) Agreement of Limited Partnership of AEJH 1989 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company dated April 25, 1989.
10(m) Limited Partnership Agreement of Independent Energy Marketing, Ltd. dated January 1, 1990 by and between Independent Energy Marketing, Inc. ("IEM"), general partner, and Boomer Marketing Corporation ("Boomer"), Verado Energy, Inc. and Anchorage Oil & Gas, Inc., limited partners, ("IEM Partnership") has previously been filed as Exhibit 10(k) to Form 10-K dated December 31, 1991, and such agreement is incorporated herein by reference.
10(n) Letter Agreement dated August 22, 1994 by and between IEM and Boomer, a wholly-owned subsidiary of the Registrant, terminating IEM Partnership.
10(o) Limited Partnership Agreement of Energy and Environmental Services Limited Partnership dated May 15, 1991 by and between Energy and Environmental Services, Inc., as general partner, and Alexander Energy Corporation and REP, Inc., as limited partners, has previously been filed as Exhibit 10(l) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(p) Promissory Note dated June 15, 1988 in the principal amount of $77,500 from Bob G. Alexander to the Registrant has previously been filed as Exhibit 10(u) to Registration Statement No.33-45182 dated January 24, 1992, and such note is incorporated herein by reference.
10(q) Purchase Agreement between the Registrant and Alexander Resources, a limited partnership, dated August 13, 1990 has previously been filed as Exhibit 10(v) to Registration Statement No. 33-45182 dated January 24, 1992, and such agreement is incorporated herein by reference.
10(r) Alexander Energy Corporation 1981 Non-Qualified Stock Option Plan has previously been filed as Exhibit 10(w) to Registration Statement No. 33-45182 dated January 24, 1992, and such plan is incorporated herein by reference.
10(s) Consulting Agreement dated March 19, 1992 between the Registrant and Petroleum Investment Securities Corp. has previously been filed as Exhibit 10(t) to Form 10-K for the fiscal year ended December 31, 1993, and such agreement is incorporated herein by reference.
10(t) Warrant Purchase Agreement among the Registrant, Hanifen, Imhoff Inc. and The Principal/Eppler, Guerin & Turner, Inc. has previously been filed as Exhibit 10(u) to Amendment No. 1 to Registration Statement No. 33- 57142 dated February 26, 1993, and such agreement is incorporated herein by reference.
10(u) Purchase Option agreement (warrants) between ANEC and Gaines, Berland, Inc. dated September 14, 1993.
10(v) Alexander Energy Corporation Management Incentive Plan effective January 1, 1991 has previously been filed as Exhibit 10(v) to Registration Statement No. 33-57142 dated January 19, 1993, and such agreement is incorporated herein by reference.
10(w) Underwriting Agreement by and among the Registrant, Hanifen, Imhoff Inc. and The Principal/Eppler, Guerin & Turner, Inc. dated March 3, 1993, has previously been filed as Exhibit 10(w) to Form 10-K for the fiscal year ended December 31, 1993, and such agreement is incorporated herein by reference.
10(x) Stock Option Agreements between ANEC and Larry L. Terry dated April 19, 1993 and November 29, 1993.
10(y) ALN Resources Corporation (former corporate name for ANEC) ("ALN") 1992 Directors Stock Option Plan.
10(z) Employment and Option Agreement between ALN and Michael Paulk dated July 1, 1990, as amended May 1, 1993.
10(aa) Cancellation and Severance Agreement between ANEC and Michael Paulk dated September 19, 1994.
10(bb) Employment and Option Agreement between ALN and Robert C. Johnson dated July 1, 1990, as amended May 1, 1993.
10(cc) Cancellation and Severance Agreement between ANEC and Robert C. Johnson dated September 19, 1994.
10(dd) Form of Employment Agreement between the Registrant and the executive officers of the Registrant.
10(ee) Form of Special Severance Agreement between the Registrant and the technical support staff of the Registrant.
10(ff) Separation Policy of the Registrant dated December 8, 1994.
11 Computation of Earnings (Loss) per share.
21 Subsidiaries of the Registrant
23(a) Consent of Ernst & Young LLP, Independent Auditors
23(b) Consent of Coopers & Lybrand L.L.P., Independent Accountants
27 Financial Data Schedules
(b)(i) Report on Form 8-K dated November 14, 1994, as amended by Form 8-K/A filed January 27, 1995, disclosing the acquisition of properties from JMC Exploration, Inc. and execution of a $52 million credit facility with Canadian Imperial Bank of Commence.
(b)(ii) Report on Form 8-K dated December 15, 1994 reporting the adoption of a Rights Agreement and the declaration of a dividend distribution of preferred share purchase rights.
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 behalf of the undersigned, thereunto duly authorized.
ALEXANDER ENERGY CORPORATION
By /s/ BOB G. ALEXANDER March __, 1995 Bob G. Alexander President
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 dates indicated.
Index to Exhibits to Form 10-K
Exhibit Number Description ------- ----------- 3(a) Certificate of Incorporation of the Registrant, and amendments thereto, has been previously filed as Exhibit 3(a) to Form 10-K for the fiscal year ended December 31, 1991, and such certificate is incorporated herein by reference.
3(b) Certificate of Amendment of Certificate of Incorporation of the Registrant as filed with the Oklahoma Secretary of State on May 18, 1993, has been previously filed as Exhibit 3(b) to Form 10-K for the fiscal year ended December 31, 1993, and such certificate is incorporated herein by reference.
3(c) Certificate of Designation of Series A Junior Participating Preferred Stock of the Registrant as filed with the Oklahoma Secretary of State on December 15, 1994, has been previously filed as Exhibit 4.1 to Form 8-K dated December 15, 1994, and such certificate is incorporated herein by reference.
3(d) Restated Bylaws of the Registrant, effective November 1, 1987.
4(a) Share Rights Agreement by and between the Registrant and Liberty Bank and Trust Company of Oklahoma City, N.A. dated December 15, 1994, has been previously filed as Exhibit 4.2 to Form 8-K dated December 15, 1994, and such agreement is incorporated herein by reference.
4(b) Note Agreement between the Registrant and John Hancock Mutual Life Insurance Company dated June 1, 1988.
4(c) Note Agreement dated as of April 25, 1989, by and among AEJH 1989 Limited Partnership, the Registrant and John Hancock Mutual Life Insurance (10 1/2% Senior Secured Notes).
10(a) Agreement and Plan of Merger by and among the Registrant, Alexander Acquisition Company and American Natural Energy Corporation ("ANEC") dated April 21, 1994, has previously been filed as Item 2 to Registration Statement No. 33-78450 dated May 4, 1994, and such agreement is incorporated herein by reference.
10(b) Amendment to Agreement and Plan of Merger by and among the Registrant, Alexander Acquisition Company and ANEC dated June 10, 1994, has previously been filed as Item 2.1 to Registration Statement No. 33-78450 dated June 14, 1994, and such amendment is incorporated herein by reference.
10(c) Credit Agreement dated November 14, 1994 among the Registrant, certain commercial lending institutions and Canadian Imperial Bank of Commerce, as Agent, has previously been filed as Exhibit 10.1 to Form 8-K dated November 14, 1994, and such agreement is incorporated herein by reference.
10(d) Sale and Purchase Agreement dated September 26, 1994 by and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the Registrant has previously been filed as Exhibit 2.1 to Form 8-K dated November 14, 1994, and such agreement is incorporated herein by reference.
10(e) First Amendment to Sale and Purchase Agreement dated October 26, 1994 by and among JMC Exploration, Inc., Ted Bowman, Chris Webb and John Abrahamson and the Registrant has previously been filed as Exhibit 2.2 to Form 8-K dated November 14, 1994, and such amendment is incorporated herein by reference.
10(f) Alexander Energy Corporation 1986 Incentive Stock Option Plan, as amended, has previously been filed as Exhibit 4.2 to Registration Statement No. 33-20425 dated March 22, 1988, and such plan is incorporated herein by reference.
10(g) Alexander Energy Corporation 1993 Stock Option Plan has previously been filed as Exhibit A to the Registrant's Proxy Statement for the 1993 Annual Meeting of Stockholders, and such plan is incorporated herein by reference.
10(h) 1993 Restricted Stock Award Plan for Alexander Energy Corporation and It's Subsidiaries has previously been filed as Exhibit B to the Registrant's Proxy Statement for the 1993 Annual Meeting of Stockholders, and such plan is incorporated herein by reference.
10(i) Agreement of Limited Partnership of AEJH 1985 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company, together with all amendments thereto, has previously been filed as Exhibit 10(e) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(j) Agreement of Limited Partnership of AEJH 1987 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company, together with all amendments thereto, has previously been filed as Exhibit 10(g) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(k) Agreement of Limited Partnership of AEJH 1987-A Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company dated December 28, 1987.
10(l) Agreement of Limited Partnership of AEJH 1989 Limited Partnership by and between the Registrant and John Hancock Mutual Life Insurance Company dated April 25, 1989.
10(m) Limited Partnership Agreement of Independent Energy Marketing, Ltd. dated January 1, 1990 by and between Independent Energy Marketing, Inc. ("IEM"), general partner, and Boomer Marketing Corporation ("Boomer"), Verado Energy, Inc. and Anchorage Oil & Gas, Inc., limited partners, ("IEM Partnership") has previously been filed as Exhibit 10(k) to Form 10-K dated December 31, 1991, and such agreement is incorporated herein by reference.
10(n) Letter Agreement dated August 22, 1994 by and between IEM and Boomer, a wholly-owned subsidiary of the Registrant, terminating IEM Partnership.
10(o) Limited Partnership Agreement of Energy and Environmental Services Limited Partnership dated May 15, 1991 by and between Energy and Environmental Services, Inc., as general partner, and Alexander Energy Corporation and REP, Inc., as limited partners, has previously been filed as Exhibit 10(l) to Form 10-K for the fiscal year ended December 31, 1991, and such agreement is incorporated herein by reference.
10(p) Promissory Note dated June 15, 1988 in the principal amount of $77,500 from Bob G. Alexander to the Registrant has previously been filed as Exhibit 10(u) to Registration Statement No.33-45182 dated January 24, 1992, and such note is incorporated herein by reference.
10(q) Purchase Agreement between the Registrant and Alexander Resources, a limited partnership, dated August 13, 1990 has previously been filed as Exhibit 10(v) to Registration Statement No. 33-45182 dated January 24, 1992, and such agreement is incorporated herein by reference.
10(r) Alexander Energy Corporation 1981 Non-Qualified Stock Option Plan has previously been filed as Exhibit 10(w) to Registration Statement No. 33-45182 dated January 24, 1992, and such plan is incorporated herein by reference.
10(s) Consulting Agreement dated March 19, 1992 between the Registrant and Petroleum Investment Securities Corp. has previously been filed as Exhibit 10(t) to Form 10-K for the fiscal year ended December 31, 1993, and such agreement is incorporated herein by reference.
10(t) Warrant Purchase Agreement among the Registrant, Hanifen, Imhoff Inc. and The Principal/Eppler, Guerin & Turner, Inc. has previously been filed as Exhibit 10(u) to Amendment No. 1 to Registration Statement No. 33- 57142 dated February 26, 1993, and such agreement is incorporated herein by reference.
10(u) Purchase Option agreement (warrants) between ANEC and Gaines, Berland, Inc. dated September 14, 1993.
10(v) Alexander Energy Corporation Management Incentive Plan effective January 1, 1991 has previously been filed as Exhibit 10(v) to Registration Statement No. 33-57142 dated January 19, 1993, and such agreement is incorporated herein by reference.
10(w) Underwriting Agreement by and among the Registrant, Hanifen, Imhoff Inc. and The Principal/Eppler, Guerin & Turner, Inc. dated March 3, 1993, has previously been filed as Exhibit 10(w) to Form 10-K for the fiscal year ended December 31, 1993, and such agreement is incorporated herein by reference.
10(x) Stock Option Agreements between ANEC and Larry L. Terry dated April 19, 1993 and November 29, 1993.
10(y) ALN Resources Corporation (former corporate name for ANEC) ("ALN") 1992 Directors Stock Option Plan.
10(z) Employment and Option Agreement between ALN and Michael Paulk dated July 1, 1990, as amended May 1, 1993.
10(aa) Cancellation and Severance Agreement between ANEC and Michael Paulk dated September 19, 1994.
10(bb) Employment and Option Agreement between ALN and Robert C. Johnson dated July 1, 1990, as amended May 1, 1993.
10(cc) Cancellation and Severance Agreement between ANEC and Robert C. Johnson dated September 19, 1994.
10(dd) Form of Employment Agreement between the Registrant and the executive officers of the Registrant.
10(ee) Form of Special Severance Agreement between the Registrant and the technical support staff of the Registrant.
10(ff) Separation Policy of the Registrant dated December 8, 1994.
11 Computation of Earnings (Loss) per share.
21 Subsidiaries of the Registrant
23(a) Consent of Ernst & Young LLP, Independent Auditors
23(b) Consent of Coopers & Lybrand L.L.P., Independent Accountants
27 Financial Data Schedules
(b)(i) Report on Form 8-K dated November 14, 1994, as amended by Form 8-K/A filed January 27, 1995, disclosing the acquisition of properties from JMC Exploration, Inc. and execution of a $52 million credit facility with Canadian Imperial Bank of Commence.
(b)(ii) Report on Form 8-K dated December 15, 1994 reporting the adoption of a Rights Agreement and the declaration of a dividend distribution of preferred share purchase rights.