-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, P0k6eeogpmWKQK437EI4erPo6WYEjXIu1biDNc950c4vifr4CeNKQvaMvoK/qCu+ 265hYkv2KHdc9sIV3rLptQ== 0000950109-96-001733.txt : 19960326 0000950109-96-001733.hdr.sgml : 19960326 ACCESSION NUMBER: 0000950109-96-001733 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960325 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARCH PETROLEUM INC /NEW/ CENTRAL INDEX KEY: 0000320678 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 830248900 STATE OF INCORPORATION: NV FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-09976 FILM NUMBER: 96538104 BUSINESS ADDRESS: STREET 1: 777 TAYLOR ST STE II-A CITY: FORT WORTH STATE: TX ZIP: 76102 BUSINESS PHONE: 8173329209 MAIL ADDRESS: STREET 1: 777 TAYLOR STREET SUITE II-A STREET 2: 777 TAYLOR STREET SUITE II-A CITY: FT WORTH STATE: TX ZIP: 76102 10-K 1 FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES - ------ EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31, 1995 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES - ------ EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from ________ to ________ Commission file number 0-9976 ARCH PETROLEUM INC. (Exact name of registrant as specified in its charter) DELAWARE 83-0248900 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 777 Taylor Street, Suite II, Fort Worth, Texas 76102 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (817)332-9209 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: None SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Name of each exchange Title of each class on which registered ------------------------- ---------------------- Common Stock, par value $0.01 per share NASDAQ National Market Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ________ ------- As of February 29, 1996, the aggregate market value of the voting stock held by nonaffiliates of the registrant was $34,295,700 based on the closing price reported by NASDAQ National Market. As of February 29, 1996, there were 17,141,404 shares of the registrants Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Part III information is included in the Registrant's definitive proxy statement which will be filed within 45 days of the date of this Form 10-K. TABLE OF CONTENTS PART I Page Item 1. Business................................................. 3 Item 2. Properties............................................... 7 Item 3. Legal Proceedings........................................ 10 Item 4. Submission of Matters to a Vote of Security Holders...... 10 PART II Item 5. Market for Company's Common Stock and Related Shareholder Matters...................................... 11 Item 6. Selected Financial Data.................................. 12 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 13 Item 8. Consolidated Financial Statements and Supplementary Data. 20 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................... 48 PART III Item 10. Directors and Executive Officers of the Company.......... 48 Item 11. Executive Compensation................................... 48 Item 12. Security Ownership of Certain Beneficial Owners and Management........................................... 48 Item 13. Certain Relationships and Related Transactions........... 48 PART IV Item 14. Exhibits, Consolidated Financial Statement Schedules, and Reports on Form 8-K.................................. 49
Signatures PART I ITEM 1. BUSINESS Arch Petroleum Inc., a Delaware corporation, (together with its subsidiaries, "the Company") primarily engages in oil and natural gas exploration, development, production, transportation and marketing in the Southwestern United States and subsequent to January 31, 1996, in Western Canada. The Company is also active in the acquisition of interests in oil and gas leases, both producing and non-producing. Threshold Development Company ("TDC"), an oil and gas exploration company, owns approximately 16.5% of the Company's common stock as of December 31, 1995. On October 30, 1992, the Company's Board of Directors approved the change of the Company's fiscal year end from October 31 to December 31 retroactive to December 31, 1991. On October 20, 1994, the Company sold the following securities to four institutional investors in a private placement (the "Placement"): (a) 727,273 shares of its 8% Exchangeable Convertible Preferred Stock (the "Preferred Stock"), $.01 par value, having an aggregate liquidation preference of $20,000,000, (b) $500,000 aggregate principal amount of its 9.75% Series A Convertible Subordinated Notes due 2004 (the "Series A Notes") and (c) $4,500,000 aggregate principal amount of its Adjustable Rate Series B Notes due 2004 (the "Series B Notes" and, together with the Series A Notes, the "Notes"). Gross proceeds from the Placement were $20 million for the Preferred Stock and $5 million for the Notes. The proceeds were used to pay down the Company's revolving credit facility (the "Revolver") with Bank One, Texas, N.A. The Bank of Scotland participates with Bank One in the Revolver. On January 31, 1995, the Company's shareholders, in a special meeting, approved an amendment to the Company's articles of incorporation whereby the number of authorized shares of the Company's capital stock was increased from 26,000,000 shares to 51,000,000 shares. Common stock is designated for 50,000,000 shares and preferred stock is designated for the remaining 1,000,000 shares. The Company has reserved 9,090,909 shares of common stock for issuance upon conversion of the securities in the Placement, if necessary, and has also reserved 361,690 shares of common stock for issuance upon exercise of options under its current incentive stock option plan. On April 11, 1995, the Company purchased 100,000 shares of common stock for its treasury from TDC at the then current market price. See Note 13 in the consolidated financial statements for information regarding revenues, operating profit and identifiable assets of the Company's segments. RECENT DEVELOPMENTS: OIL AND GAS OPERATIONS - ---------------------- In November 1992 the Company sold a volumetric production payment to Enron Reserve Acquisition Corp. ("Enron") for $24.3 million. The Company contracted to deliver to Enron the equivalent of approximately 17.9 Bcf of natural gas from Company operated properties in the Keystone Ellenburger Field ("Keystone") over 5.7 years beginning in December 1992. The Company is responsible for all costs of production, development and marketing of the dedicated gas. The deferred revenue associated with this transaction is recognized as the dedicated gas is delivered to Enron. In May 1993 the Railroad Commission 3 of Texas ("RRC") amended the field rules for Keystone reducing the allowable production. Subsequent to this ruling, until February 1995 the Company was not able to produce enough gas to satisfy the monthly delivery obligations to Enron. This created a delay in the scheduled volume deliveries under the volumetric production payment agreement. Effective February 1, 1995 through October 31, 1995, the RRC amended its interim order and established a system of field-wide allowables which allowed the Company to produce and sell approximately 20.2 million cubic feet (16.0 million net) of natural gas per day from its operated leases in Keystone. As of February 1, 1995, the Company resumed full scheduled natural gas volume deliveries under the existing production payment agreement. Approximately 9.0 million cubic feet of the natural gas produced each day from Company operated leases is delivered to Enron. Proceeds from the sale of a portion of the remaining net volumes may be used to offset past delivery volume delays. For two months effective November 1, 1995, the operators of Keystone agreed (with the RRC's approval) to reduce by approximately one-half, the daily production from the field. This temporary modification to current allowables was designed to provide the operators with additional information concerning the reservoir dynamics. The Company's net production from operated and nonoperated leases during this period was approximately 10.1 million cubic feet of natural gas per day. The curtailment did not significantly impact the Company's scheduled deliveries under the production payment agreement. During 1996 the Company anticipates the RRC to establish allowables for Keystone which will allow the Company to sell approximately 10.1 million cubic feet of natural gas per day from its operated leases. On March 31, 1994, the Company consummated an agreement with Chevron U.S.A. Inc. to purchase certain oil and gas properties for a cash consideration of $17.9 million. The Company borrowed the purchase price under the Revolver. The properties, located in Lea County, New Mexico, included interests in approximately 130 producing oil and gas wells. The Company operates and has a significant working interest in the majority of these properties. The effective date of the purchase was April 1, 1994. Effective January 31, 1996, the Company acquired Trax Petroleums Limited ("Trax"), a Canadian oil and gas exploration and development company headquartered in Calgary, Alberta, Canada. The Company's January 9, 1996, cash offer of Cdn. $0.71 for each of Trax's approximately 14,100,000 shares was accepted by more than 91% of Trax shareholders. Effective February 12, 1996, the Company completed the statutory compulsory acquisition of the remaining shares of Trax through the depository, Montreal Trust Company of Canada. The acquisition was made through Northern Arch Resources Ltd., a wholly-owned Canadian subsidiary of the Company. The current Trax staff of employees and its headquarters will remain in Calgary. The acquisition purchase price was approximately Cdn. $10,000,000 (approximately US $7,400,000 at January 31, 1996). Trax's November 30, 1995, oil and gas reserves, as estimated by its independent engineers,totalled 964,000 barrels of oil and 1.38 billion cubic feet of natural gas (1,193,000 BOE). The estimated future net income attributable to these reserves (discounted at 15%) is Cdn. $11,100,000 (approximately US $8,100,000 at January 31, 1996). Estimated daily production currently approximates 600 BOE. In addition to the existing reserve base, Trax holds a large working interest in approximately 40,000 net undeveloped acres. This acreage includes more than thirty distinct, high quality prospects which are in various stages of development. 4 NATURAL GAS PIPELINE OPERATIONS - ------------------------------- In July 1992 the Company, in conjunction with Central States Energy Corporation ("CSE"), formed Saginaw Pipeline Company, L.C. ("Saginaw") and Industrial Natural Gas, L.C. ("ING"). Concurrent with this event, Saginaw acquired a 6" pipeline that extends approximately 100 miles from Wichita Falls, Texas to Saginaw, Texas. ING was formed to market the sales and transmission of natural gas through the Saginaw pipeline. On September 27, 1995, the Company resolved a membership interest dispute with CSE. The Company issued $45,000 and 25,000 shares of the Companys' unissued common stock to CSE. As a result of this transaction, the Company now owns a 95% membership interest in Saginaw and ING. In January 1993 the Company acquired a 50% membership interest in Onyx Pipeline Company, L.C. ("Onyx"). PURECO Inc. and Sejita Pipeline Company each own a 25% membership interest. Onyx owns four pipelines (approximately 25 miles) which supply natural gas to four electric power plants owned by Central Power and Light ("CPL") in Nueces, Hidalgo, Webb and San Patricio Counties, in South Texas. Onyx's contract with CPL includes a provision for a portion of the base load to the four plants. Onyx also competes to supply additional quantities of gas which the plants require. Onyx also owns other pipelines, including approximately 40 miles of gathering systems. PRINCIPAL PRODUCTS AND MARKETS: The Company's principal products are oil and natural gas. The principal markets for such products are those wherein the Company's oil and gas properties are physically located, and the methods of distribution of such products are by the sale of such products at the wellhead to appropriate gathering companies operating in the geographic area of production. In its natural gas marketing and transmission activities, the Company buys and resells natural gas, receiving a gross margin or spread equal to the difference between the purchase price and the resale price of such natural gas. In addition, the Company receives a fee for transmission of natural gas over pipeline systems owned by the Company. CUSTOMERS: The Company markets and will continue to market its oil and gas products to a number of purchasers and does not believe that the loss of any single purchaser of its crude oil, condensate or natural gas production would adversely affect its operations. During the year ended December 31, 1995, the Company had two customers that represented 62% of total revenues from oil and gas sales, Cheveron U.S.A. Inc. (31%) and Enron Gas Marketing (31%). During 1995 Onyx sold natural gas to approximately 70 customers. CPL is the largest customer of the Company, representing 58% of gross revenues from pipeline sales. Onyx has a contract to deliver gas to CPL into 1999. BACKLOG ORDERS AND GOVERNMENT CONTRACTS: The Company has no amount of firm backlog orders, and is not a party to any material contracts the termination of which or renegotiation of terms of which may be made at the election of any government. 5 COMPETITION: The Company competes with numerous other companies and individuals in the search for and the acquisition of attractive oil and gas properties and in the marketing of oil and gas. The Company's competitors include major oil companies, other independent oil companies and individuals, most of which have financial resources, staffs and facilities substantially in excess of those of the Company. The Company is not a major factor in the petroleum industry. Competition in the acquisition of oil and gas prospects and properties has become increasingly intense in recent years. The Company's ability to acquire reserves in the future will depend not only on its ability to develop its present properties, but also on its ability to select and acquire suitable prospects for exploratory drilling or development. Marketing competition is affected in part by the production levels of domestic crude oil, crude oil imports, the proximity of pipelines to producing properties and the regulation by states of allowable rates of production. All of these variable factors are dependent on economic and political forces which cannot be accurately predicted in advance. Natural gas marketing is a highly competitive business. The Company sells natural gas to customers who can purchase natural gas from other suppliers. The Company competes with traditional regulated distribution companies as well as an increasing number of natural gas producers, marketers and brokers for the business of buying, selling and transporting natural gas. Other entities, including unregulated affiliates of regulated pipeline companies attempting to arrange direct sales of their own, have created natural gas marketing companies which also compete with the Company. ENVIRONMENTAL REGULATION: Production of oil and gas by the Company is affected by state and federal regulations. In most areas, the production of oil and gas is regulated by conservation laws and regulations which set allowable rates of production and otherwise control the conduct of oil and gas operations. In addition, the Company's producing and drilling operations are also subject to environmental protection regulations established by federal, state and local agencies. The Company believes that it is currently in compliance with all applicable federal, state and local environmental regulations. The Company does not believe that such environmental regulations in their present form have or will have any material effect upon its capital expenditures or earnings. The Company's competitors are subject to the same regulations to which the Company is subject and, therefore, such regulations will not have any material effect upon competitive position. The Company does not project any material capital expenditures for environmental control facilities for any succeeding year. GOVERNMENT REGULATION: Federal regulation has had and is expected to continue to have a significant effect on the natural gas marketing activities of the Company. Such activities are affected by the Federal Energy Regulatory Commission ("FERC") rules and orders issued pursuant to the Natural Gas Act ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA"). In general, both of these acts authorize the FERC to regulate certain activities of companies engaged in the interstate sale and transport of natural gas. 6 Under the NGPA, natural gas was classified according to category, based primarily on the age of the well producing the natural gas and the location, character and permeability of the formation from which the natural gas is produced, and price ceilings were established for the various categories of natural gas. Most of the price ceilings established by the NGPA have been abolished and many categories of natural gas have been deregulated. The Company must comply with the price ceilings for the very limited volume of gas still subject to the price ceilings, if any. The natural gas industry is presently in a state of significant change because of the adoption by FERC of "Order 636". The Order directly affects the natural gas pipeline companies regulated by FERC, primarily with regard to natural gas transportation services provided by those companies. In addition, because of Order 636, most of those pipeline companies are no longer directly acting as gas suppliers to the natural gas distribution companies serving gas consumers in the United States. Due to these changes, the distribution companies are forced to make new gas supply arrangements for their needs. All of these changes affect both gas producers and marketers. However, the changes have not materially adversely affected Company operations. The states in which the Company conducts oil and gas activities also regulate oil and gas production. Such rules may control the method of developing new fields, the maximum daily production allowed from a well and the operation of a well. EMPLOYEES: As of February 29, 1996, the Company had 50 full-time employees. These employees are not represented by labor unions and the Company considers its employee relations to be satisfactory. ITEM 2. PROPERTIES GENERAL: The Company's corporate headquarters occupy approximately 9,745 square feet of leased office space located in Fort Worth, Texas. The Company also leases 2,200 square feet of office space in Midland, Texas. Onyx leases 3,664 square feet of office space in Corpus Christi, Texas. Saginaw leases 500 square feet of office space in Wichita Falls, Texas. The Company owns small field offices in Kermit, Texas, and in Eunice and Artesia, New Mexico. OIL AND GAS RESERVES: A description of the Company's net quantity of oil and gas reserves is contained in the Unaudited Supplemental Oil and Gas Disclosures of the accompanying consolidated financial statements. All oil and gas reserves were estimated by Ryder Scott Company, independent petroleum engineers, and are detailed in a report prepared for the exclusive use of the Company. All such estimations were made in accordance with regulations promulgated by the Securities and Exchange Commission ("SEC"). The reserve report is available for examination at the corporate headquarters. The Company has no long-term supply or similar agreements with foreign governments or authorities. The Company has not filed with or included in reports to any federal authority or agency, other than the SEC any estimate of total proved net oil and gas reserves since December 31, 1994. All of the Company's production, acreage and drilling activity is located in the United States. In 1996, Trax's results of operations and its oil and gas reserves, all of which are located in Western Canada, will be consolidated into the 7 Company's financial statements. The Company operates in an industry that is subject to volatile prices for its products. Revenues from oil and gas production may be affected to a significant degree by fluctuations in prices that are brought on by factors beyond the Company's control. The following table sets forth a summary of the Company's oil and gas reserve quantities and present value of future net revenues associated therewith.
December 31, ------------------------------------- 1995 1994 1993 ----------- ----------- ----------- Present value of discounted future net revenues before income taxes $64,296,200 $61,078,500 $39,252,500 Quantities of reserves: Proved developed and undeveloped: Oil (Bbls) 4,030,300 3,586,400 1,585,700 Gas (Mcf) 61,286,400 61,546,200 43,553,600 Proved developed: Oil (Bbls) 2,993,600 3,390,600 1,368,600 Gas (Mcf) 55,628,500 60,666,200 41,785,500
The figures above exclude 11.9 Bcf, 15.5 Bcf and 16.1 Bcf of proved gas reserves and $11,672,700, $12,566,300 and $12,860,100 of discounted future net revenues at December 31, 1995, 1994 and 1993, respectively, which were sold to Enron in the volumetric production payment discussed earlier. See the Unaudited Supplemental Oil and Gas Disclosures in the accompanying consolidated financial statements for key factors and additional information related to the Company's reserve estimates. WELLS DRILLED: The following table shows the wells drilled by or participated in by the Company since 1993. Gross wells refer to the total number of wells in which the Company has an interest. Net wells are the gross wells multiplied by the Company's working interest in each well. A dry well is one that is found to be incapable of producing commercial amounts of oil or gas, and a productive well is one that is not dry.
Gross Wells Net Wells ------------------------- --------------------- Produc- Produc- tive Dry Total tive Dry Total ------- --- ----------- --------- --- ----- Year Ended December 31,1995: Exploratory - 4 4 - 2.2 2.2 Development 110 - 110 13.4 - 13.4 Year Ended December 31,1994: Exploratory - - - - - - Development 34 - 34 17.9 - 17.9 Year Ended December 31,1993: Exploratory - - - - - - Development 32 - 32 12.6 - 12.6
8 LEASES AND WELLS OWNED: At December 31, 1995, the Company owned interests in 83,333 gross developed acres and 17,252 net developed acres. It also owned an interest in 117,433 gross undeveloped acres and 45,455 net undeveloped acres, the majority of which is held by production. The leases and wells acquired in the Trax purchase effective January 31, 1996, are not included in the information below. See also the discussion of Proposed Drilling Activity and Acquisitions. As of December 31, 1995, the Company's interests in wells owned were as follows:
Total Texas New Mexico ----------------- ------------ ------------ Gross Net Gross Net Gross Net Type Wells Wells Wells Wells Wells Wells - ------- ----- ---------- ----- ----- ----- ----- Oil 1,356 253.3 1,223 145.5 133 107.8 Gas 204 121.0 117 55.8 87 65.2 ----- ----- ----- ----- --- ----- 1,560 374.3 1,340 201.3 220 173.0 ===== ===== ===== ===== === =====
In addition, the Company owns royalty interests in approximately 400 productive wells located in West Texas. PRODUCTION: The following table reflects net quantities of oil (including condensate and natural gas liquids) and of gas produced, the average price received per barrel of oil and per Mcf of gas and the average production (lifting) cost per equivalent barrel.
Oil (Bbl) Gas (Mcf) Avg. Lifting --------------------- ----------------------- Cost Per Volume Avg Price Volume Avg Price Eq. Bbl (1) ------- --------- --------- --------- ------------ 1993 (2) 159,500 $17.36 3,851,500 $1.39 $5.35 1994 (3) 281,300 16.18 2,488,900 1.67 5.07 1995 (4) 382,100 17.28 7,382,900 1.32 4.45
(1) Equivalent barrels are calculated using a conversion factor of six Mcf of gas to one barrel of oil. Costs include severance taxes. (2) Includes effect of production payment volume of 1,382,900 Mcf at an average price of $1.30 and losses of $783,600 resulting from a natural gas swap transaction. (3) Includes effect of production payment volume of 183,300 Mcf at an average price of $1.28. (4) Includes effect of production payment volume of 3,090,400 Mcf at an average price of $1.11. 9 PROPOSED DRILLING ACTIVITY AND ACQUISITIONS: In late 1995 the Company began an infill drilling program in the Teague field area of its New Mexico properties. The first phase of this program comprises seven wells to be drilled by the end of the first quarter 1996. As of February 29, 1996, six of these wells had been successfully drilled and completed. Phase two of the infill program identifies up to twenty wells. Drilling commences upon the completion of phase one. If the Teague infill program continues successfully, the Company could drill up to forty wells in this field in the next three years. In addition the Company plans to recomplete numerous existing wells in the next two years if economic conditions are favorable. The Company expects to participate in similar development operations in non-operated properties on various other wells. The Company is involved in a 3-D seismic program encompassing three different regions in North Texas, West Texas and the Texas Panhandle area. In North Texas, the Company participated in the drilling of two successful development wells during 1995 using the 3-D data. The 3-D data also confirmed several quality development locations which had been tentatively identified by geology before the 3-D survey was conducted. These locations can be developed at reasonable costs and may be drilled to capitalize on improved product prices. In addition to providing confirmation of the known locations, a number of deeper structures were identified by the 3-D seismic program. During 1995 the Company drilled two non-commercial wells in both the West Texas and the Texas Panhandle prospect areas. The 3-D seismic and its interpretation was very effective in locating the drilling targets zones as expected. However, commercial quantities of hydrocarbons were not encountered in these wells. There are productive multi-pay zones in both prospect areas. The Company is continuing to develop and interpret the seismic information for both of these prospects. ITEM 3. LEGAL PROCEEDINGS From time to time the Company is involved in litigation arising in the normal course of business. In the opinion of management, the Company's ultimate liability, if any, from lawsuits currently pending would not materially affect the Company's financial condition or operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the Company's shareholders during the quarter ended December 31, 1995. 10 PART II ITEM 5. MARKET FOR COMPANY'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS The Company's common stock trades on the NASDAQ National Market under the symbol "ARCH". The following table sets forth the high and low prices of the Company's stock as reported by NASDAQ for the period from January 1, 1994, through December 31, 1995. These price quotations represent prices between dealers, do not include retail mark ups, mark downs, commissions or other adjustments and do not necessarily represent actual transactions. On February 29, 1996, the closing price for the Company's common stock was $2-3/4.
1995 1994 ------------------ ---------------- Period High Low High Low -------- -------- ------ -------- lst quarter $2-3/16 $1-11/16 $2-5/8 $2 2nd quarter 2-15/16 1-3/4 2-5/8 2-1/8 3rd quarter 3-1/16 2-1/4 2-3/8 1-15/16 4th quarter 2-11/16 1-11/16 2-1/4 1-15/16
There were approximately 1,600 shareholders of record as of December 31, 1995. No cash dividends have been paid on common stock to date. See Note 6 of the accompanying consolidated financial statements for discussion of restriction related to common stock dividends. The Company intends to maintain a policy of retaining earnings for use in the expansion of business. Transfer Agent: Harris Trust and Savings Bank P. O. Box 755 Chicago, IL 60690-0755 Investor Relations: Arch Petroleum Inc. Attention: Ralph Manoushagian 777 Taylor Street, Suite II Fort Worth, Texas 76102 11 ITEM 6. SELECTED FINANCIAL DATA The selected financial information set forth below was derived from the consolidated financial statements of the Company included in this report (see Item 8) and should be read in conjunction with them and Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Two Months Year Year Ended December 31, Ended Ended -------------------------------------------- December 31, October 31, (In Thousands) 1995 1994 1993 1992 1991 1991 ------- ------- ------- -------- ------------ ----------- OPERATING DATA: - --------------- Operating revenues (1) $66,590 $82,696 $44,148 $ 7,226 $ 883 $16,021 Exploration expense 898 1,641 157 24 9 108 Income (loss) before extraordinary item and cumulative effect of accounting change (164) (1,830) 176 68 60 6,991 Net income (loss) (164) (1,830) 176 68 - 6,991 Preferred stock dividends 1,600 311 - - - 152 Net income (loss) available per common share (.10) (.12) .01 - - .42 Weighted average common and common equivalent shares outstanding 17,195 17,244 17,142 16,884 16,802 16,470 BALANCE SHEET DATA: - -------------------------------- Total assets $79,672 $78,025 $51,069 $40,993 $26,238 $25,753 Deferred revenue 16,037 20,690 21,499 23,559 - - Long-term debt 17,821 9,632 6,500 - 10,000 9,000 Convertible subordinated notes 5,000 5,000 - - - - Convertible preferred stock 20,000 20,000 - - - - Shareholders' equity 7,595 9,490 11,679 11,855 12,032 11,963
No cash dividends have been paid on common stock since inception. See Note 6 of the accompanying consolidated financial statements for discussion of restriction on common stock dividends. (1) Included in 1991 operating revenues is a gain on sale of properties of $9,119,000. 12 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS With the exception of historical information, the matters discussed herein are forward-looking statements that involve risks and uncertainties including, but not limited to, oil and gas price fluctuations, economic conditions, interest rate fluctuations, the regulatory and political environments and other risks indicated in filings with the Securities and Exchange Commission. The following review of operations for the years ended December 31, 1995, 1994 and 1993 should be read in conjunction with the consolidated financial statements presented elsewhere. CAPITAL RESOURCES AND LIQUIDITY FINANCIAL POSITION. At December 31, 1995 the Company's total assets increased to $79.7 million from $78.0 million at December 31, 1994. Oil and gas properties increased $5.2 million as a result of development drilling as well as the recompletion and refurbishment of existing wells in New Mexico. The Company's working capital ratio was .9 at December 31, 1995 and 1994. The volumetric production payment sale to Enron on December 1, 1992, generated $24.3 million cash. The proceeds of the sale were first used to retire all $16.1 million of bank debt outstanding at that time. The proceeds from the production payment sale, less origination fees and revenue recognized as of December 31, 1992, were recorded as deferred revenue of $23.6 million. This revenue is recognized as the gas reserves (originally 17.9 Bcf) from Company operated interests in the Keystone Ellenburger Field ("Keystone") are produced and delivered to Enron. The Company is responsible for all costs of production, development and marketing of the dedicated gas. The Company recognized deferred revenues of $3.5 million, $0.2 million and $1.8 million during 1995, 1994 and 1993, respectively. The Company remitted $1.2 million, $0.6 million and $0.3 million to Enron during 1995, 1994 and 1993, respectively, in satisfaction of the Remedy Adjustment discussed below and in Note 5 to the consolidated financial statements. The proceeds for these payments were provided by a portion of the sale of allowable oil and casing head gas, as well as from gas produced in excess of the scheduled production payment volumes from Keystone, and which are made in addition to scheduled natural gas volume deliveries. Based on the expected deliveries under the agreement and the current product prices, estimated annual amortization of remaining deferred revenue is expected to be $6.8 million, $6.6 million and $2.6 million for 1996, 1997 and 1998, respectively. At December 31, 1995, the estimated remaining volumes deliverable to Enron under the production payment agreement were 11.9 Bcf of natural gas (including 3.6 Bcf of natural gas attributable to volume delivery delays resulting from field rule changes in prior periods). Pursuant to the agreement, the remedies for these volume delivery delays (the "Remedy Adjustment") are confined to sales only from Company operated properties in Keystone. Effective February 1, 1995 through October 31, 1995, the RRC amended its interim order issued in May 1993 and implemented a system of field-wide allowables which allowed the Company to fully meet its scheduled delivery of volumes under the production payment agreement and reduce the Remedy Adjustment. However, effective November 1, 1995, the RRC once again restricted the allowables thereby impeding the Company's ability to meet its scheduled deliveries. During 1996 the Company anticipates the RRC to establish allowables for Keystone which will allow the Company to sell approximately 10.1 million cubic feet of natural gas per day from its operated leases in Keystone. However, there can be no assurance that the RRC will issue orders which would allow production to resume at a rate to meet scheduled deliveries and reduce the Remedy Adjustment. The amount of volumes, if any, which will be necessary to satisfy the Remedy Adjustment is 13 dependent upon future gas prices. Based upon economics at December 31, 1995, the Company may deliver approximately 1.4 Bcf of natural gas volumes in excess of the original contracted delivery volumes in this regard. The Company's Revolver, which the Company entered into on April 6, 1990 (last amended on September 30, 1995, the third amendment) is in place for use by the Company at its discretion including drilling, development and acquisition of oil and gas properties. The Company has borrowed $15.3 million against the Revolver at December 31, 1995. The Revolver's borrowing base is the amount that the bank commits to loan to the Company based on the designated loan value established by the bank at its sole discretion and assigned to substantially all of the Company's oil and gas properties which serve as collateral for any loan which may be outstanding under the Revolver. The Revolver facility is $50.0 million and the borrowing base is currently $30.0 million. The borrowing base is reviewed semiannually by the bank at their discretion. A commitment fee of one half of one percent of the unused borrowing base accrues and is payable quarterly. Borrowings under the Revolver will, at the Company's option, bear interest either at the bank's Base Rate (national prime rate) or a rate based on the London Interbank Offered Rate (LIBOR). The average actual interest rate was 8.0% at December 31, 1995. Interest is payable monthly and no principal payments are required until maturity, which is May 1, 1997. The Onyx Term Loan Agreement (the "Onyx Note"), which Onyx entered into with the Bank of Scotland on March 30, 1994 (last amended September 30, 1994, the first amendment), is a separate facility and provided Onyx with $5.0 million. The Onyx Note bears interest at national prime rate plus one-half of one percent (9.00% at December 31, 1995). Interest on the unpaid principal amount of the note is payable quarterly and commenced on June 30, 1994. The unpaid principal ($3,611,000 at December 31, 1995), is payable in eighteen quarterly installments ending on March 31, 1999. Current maturities of the Onyx Note total $1.1 million at December 31, 1995. The Onyx Note is collateralized by certain of Onyx's pipelines, gathering facilities and related transportation contracts. In addition, the Onyx Note is guaranteed by the Company. Both the Revolver and Onyx note contain normal and standard covenants generally found in lending agreements. Among other things, these covenants prohibit the declaration and payment of cash dividends on the Company's common stock. In addition, the covenants stipulate the maintenance of financial criteria including: a minimum level of net worth, a certain current ratio, a certain debt to net worth ratio and a defined net income in excess of scheduled interest and principal payments. The Company and Onyx are currently in compliance with the loan agreements. Neither the Company nor Onyx has any additional unused lines of credit. Effective January 31, 1996, the Company acquired Trax Petroleums Limited ("Trax"), a Canadian oil and gas exploration and development company. The Company acquired 100% of the approximately 14,100,000 Trax common shares through Northern Arch Resources Ltd., ("Northern Arch") a wholly-owned Canadian subsidiary of the Company. The acquisition price was approximately Cdn. $10,000,000 (approximately U.S. $7,400,000 at January 31, 1996). On February 20, 1996, the Company entered into two new bank credit facilities: the Third Restated Revolving Credit Loan Agreement among the Company and Bank One, Texas, N.A., the Agent bank, and other banks (the "Domestic Revolver") and through its new 100% - owned subsidiary, Trax, the Credit Agreement among Trax and Bank of Montreal, the Canadian Agent bank, and other financial institutions (the "Canadian Revolver"). The two credit facilities are separate bank revolvers. It was the Company's desire to have "cross border" facilities in place to accommodate the Trax acquisition that led to these new credit facilities. The Domestic Revolver is a modification of the Company's existing Revolver with Bank One, Texas, N.A. and its participant, the Bank of Scotland. The principal changes to the former Revolver was the introduction of certain language, terms and concepts such that the Domestic Revolver and the Canadian Revolver 14 will be accommodated in pari passu sharing and general administration. This facility amends, restates and supersedes in its entirety the former Revolver. The facility remains at $50,000,000 and the current borrowing base also remains at $30,000,000. The Domestic Revolver matures on May 1, 1997. The security collateral requirements and the bank covenants and default provisions are essentially unchanged from the former Revolver. The Canadian Revolver is similar to the Domestic Revolver in all significant aspects. The loans under the Canadian Revolver are guaranteed by the Company ("the Guaranty") and is secured by, among other things, a first lien on 65% of the issued and outstanding shares of Northern Arch's common stock and a first lien on the oil and gas properties of the Company which serve as security in the Domestic Revolver. The Guaranty is intended to rank pari passu with the Company's obligations under the Domestic Revolver. The Canadian Revolver is also guaranteed by Northern Arch. The facility's initial commitment is U.S. $11,000,000. The proceeds of each advance may be used to fund the loan from Trax to Northern Arch up to U.S. $8,000,000 (which funded the acquisition of Trax), to acquire additional borrowing base properties, to drill and recomplete oil and gas wells and for general corporate purposes. Repayments shall be made relative to the currency used in each borrowing. The Canadian Revolver matures on May 1, 1997. There is a commitment fee of one half of one percent for the unused borrowing base which accrues and is payable on the first day of each quarter. The Trax borrowing base, which was designated as zero at date of closing, is the loan value determined by the Canadian Agent bank in its sole discretion based on its calculations of value of borrowing base properties utilizing current and customary procedures and standards for petroleum industry customers. The Canadian Agent bank is currently studying and evaluating Trax's properties. On October 20, 1994, the Company sold in a private placement (the "Placement") 727,273 shares of its 8% Exchangeable Convertible Preferred Stock having a liquidation preference of $20,000,000 and $5,000,000 of Convertible Subordinated Notes. The Preferred Stock accrues annual dividends at the rate of $2.20 per share. Dividends are payable semiannually and commenced April 20, 1995. During 1995 the Company paid $1,600,000 in dividends. The Notes bear interest at 9.75%. Interest on the unpaid principal balance of the Notes is payable quarterly and commenced January 20, 1995. During 1995 the Company paid $488,000 in interest. Gross proceeds from the Placement were used to pay down the Company's Revolver with Bank One, Texas, N.A. and the Bank of Scotland. Sources and Uses of Capital Resources. In 1995 the Company's principal sources of funds were $8.2 million (net) from the Revolver and $2.0 million from operations (excluding production payment remedy adjustment). These funds were consumed by: funding $6.1 million for development of existing properties in New Mexico and Texas and providing $1.8 million to financing activities including $1.6 million in preferred stock dividends and $0.2 million for treasury shares. In 1994 the Company's significant sources of funds were $25.0 million from the Placement and $32.9 million in borrowings from its debt facilities. These funds were utilized to retire $28.7 million in bank debt, to fund $18.7 million in developed and undeveloped oil and gas property acquisitions, to fund $5.8 million in development of existing properties in New Mexico and Texas, including the Keystone Ellenburger Field properties, to fund $2.9 million in pipeline acquisition and construction costs and to fund $1.6 million of the Company's 3-D seismic activities in Stonewall County and the Panhandle of Texas. In 1993 the Company's significant sources of funds were $6.5 million in borrowings from its Revolver, $0.8 million from net operating cash flows and the remaining cash proceeds ($7.0 million) from the Enron production payment sale. These funds were utilized to fund $5.7 million in pipeline acquisition and construction 15 costs and $5.4 million in development of existing wells, including the Keystone Ellenburger Field properties. The RRC is empowered to prevent waste and protect correlative rights and, in part, to oversee the oil and gas operators in Texas. It routinely rules in disagreements among operators and establishes "allowables" for all wells. Allowables are the rates of production for a specific well, generally stated in terms of barrels of oil or thousand cubic feet ("Mcf") of natural gas per day. Keystone is operated by three operators, including the Company. For at least two decades this field has been produced at certain allowable rates, under rules established by the RRC, so as to maximize the economic recovery of oil before the vast reserves of natural gas are produced. There had arisen a difference of opinion among the operators in the past three years concerning the appropriate rules necessary to maximize the economic recovery of oil and natural gas reserves in the field. In May 1993 the RRC amended the field rules regarding formation water production in Keystone. Subsequent to this ruling, until February 1995 the Company produced approximately 18.9 million barrels of formation water, thus earning and accumulating a bonus production allowable of approximately 9.5 million Mcf of natural gas. As a result, the Company incurred high water lifting costs without realizing the related natural gas revenues during this period. Effective February 1, 1995 through October 31, 1995, the RRC amended its interim order and established a system of field-wide allowables which allows the Company to produce and sell approximately 20.2 million cubic feet (16.0 million, net) of natural gas per day from its operated leases in Keystone. The Company continues to produce approximately 15,000 barrels of formation water per day. Concurrent with the implementation of the new field rules, the Company ceased to capitalize water lifting program costs and commenced amortization of the deferred water production costs as the bonus production allowable is produced. At December 31, 1995 and 1994, the Company had deferred $5.1 million and $5.6 million, respectively, of net water production costs. These costs have been included in proved oil and gas properties. As of December 31, 1995, the Company has amortized approximately $0.6 million of the deferred water production costs. On February 1, 1995, the Company resumed full scheduled natural gas volume deliveries under the existing production payment agreement. Approximately 9.0 million cubic feet of the natural gas produced each day from Company operated leases is delivered to Enron. Proceeds from the sale of a portion of the remaining net volumes is being used to offset past volume under deliveries. In November and December 1995 the operators of Keystone agreed (with the RRC's approval) to reduce, by approximately one-half, the daily production from the field. This temporary modification to current allowables was designed to provide the operators with additional information concerning the reservoir dynamics. The Company's net production from operated and nonoperated leases during this two months period was approximately 10.1 million cubic feet of natural gas per day. The curtailment did not significantly impact the Company's scheduled deliveries under the production payment agreement. During 1996 the Company anticipates the RRC to establish allowables for Keystone which will allow the Company to sell approximately 10.1 million cubic feet of natural gas per day from its operated leases. However, there can be no assurance that the RRC will increase the allowables and, if they do, how long they will maintain the increased allowables. During 1995 the Company successfully drilled and completed six development wells in New Mexico. Average daily production in the aggregate from these wells is approximately 335 barrels of oil and 1,300 Mcf of gas. The Company also successfully recompleted numerous wells in New Mexico. In late 1995 the Company began an infill drilling program in the Teague field area of its New Mexico properties. The first phase of this program comprises seven wells to be drilled by the end of the first quarter 1996. As of February 29, 1996, six of these wells had been successfully drilled and completed. Phase two of the infill program identifies up to 16 twenty wells. Drilling commences upon the completion of phase one. If the Teague infill program continues successfully, the Company could drill up to forty wells in this field in the next three years. In addition the Company plans to recomplete numerous existing wells in the next two years if economic conditions are favorable. The Company expects to participate in similar development operations in non-operated properties on various other wells. The Company is also involved in a 3-D seismic program encompassing three different regions in North Texas, West Texas and the Texas Panhandle. In North Texas, the Company participated in the drilling of two successful development wells during 1995 using the 3-D data. The 3-D data also confirmed several quality development locations which had been tentatively identified by geology before the 3-D survey was conducted. These locations can be developed at reasonable costs and may be drilled to capitalize on improved product prices. In addition to providing confirmation of the known locations, a number of deeper structures were identified by the 3-D seismic program. During 1995 the Company drilled two non-commercial wells in both the West Texas and the Texas Panhandle prospect areas. The 3-D seismic and its interpretation was very effective in locating the drilling target zones as expected. However, commercial quantities of hydrocarbons were not encountered in these wells. There are productive multi-pay zones in both prospect areas. At December 31, 1995, the Company had capitalized costs of approximately $1.0 million in total related to the 3-D seismic prospects included in unproved properties. The Company is continuing to develop and interpret the seismic information for both of these prospects. However, there can be no assurances that our exploration efforts will result in finding commercial quantities of oil and gas. Should the Company decide in the future that either of the prospects do not warrant extension of the lease terms, the Company would recognize an impairment charge at that time. The Company has sufficient cash flows and borrowing base in the Revolver to fund its anticipated drilling, development and acquisition programs for 1996 as well as its debt service and preferred stock dividend requirements. Additionally, the Company expects to meet its current operating cash requirements from cash flows provided by current operations. Management believes that the Company can continue to generate, or obtain through other alternatives, resources sufficient to meet cash requirements for future acquisition opportunities. The Company operates in an industry that is subject to volatile prices for its products. Cash flows from operations may be affected to a significant degree by fluctuations in prices that are brought on by factors beyond the Company's control. RESULTS OF OPERATIONS Year ended December 31, 1995 compared to ---------------------------------------- year ended December 31, 1994 ---------------------------- The Company recorded a net loss before dividends of $164,000 in 1995 as compared to a net loss before dividends of $1,830,000 in 1994. The net loss before dividends decreased $1,666,000 resulting from increased oil and gas sales, improved margins on pipeline sales and a decrease in exploration expense. Pipeline sales decreased $24,276,000 in 1995 as compared to 1994, and were offset by a corresponding decrease in natural gas purchases and operations of $25,806,000 for an overall net margin increase of $1,530,000. Natural gas volumes sold decreased 8,700,000 MMBtu in 1995 as compared to 1994. During 1994 gas was delivered to a major customer under a short-term contract that expired during 1994 and was not renewed. There were also less spot sales of gas during 1995 as compared to 1994. Both of these factors contributed to 17 the decline in volumes sold. During 1995 natural gas was purchased at an average price of $1.52 and sold at an average price of $1.58. During 1994 gas was bought and sold at an average price of $1.82 and $1.86, respectively. Gross margin increased to 5.6% in 1995 as compared to 1.7% in 1994 reflecting higher spreads in 1995. Revenues from oil and gas sales increased $7,649,000 in 1995 as compared to 1994, as a result of increased gas production from Keystone and increased production from the New Mexico properties as a result of the development and exploitation program in New Mexico and a full year of production as compared to nine months in 1994. Additionally, revenues were impacted by an increase in average oil prices and a decrease in average gas prices. Gas production in 1995 increased to 7,383,000 Mcf as compared to 2,489,000 Mcf in 1994, resulting in a $8,192,000 increase in sales. The average price received for gas was $1.32 in 1995 as compared to $1.67 in 1994, resulting in a $2,578,000 decrease in sales. The average price of gas, excluding certain production payment volumes, was $1.47 in 1995. Gas production increased primarily as a result of the RRC's amended order effective February 1, 1995, allowing the Company to produce approximately 18.1 million cubic feet of natural gas per day (net to its interest) from its operated and non-operated leases in Keystone. Oil production increased to 382,000 barrels in 1995 as compared to 281,000 barrels in 1994, resulting in a $1,630,000 increase in sales. The increase in oil production is due to the Company's successful drilling and development program in New Mexico and a full year of production from these properties. The average price received for oil increased to $17.28 in 1995 as compared to $16.18 in 1994, resulting in a $422,000 increase in sales. Lease operating expenses ("LOE") related to oil and gas properties increased $3,649,000 in 1995 as compared to 1994, primarily as a result of the amended RRC order affecting Keystone and the increased operations in New Mexico. As a result of the RRC's amended order effective February 1, 1995, the Company ceased capitalizing the water lifting program costs and is charging these costs to LOE as incurred. Lifting costs per equivalent barrel decreased to $4.45 in 1995 as compared to $5.07 in 1994, as a result of the increased oil and gas production. Exploration expense decreased $743,000 in 1995 as compared to 1994. During 1994 the Company incurred significant costs related to the early stages of a 3-D seismic program. Depletion, depreciation and amortization increased $2,482,000 in 1995 primarily as a result of the increased oil and gas production and investment in producing properties. General and administrative expenses increased $591,000 in 1995 as compared to 1994, reflecting higher personnel costs. Year ended December 31, 1994 compared to ---------------------------------------- year ended December 31, 1993 ---------------------------- The Company recorded a net loss before dividends of $1,830,000 in 1994 as compared to net income of $176,000 in 1993. Net income decreased $2,006,000 resulting from a $38,548,000 increase in revenues which was offset by a $41,495,000 increase in costs and expenses and a $941,000 decrease in income tax expense. Pipeline sales increased $37,953,000 in 1994 as compared to 1993, but were offset by an increase in natural gas purchases of $39,933,000 for the same period for an overall net margin decrease of $1,980,000. The increase in sales and purchases generally reflects substantially higher activity levels for Onyx in 1994 compared to 1993. Purchases increased more than sales, reflecting the fact that most of the increased volumes were from gas marketing activities from which Onyx normally realizes lower spreads than from gas transportation. Revenues from oil and gas sales increased $625,000 in 1994 as compared to 1993, primarily as a result of the revenues attributable to the acquired New Mexico properties (effective April 1, 1994). Oil production in 18 1994 increased to 281,000 barrels as compared to 159,000 barrels in 1993, resulting in a $2,114,000 increase in sales. The average price received for oil was $16.18 in 1994 as compared to $17.36 in 1993, resulting in a $332,000 decrease in sales. The New Mexico properties contributed additional volumes of 142,000 barrels and 856,000 Mcf in 1994. Gas production in 1994 decreased to 2,489,000 Mcf as compared to 3,851,000 in 1993, resulting in a $1,889,000 decrease in sales. The decrease in gas production is primarily the result of the RRC's interim order in May 1993 suspending the sale of bonus gas production allowables from the Keystone Ellenburger field until February 1995. The average price received for gas was $1.67 in 1994 as compared to $1.39 in 1993, resulting in a $715,000 increase in sales. The average price of gas, excluding certain production payment volumes and a gas swap contract loss was $1.75 in 1993. Lease operating expenses ("LOE") related to oil and gas properties decreased $764,000 in 1994 as compared to 1993. As a result of the RRC's interim order noted above the Company has capitalized its costs associated with the formation water recovery and natural gas reinjection program in the Keystone. The Company deferred $3,190,000 of these costs in 1994. LOE related to the acquired New Mexico properties was $1,030,000. Lifting costs per equivalent barrel decreased to $5.07 in 1994 as compared to $5.35 in 1993, primarily as a result of capitalizing the Keystone water lifting costs for the full year in 1994 whereas these costs were only capitalized from June through December in 1993. The $1,484,000 increase in exploration expense is due to 3-D seismic programs that the Company is undertaking in West Texas and the Panhandle of Texas. Current developments in the industry employ the use of new sophisticated seismic shoots and extensive computer modeling evaluation of this data to locate specific drilling objectives. While the industry's expectations are that ultimately this will limit exploration risks and make exploration efforts more deliberate, this new technology is expensive. Accounting literature clearly calls for identification of these costs as geological and geophysical expenses and, accordingly, must be expensed as incurred. While this mandate is severe on the early operations of such exploration programs, these targeted costs must be expensed as incurred. Depletion, depreciation and amortization increased $811,000 in 1994 primarily as a result of the New Mexico operations. General and administrative expenses increased $407,000 in 1994 as compared to 1993 reflecting the increased pipeline operations. Net interest expense increased $1,481,000 as a result of the increased outstanding bank debt during most of 1994 as compared to 1993, until the consummation of the Placement in October 1994. 19 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ARCH PETROLEUM INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Page ---- Report of Independent Accountants..................................... 21 Consolidated Balance Sheets at December 31, 1995 and 1994............. 22 Consolidated Statements of Operations for years ended December 31, 1995, 1994 and 1993.............................................. 24 Consolidated Statements of Changes in Shareholders' Equity for years ended December 31, 1995, 1994 and 1993..................... 25 Consolidated Statements of Cash Flows for years ended December 31, 1995, 1994 and 1993.............................................. 26 Notes to Consolidated Financial Statements............................ 27 Unaudited Quarterly Financial Data.................................... 43 Unaudited Supplemental Oil and Gas Disclosures........................ 44 Index to Exhibits..................................................... 50
All other schedules and compliance information are omitted since 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 the notes thereto. 20 REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders and Board of Directors of Arch Petroleum Inc. In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Arch Petroleum Inc. and its subsidiaries at December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. Price Waterhouse LLP Fort Worth, Texas March 20, 1996 21 ARCH PETROLEUM INC. CONSOLIDATED BALANCE SHEETS
December 31, December 31, 1995 1994 ------------ ------------ ASSETS Current Assets: Cash and cash equivalents $ 2,574,000 $ 1,553,000 Accounts receivable - trade 6,986,000 6,429,000 Accounts receivable - related parties - 1,815,000 Prepaid expenses and other 542,000 635,000 ----------- ----------- Total current assets 10,102,000 10,432,000 Property and Equipment, at cost: Oil and gas properties accounted for by successful efforts method 66,375,000 61,145,000 Natural gas pipelines 11,448,000 11,184,000 Furniture, fixtures and other equipment 957,000 899,000 ----------- ----------- 78,780,000 73,228,000 Less accumulated depletion, depreciation and amortization 12,968,000 8,371,000 ----------- ----------- Net property and equipment 65,812,000 64,857,000 Accounts receivable - related parties 939,000 - Notes receivable - related parties 1,645,000 1,412,000 Other 1,174,000 1,324,000 ----------- ----------- $79,672,000 $78,025,000 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 22 ARCH PETROLEUM INC. CONSOLIDATED BALANCE SHEETS
December 31, December 31, 1995 1994 ------------- ------------- LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable $ 9,552,000 $ 8,604,000 Accounts payable - related parties 75,000 1,375,000 Current maturities of long-term debt 1,111,000 1,111,000 Preferred stock dividends payable 311,000 311,000 ----------- ----------- Total current liabilities 11,049,000 11,401,000 Deferred revenue 16,037,000 20,690,000 Long-term debt, less current maturities 17,821,000 9,632,000 Convertible subordinated notes 5,000,000 5,000,000 Deferred federal income taxes 1,711,000 1,797,000 Minority interest in consolidated subsidiaries 459,000 15,000 Exchangeable convertible preferred stock, $.01 par value, 727,273 shares authorized, issued and outstanding 20,000,000 20,000,000 Shareholders' Equity: Preferred stock, $.01 par value, 1,000,000 shares authorized, 727,273 issued as exchangeable convertible preferred stock - - Common stock, $.01 par value, 50,000,000 shares authorized, 17,141,404 and 17,186,404 shares issued and outstanding, respectively 172,000 172,000 Additional paid-in capital 5,944,000 5,809,000 Employee notes for stock purchases (965,000) (905,000) Treasury stock, 100,000 and none, respectively (206,000) - Retained earnings 2,650,000 4,414,000 ----------- ----------- 7,595,000 9,490,000 Commitments and contingencies (Note 11) $79,672,000 $78,025,000 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 23 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, --------------------------------------- 1995 1994 1993 ------------ ------------ ----------- REVENUES: Oil and gas sales $16,379,000 $ 8,730,000 $ 8,105,000 Pipeline sales 49,249,000 73,525,000 35,572,000 Drilling and production overhead fees 220,000 203,000 249,000 Interest and other 742,000 238,000 222,000 ----------- ----------- ----------- 66,590,000 82,696,000 44,148,000 COSTS AND EXPENSES: Oil and gas lease operations 7,176,000 3,527,000 4,291,000 Natural gas purchases and pipeline operations 46,859,000 72,665,000 33,732,000 Exploration 898,000 1,641,000 157,000 Depletion, depreciation and amortization 5,389,000 2,907,000 2,096,000 General and administrative 4,208,000 3,617,000 3,210,000 Interest 1,865,000 1,634,000 153,000 Minority interest in income (loss) of consolidated subsidiaries 445,000 (524,000) 333,000 ----------- ----------- ----------- 66,840,000 85,467,000 43,972,000 ----------- ----------- ----------- Income (loss) before income taxes and dividends (250,000) (2,771,000) 176,000 Deferred federal income tax benefit (86,000) (941,000) - ----------- ----------- ----------- Net income (loss) (164,000) (1,830,000) 176,000 Dividends on preferred stock 1,600,000 311,000 - ----------- ----------- ----------- Net income (loss) available to common shareholders $(1,764,000) $(2,141,000) $ 176,000 =========== =========== =========== Net income (loss) available per common share $(0.10) $(0.12) $0.01 =========== =========== =========== Weighted average common and common equivalent shares outstanding 17,195,000 17,244,000 17,142,000 =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 24 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Years Ended December 31, 1995, 1994 and 1993
Additional Common Common Paid-in Retained Shareholders' Shares Stock Capital Earnings Equity ----------- ----------- ----------- ------------ -------------- Balance - December 31, 1992 8,305,924 $ 83,000 $5,307,000 $ 6,465,000 $11,855,000 Exercise of stock options 379,800 4,000 746,000 - 750,000 Purchases of stock for employee notes - - (501,000) - (501,000) Purchase of treasury shares (94,800) (1,000) (474,000) - (475,000) Cash distributions to minority interests in subsidiary - - - (86,000) (86,000) Two-for-one stock split 8,590,924 85,000 (85,000) - - Interest on employee notes - - (40,000) - (40,000) Net income - - - 176,000 176,000 ---------- ---------- ---------- ----------- ----------- Balance - December 31, 1993 17,181,848 171,000 4,953,000 6,555,000 11,679,000 Exercise of stock options 4,556 1,000 8,000 - 9,000 Preferred stock dividends - - - (311,000) (311,000) Interest on employee notes - - (57,000) - (57,000) Net loss - - - (1,830,000) (1,830,000) ---------- ---------- ---------- ----------- ----------- Balance - December 31, 1994 17,186,404 172,000 4,904,000 4,414,000 9,490,000 Preferred stock dividends - - - (1,600,000) (1,600,000) Purchase of treasury shares (100,000) - (206,000) - (206,000) Issue common stock as compensation 30,000 - 60,000 - 60,000 Issue common stock for interest in subsidiary 25,000 - 75,000 - 75,000 Repayment of employee note receivable - - 14,000 - 14,000 Interest on employee notes - - (74,000) - (74,000) Net loss - - - (164,000) (164,000) ---------- ---------- ---------- ----------- ----------- Balance - December 31, 1995 17,141,404 $172,000 $4,773,000 $ 2,650,000 $ 7,595,000 ========== ========== ========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 25 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ------------------------------------------ 1995 1994 1993 ------------ ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ (164,000) $ (1,830,000) $ 176,000 Adjustments to reconcile to net cash provided (used) by operations: Depletion, depreciation and amortization 5,389,000 2,907,000 2,096,000 Deferred taxes (86,000) (941,000) - Deferred revenue (3,457,000) (235,000) (1,498,000) Interest on notes receivable and other (198,000) (133,000) (69,000) Issue common shares for compensation 35,000 - - Minority interest in net income (loss) of consolidated subsidiaries 445,000 (524,000) 333,000 Change in accounts receivable 319,000 (673,000) (5,320,000) Change in other current assets 93,000 (317,000) (91,000) Change in accounts payable and other current liabilities (352,000) 1,491,000 5,479,000 Production payment remedy adjustment (1,196,000) (574,000) (281,000) ----------- ------------ ------------ Net operating cash flows 828,000 (829,000) 825,000 ----------- ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (6,088,000) (27,443,000) (11,599,000) Notes receivable and other assets (101,000) (15,000) (1,358,000) ----------- ------------ ------------ Net investing cash flows (6,189,000) (27,458,000) (12,957,000) ----------- ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from bank borrowings 11,800,000 32,921,000 6,500,000 Proceeds from preferred stock sale - 20,000,000 - Proceeds from subordinated debt sale - 5,000,000 - Payments of bank debt (3,612,000) (28,678,000) - Debt issue costs - (916,000) - Proceeds from exercise of stock options - 8,000 249,000 Purchase of treasury shares from related party (206,000) - (475,000) Preferred stock dividends (1,600,000) - - Cash distributions to minority interests in subsidiary - (74,000) (86,000) ----------- ------------ ------------ Net financing cash flows 6,382,000 28,261,000 6,188,000 ----------- ------------ ------------ Change in cash and cash equivalents 1,021,000 (26,000) (5,944,000) Cash and cash equivalents at beginning of period 1,553,000 1,579,000 7,523,000 ----------- ----------- ------------ Cash and cash equivalents at end of period $ 2,574,000 $ 1,553,000 $ 1,579,000 =========== =========== ============
The accompanying notes are an integral part of these consolidated financial statements. 26 ARCH PETROLEUM INC. Notes to Consolidated Financial Statements 1. SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION: Arch Petroleum Inc., a Delaware corporation, (together with its subsidiaries,"the Company") primarily engages in oil and natural gas exploration, development, production, transportation and marketing in the Southwestern United States. Arch is also active in the acquisition of interests in oil and gas leases, both producing and non-producing. Threshold Development Company ("TDC"), an oil and gas exploration company, owns approximately 16.5% of the Company's common stock as of December 31, 1995. TDC's two majority shareholders are also officers and directors of the Company. See Note 14 for acquisition of Canadian subsidiary effective February 20, 1996. On January 31, 1995, the Company's shareholders, in a special meeting, approved an amendment to the Company's articles of incorporation whereby the number of authorized shares of the Company's capital stock was increased from 26,000,000 shares to 51,000,000 shares. Common stock is designated for 50,000,000 shares and preferred stock is designated for the remaining 1,000,000 shares. The Company has reserved 9,090,909 shares of common stock for issuance upon conversion of the securities in the Placement (see Note 7), if necessary, and has also reserved 361,690 shares of common stock for issuance upon exercise of options under its current incentive stock option plan. SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid for interest was $1,466,000, $1,638,000 and $83,000 during 1995, 1994, and 1993, respectively. Cash paid for income taxes was $60,000 during 1993. During 1995 and 1994 the Company paid no income taxes. BASIS OF CONSOLIDATION: The consolidated financial statements include the accounts of the Company and its subsidiaries: Arch Production Company, wholly-owned; Saginaw Pipeline Company, L.C. ("Saginaw") and Industrial Natural Gas, L.C. ("ING"), 95% membership interest; and Onyx Pipeline Company, L.C., Onyx Gathering Company, L.C. and Onyx Gas Marketing Company, L.C. (all together, "Onyx"), 50% membership interest. All significant intercompany balances and transactions are eliminated. REVENUE RECOGNITION: The Company recognizes revenues as quantities of oil and gas are sold or volumes of gas are transported, and utilizes the entitlement method of accounting for oil and gas imbalances. Under this method the oil and gas segment recognizes revenue for its proportionate share of volumes sold. Any over-produced amount is recorded as deferred revenue and any under-produced amount is recorded as current revenue and revenue receivable. The Company had no significant over or under-produced positions as of December 31, 1995 and 1994. The natural gas pipeline segment also utilizes the entitlement method, recognizing a receivable or payable for over or underdelivered volumes, as applicable. As of December 31, 1995 and 1994, the Company had net imbalance receivables of $192,000 and $41,000 respectively. 27 CASH AND CASH EQUIVALENTS: Cash and cash equivalents consist of cash in banks and cash investments in immediately available interest bearing accounts. PROPERTY AND EQUIPMENT: The Company follows the successful efforts method of accounting for costs incurred in oil and gas exploration and development operations, all of which are conducted in the United States. Under this method, the Company capitalizes all costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells which discover proved reserves, and to drill and equip development wells. Exploration costs, including geological and geophysical costs, delay rentals and exploratory dry holes, are charged to expense when incurred. The Company does not capitalize internal costs such as salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties or any other directly identifiable general and administrative costs associated with such activities. Under the successful efforts method all costs capitalized are aggregated on an area basis and depleted using the units-of-production method based upon proved reserves as estimated by independent petroleum engineers. Capitalized costs are evaluated at least annually to determine whether their net book value has been impaired; where permanent impairment is indicated, a loss is recognized as additional depletion expense. Interest is capitalized in accordance with the guidelines established in SFAS No. 34, "Capitalization of Interest Cost", during the periods of drilling (or preparation for drilling) and completing of wells or construction of natural gas pipelines. Interest of $32,000, $127,000, and $21,000 was capitalized for the years ended December 31, 1995, 1994 and 1993, respectively. Costs of unproved properties that are individually significant are evaluated at least annually for impairment of net book value. Costs of proved properties that are abandoned or retired are charged against accumulated reserves for depreciation, depletion and amortization for their respective area and a loss is recognized to the extent of any excess. Depreciation of property and equipment, other than oil and gas properties but including natural gas pipelines, is determined on the straight-line method using estimated useful lives, which vary from two to thirty years. Maintenance and repairs are charged to expense; renewals and betterments are capitalized. Upon sale or retirement of depreciable assets other than proved oil and gas properties, the cost and related accumulated depreciation are removed from the accounts, and the resulting gain or loss is included in operations. KEYSTONE ELLENBURGER FIELD In May 1993 the Railroad Commission of Texas ("RRC") amended the field rules regarding formation water production in the Keystone Ellenburger Field ("Keystone") in Winkler County, Texas. Subsequent to this ruling and until February 1995 the Company produced approximately 18.9 million barrels of formation water, thus earning and accumulating a bonus production allowable of approximately 9.5 million Mcf of natural gas. As a result, the Company incurred high water lifting costs without realizing the related natural gas revenues during this period. 28 Effective February 1, 1995 to October 31, 1995, the RRC amended its interim order and established a system of field-wide allowables which allowed the Company to produce and sell approximately 20.2 million cubic feet (16.0 million, net) of natural gas per day from its operated leases in Keystone. The Company continues to produce approximately 15,000 barrels of formation water per day. Concurrent with the implementation of the new field rules, the Company ceased to capitalize water lifting program costs and commenced amortization of the deferred water production costs as the bonus production allowable is produced. At December 31, 1995 and 1994, the Company had deferred $5.1 million and $5.6 million, respectively, of net water production costs. These costs have been included in proved oil and gas properties. During 1995 the Company amortized approximately $0.6 million of the deferred water production costs. The water lifting program costs that have been capitalized arise from the recovery, transportation and re-injection of formation water in Keystone. The most significant costs are the following: rental of submersible electric pumps used to produce the formation water, electricity to power the submersible pumps and above-ground injection pumps, water disposal facilities and pipelines. The wells in the water lifting program, as well as the water disposal facilities used to collect and transport the water, are used exclusively for the lifting and reinjection of formation water and are specifically identified by the Company. The water lifting program was encouraged by the RRC to enhance future recovery of oil and gas. HEDGING ACTIVITIES: In 1993 the Company entered into a natural gas swap transaction ("hedge") to reduce the impact of historically volatile natural gas spot market prices during the spring and summer months. The contract volume was 10,000 MMBtu per day for the period April 1, 1993 to August 31, 1993. This agreement involved the cash settlement of the differential between the contract price paid to the Company and the average NYMEX natural gas futures contract price at each settlement date. Due to the higher than expected gas futures prices in 1993, the Company suffered a loss on this contract of $784,000 which has been included as a reduction of oil and gas sales in the consolidated statements of operations. The Company has not historically entered into hedging contracts. There were no material contracts entered into in 1995 and 1994. NET INCOME AVAILABLE PER COMMON SHARE: Net income available per common share is computed by dividing net income (loss) available to common shareholders (net income (loss) reduced by dividends on convertible preferred stock; if applicable), by the weighted average number of common shares outstanding for each period including common stock equivalents, if dilutive. Common stock equivalents consist of stock options. The exchangeable convertible preferred stock and convertible subordinated notes are included under the "if converted" method for fully diluted computational purposes. Fully diluted net income (loss) per share is not presented since it is anti-dilutive. INCOME TAXES: The Company accounts for income taxes under Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes". SFAS No. 109 requires the use of the liability method for computing deferred income taxes and allows the recognition of deferred tax assets for deductible temporary differences and carryforwards. The standard also provides valuation allowances for the amount of tax assets not expected to be realized. 29 NEW ACCOUNTING STANDARDS: In March 1995 the FASB issued FAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("FAS 121"), which is effective for fiscal years beginning after December 15, 1995. Effective January 1, 1996, the Company will adopt FAS 121 which requires that long-lived assets (i.e, property, plant and equipment) held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the net book value of the asset may not be recoverable. An impairment loss will be recognized if the sum of the expected future cash flows (undiscounted and before interest) from the use of the asset is less than the net book value of the asset. The amount of the impairment loss will be measured as the difference between the net book value of the assets and the estimated fair value of the related assets. FAS 121 requires that assets be grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other group of assets. The Company does not expect any material impact upon adoption of FAS 121 in the first quarter of 1996. In October 1995, the FASB issued FAS No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), which is effective for fiscal years beginning after December 15, 1995. Effective January 1, 1996, the Company will adopt FAS 123 which establishes financial accounting and reporting standards for stock-based employee compensation plans. The pronouncement defines a fair value based method of accounting for an employee stock option or similar equity instrument. However, it also allows an entity to continue to measure compensation cost for those plans using the intrinsic value based method of accounting as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25"). Entities electing to remain with the accounting as prescribed by APB 25 must make pro forma disclosures of net income and earnings per share as if the fair value based method of accounting defined in FAS 123 had been applied. The Company will continue to account for stock-based employee compensation plans under the intrinsic method pursuant to APB 25 and will make the disclosures in its footnotes as required by FAS 123. PERVASIVENESS OF ESTIMATES: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that effect the reported amounts of assets and liabilities, and related revenues and expenses, and disclosure of gain and loss contingencies at the date of the financial statements. Actual results could differ from those estimates. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS: SFAS No. 107 "Disclosures about Fair Value of Financial Instruments" requires the disclosure of the estimated fair value of financial instruments. The estimated fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. Unless otherwise noted, the estimated fair values of the Company's financial instruments approximate their carrying value. Exchangeable convertible preferred stock and convertible subordinated notes: In determining the estimated fair value of the Preferred Stock and Notes, the Company used market-based prices of similar securities recently traded. The estimated fair value of the Preferred Stock was $18.8 million at December 31, 1995, and $20.0 million at December 31, 1994, as compared with the carrying value of $20.0 million at December 31, 1995 and 1994, respectively. The estimated fair value of the Notes was $4.7 million at December 31, 1995 and $5.0 million at December 31, 1994, as compared to the carrying value of $5.0 million at December 31, 1995 and 1994, respectively. 30 RECLASSIFICATION: Certain amounts in prior years have been reclassified to conform to classifications adopted in 1995. CONCENTRATION OF CREDIT RISK: The Company is exposed to credit risk with respect to receivables and related party receivables from entities associated and involved with the oil and gas industry. 2. PROPERTY AND EQUIPMENT A summary of property and equipment is as follows:
December 31, December 31, 1995 1994 ------------ ------------ Oil and gas properties: Unproved properties $ 958,000 $ 849,000 Proved properties 65,417,000 60,296,000 ----------- ----------- 66,375,000 61,145,000 Less accumulated depreciation and depletion of proved properties 11,658,000 7,526,000 ----------- ----------- Net oil and gas properties 54,717,000 53,619,000 Natural gas pipelines 11,448,000 11,184,000 Less accumulated depreciation 786,000 426,000 ----------- ----------- Net natural gas pipelines 10,662,000 10,758,000 Furniture, fixtures and other equipment 957,000 899,000 Less accumulated depreciation 524,000 419,000 ----------- ----------- Net furniture, fixtures and other equipment 433,000 480,000 ----------- ----------- Net property and equipment $65,812,000 $64,857,000 =========== ===========
3. PURCHASES OF PROPERTIES There were no significant purchases of oil and gas properties in 1995. On March 31, 1994, the Company consummated an agreement with Chevron U.S.A. Inc. to purchase certain oil and gas properties for a cash consideration of $17,900,000. The Company financed the purchase price through its revolving credit facility. The properties, located in Lea County, New Mexico, include interests in approximately 130 producing oil and gas wells. The Company operates and has a significant working interest in the majority of these properties. The effective date of the purchase was April 1, 1994. The Company has accounted for this acquisition as a purchase and operations from the properties have been included in the accompanying consolidated statements of operations since April 1, 1994. The following unaudited pro forma information has been prepared as if the acquisition had occurred at the beginning of each period presented, and is provided for comparative purposes only. The pro forma information presented is not necessarily indicative of the combined financial results and the combined financial position as they may be in the future or as they might have been for the periods or as of the dates indicated had the acquisition been consummated at the beginning of such periods. 31
Year Ended December 31, ------------------------ 1994 1993 -------- ------- (In thousands except per share data) Total consolidated revenues $83,757 $49,393 Net income (loss) (1,695) 1,128 Net income (loss) available per common share $ (0.12) $ 0.07
4. ACQUISITION OF NATURAL GAS PIPELINES In January 1993 the Company acquired a 50% membership interest in Onyx. Onyx owns four pipelines (approximately 25 miles) which supply natural gas to four electric power plants owned by Central Power and Light ("CPL") in Nueces, Hidalgo, Webb and San Patricio Counties, in South Texas. Onyx's contract with CPL includes a provision for a portion of the base load to the four plants. Onyx also competes to supply additional quantities of gas which the plants require. In January 1994 Onyx was awarded a contract by CPL to supply natural gas to an electric power plant located in Webb County, Texas into 1999. Onyx also owns other pipelines, including approximately 40 miles of gathering systems. In conjunction with the acquisition and construction of pipelines, the Company has loaned to Onyx through December 31, 1995, $6,614,000 (of which $1,131,000 was loaned in 1995) including accrued interest. Onyx has repaid the Company $4,412,000 (of which $369,000 was paid in 1995) of those loan advances including interest as of December 31, 1995. At December 31, 1995, Onyx's loan balance to the Company was $2,021,000. In July 1992 the Company, in conjunction with Central States Energy Corporation ("CSE"), formed Saginaw and ING. Concurrent with this event, Saginaw acquired a 6" pipeline that extends approximately 100 miles from Wichita Falls, Texas to Saginaw, Texas. ING was formed to market the sales and transmission of natural gas through the Saginaw pipeline. The Company initially received a 47.5% membership interest in Saginaw and ING. Effective January 1, 1993, the Company's interest increased to 75% in both Saginaw and ING. On September 27, 1995, the Company resolved a membership interest dispute with CSE. The Company issued $45,000 and 25,000 shares of the Company's unissued common stock to CSE. As a result of this transaction, the Company now owns a 95% membership interest in Saginaw and ING. 5. VOLUMETRIC PRODUCTION PAYMENT AND DEFERRED REVENUE On November 30, 1992, the Company closed the sale of a volumetric production payment to Enron Reserve Acquisition Corp. ("Enron") for $24,300,000. The Company contracted to deliver to Enron the equivalent of approximately 17.9 Bcf of natural gas from a certain property in Winkler County, Texas beginning December 1, 1992. The Company is responsible for all costs of production, development and marketing of this dedicated gas. The sale was recorded as deferred revenue in 1992, net of transaction fees. The Company recognizes deferred revenue from the production payment as deliveries of production are made. The Company recognized deferred revenues related to the production payment of $3,457,000, $235,000 and $1,779,000 during 1995, 1994 and 1993 respectively. The Company remitted $1,196,000, $574,000 and $281,000 to Enron during 1995, 1994 and 1993, respectively in satisfaction of the Remedy Adjustment discussed below. Gas was delivered to Enron from December 1992 through May 1993 in full satisfaction of the delivery schedule which is part of the production payment agreement. As discussed in Note 1, the interim ruling in May 1993 by the RRC related to this field reduced the volumes of natural gas that all operators, including the Company, could remove from the reservoir and, accordingly, reduced the volumes of natural gas that the Company had available to deliver to Enron in satisfaction of the production payment agreement. This created a delay in the scheduled volume deliveries during the period May 1993 to January 1995. The agreement with Enron provides a mechanism to remedy 32 both under and over delivery of production payment volumes. The under deliveries (volume delivery delays) on production payment volumes are converted into a dollar obligation ("Remedy Adjustment") which is calculated on a monthly basis by multiplying the deficient volumes by the market price of the gas at the end of the month. This Remedy Adjustment is satisfied by the dedication of a portion of the proceeds from oil and casing head gas production and the future proceeds from gas produced from the reservoir in excess of the future scheduled production payment volumes. All of the dedicated gas in the production payment is confined to Company operated properties in Keystone. The original delivery schedule has not been extended or amended. At December 31, 1995, the estimated remaining volumes deliverable to Enron under the production payment agreement were 11.9 Bcf of natural gas (including 3.6 Bcf of natural gas attributable to volume delivery delays resulting from field rule changes in prior periods). These gas reserves dedicated to Enron are excluded from the Undaudited Supplemental Oil and Gas Disclosures herein. Effective February 1, 1995 through October 31, 1995, the RRC amended its interim order issued in May 1993 and implemented a system of field-wide allowables which allowed the Company to fully meet its scheduled delivery of volumes under the production payment agreement and reduce the Remedy Adjustment. However, effective November 1, 1995, the RRC once again restricted the allowables thereby impeding the Company's ability to meet its scheduled deliveries. During 1996 the Company anticipates the RRC to establish allowables for Keystone which will allow the Company to sell approximately 10.1 million cubic feet of natural gas per day from its operated leases in Keystone. However, there can be no assurance that the RRC will issue orders which would allow production to resume at a rate to meet scheduled deliveries and reduce the Remedy Adjustment. The amount of volumes, if any, which will be necessary to satisfy the Remedy Adjustment is dependent upon future gas prices. Based upon economics at December 31, 1995, the Company may deliver approximately 1.4 Bcf of natural gas volumes in excess of the original contracted delivery volumes in this regard. As of December 31, 1995, the estimated annual amortization of the remaining deferred revenue, based on contracted deliveries under the production payment agreement, is expected to be as follows: 1996 $ 6,819,000 1997 6,635,000 1998 2,583,000 ----------- $16,037,000 ===========
6. LONG-TERM DEBT TO BANKS A summary of long-term debt to banks is as follows:
December 31, ------------------------ 1995 1994 ----------- ----------- Bank credit facilities $18,932,000 $10,743,000 Less current maturities 1,111,000 1,111,000 ----------- ----------- $17,821,000 $ 9,632,000 =========== ===========
Maturities of long-term bank debt are as follows (excluding maturity of Company's Revolver which matures in 1997 but is expected to be extended): 1996 - $1,111,000 (included in current liabilities), 1997 -$1,111,000, 1998 - $1,111,000 and 1999 - $278,000. 33 The Company's revolving credit facility (the "Revolver"), which the Company entered into on April 6, 1990, (last amended on September 27, 1995 by the third amendment to the Second Restated Revolving Credit Loan Agreement dated March 31, 1994) is in place for use by the Company at its discretion including drilling, development and acquisition of oil and gas properties. The Bank of Scotland participates with Bank One, Texas. N.A., the lead bank, in the Revolver. The Company has borrowed $15,321,000 against the Revolver at December 31, 1995. The Revolver borrowing base is the amount that the bank commits to loan to the Company based on the designated loan value established by the lead bank at its sole discretion and assigned to substantially all of the Company's oil and gas properties which serve as collateral for any loan which may be outstanding under the Revolver. The Revolver facility is $50,000,000 and the borrowing base is currently $30,000,000. The borrowing base is reviewed semiannually by the lead bank at its discretion. A commitment fee of one half of one percent of the unused borrowing base accrues and is payable quarterly. Borrowings under the Revolver will, at the Company's option, bear interest either at the lead bank's Base Rate (national prime rate) or a rate based on the London Interbank Offered Rate (LIBOR). The LIBOR rate is increased by an additional margin of 1.75% to 2.50% based on the ratio of total outstanding revolver debt to the borrowing base (1.75% if ratio is less than 25%, 2.00% if ratio is more than 25% but less than 50%, 2.25% if ratio is more than 50% but less than 75% and 2.50% if ratio is greater than 75%). The average actual interest rate was 8.0% at December 31, 1995. Interest is payable monthly and no principal payments are required until maturity, which is May 1997. The Onyx Term Loan Agreement (the "Onyx Note"), which Onyx entered into with the Bank of Scotland on March 30, 1994, as amended, is a separate facility and provided Onyx with $5,000,000. The Onyx Note bears interest at national prime rate plus one-half of one percent (9.0% at December 31, 1995). Interest on the unpaid principal amount of the note is payable quarterly and commenced on June 30, 1994. The unpaid principal ($3,611,000 at December 31, 1995), is payable in eighteen quarterly installments ending on March 31, 1999. Current maturities of the Onyx Note total $1,111,000 at December 31, 1995. The Onyx Note is collateralized by certain of Onyx's pipelines, gathering facilities and related transportation contracts. In addition, the Onyx Note is guaranteed by the Company. Both the Revolver and Onyx Note contain normal and standard covenants generally found in lending agreements. Among other things, these covenants prohibit the declaration and payment of cash dividends on the Company's common stock. In addition, the covenants stipulate the maintenance of financial criteria including: a minimum level of net worth, a certain current ratio, a certain debt to net worth ratio and a defined net income in excess of scheduled interest and principal payments. The Company and Onyx are currently in compliance with the loan agreements. Neither the Company nor Onyx has any other unused lines of credit. See Note 15 for discussion of new credit facilities entered into as of February 20, 1996. 7. EXCHANGEABLE CONVERTIBLE PREFERRED STOCK AND CONVERTIBLE SUBORDINATED NOTES On October 20, 1994, the Company sold the following securities to four institutional investors (the "Investors") in a private placement (the "Placement"): (a) 727,273 shares of its 8% Exchangeable Convertible Preferred Stock (the "Preferred Stock"), $0.01 par value, having an aggregate liquidation preference of $20,000,000, (b) $500,000 aggregate principal amount of its 9.75% Series A Convertible Subordinated Notes due 2004 (the "Series A Notes") and (c) $4,500,000 aggregate principal amount of its Adjustable Rate Series B Notes due 2004 (the "Series B Notes" and, together with the Series A Notes, the "Notes"). The Series B Notes currently bear interest at an annual rate of 9.75%. Gross proceeds from the Placement were $20,000,000 for the Preferred Stock and $5,000,000 for the Notes. The proceeds were used to pay down the Company's Revolver with Bank One, Texas, N.A. and the Bank of Scotland. The Company incurred $916,000 of debt issuance costs related to the Placement, which is being amortized over the period the Preferred Stock 34 and Notes are outstanding. The Preferred Stock accrues annual dividends at the rate of $2.20 per share and the dividends are cumulative. Dividends are payable April 20 and October 20 of each year. During 1995 the Company paid $1,600,000 in dividends on the Preferred Stock. If dividends remain unpaid for more than one semiannual period, the holders of the Preferred Stock have the right to elect two additional directors to the Company's board of directors until such time that all cumulative dividends have been paid. The Preferred Stock has a liquidation preference of $27.50 per share and is exchangeable in whole at the option of the Company, for its 10.563% Series C Convertible Subordinated Notes due 2004 (the "Series C Notes"). The Series C Notes possess attributes similar to the Series A Notes, except for the higher rate of interest associated with the Series C Notes. The Preferred Stock is exchangeable on April 20 and October 20 of each year. After October 20, 1998, and upon the achievement of certain stated objectives for the market price of its common stock, the Company earns the right to require the conversion of all of the Preferred Stock and the Notes into common stock of the Company. The market price objectives are as follow: after August 20, 1998, the closing price of the Company's common stock on the NASDAQ National Market System, or similarly recognized system, must list for a period of sixty consecutive trading days at a price equal to or greater than 125% of a certain target price. The target price ranges from $2.837 at October 20, 1998 to $2.764 at October 20, 2003. Each share of Preferred Stock is convertible, at any time at the option of the holder thereof, into shares of common stock of the Company, par value $0.01 per share, at a price of $2.75 per share. Based on the number of shares (17,141,404) of the Company's common stock outstanding at December 31, 1995, if all the Preferred Stock and Notes were converted into common stock of the Company, 26,232,313 shares of common stock would be outstanding. Upon such conversion the institutional investors, being Travelers, Travelers Life, Connecticut General and CIGNA Mezzanine would own 16.6%, 4.2%, 4.9% and 8.9% of the Company's common stock, respectively. The Preferred Stock entitles each holder to one vote per share on an as converted basis. The vote or consent of at least 66 2/3% (or at least a majority in the event the Investors and their affiliates own less than 66 2/3% of the Preferred Stock and Notes on an as converted basis) of the issued and outstanding shares of Preferred Stock, voting as a separate class, is required for the Company to (a) issue or authorize the issuance of any class or series of equity securities senior to the Preferred stock, (b) change the par value of the Preferred Stock, (c) alter or change the powers, preferences or special rights of the shares of Preferred Stock or any other provision of the Company's Certificate of Incorporation so as to affect the shares of Preferred Stock adversely, (d) merge, consolidate or amalgamate with other person or (e) sell, lease, transfer or otherwise dispose of all or substantially all of the assets of the Company. Interest on the unpaid principal balance of the Notes is payable quarterly and commenced January 20, 1995. During 1995 the Company paid $488,000 in interest on the Notes. The Company has the option at any time on or after October 20, 1998, to prepay the Notes in whole or in part, together with accrued interest, plus the applicable prepayment premium (expressed as a percentage of the principal amount to be prepaid). The prepayment premium ranges from 3.150% at October 20, 1998 to 0.525% at October 20, 2003. On or after October 20, 1998, the Preferred Stock is redeemable, in whole or in part at any time at the option of the Company at redemption prices ranging from $28.366 per share at October 20, 1998 to $27.644 per share at October 20, 2003. On October 20, 2004 all outstanding shares of the Preferred Stock are mandatorily redeemable by the Company at a price of $27.50 plus accrued and unpaid dividends. 35 8. INCOME TAXES Deferred taxes are provided for temporary differences between the financial reporting basis and federal income tax basis of the Company's assets, liabilities and other tax attributes. Deferred tax liabilities and assets are comprised of the following at December 31:
1995 1994 ----------- ---------- Gross deferred tax liabilities: Depreciation, depletion and intangible drilling costs $ 8,755,000 $7,672,000 Volumetric production payment 1,249,000 735,000 ----------- ---------- 10,004,000 8,407,000 Gross deferred tax assets: Net operating loss carryforwards 6,712,000 5,087,000 Statutory depletion carryforwards 888,000 830,000 Alternative minimum tax credit carryforwards 592,000 592,000 Investment tax credit carryforwards 101,000 101,000 ----------- ---------- 8,293,000 6,610,000 ----------- ---------- Deferred federal income taxes $ 1,711,000 $1,797,000 =========== ==========
The provision for income taxes differs from the amount determined by applying the U.S. federal statutory income tax rate to income before income taxes as a result of the following differences:
Year Ended December 31, -------------------------------- 1995 1994 1993 --------- ---------- --------- Provision based upon federal statutory rate $(86,000) $(941,000) $ 60,000 Statutory depletion (53,000) (26,000) (60,000) Other 53,000 26,000 - -------- --------- -------- $(86,000) $(941,000) - ======== ========= ========
At December 31, 1995, the Company has tax benefit carryforwards of approximately $17,899,000, $2,369,000, $592,000 and $101,000 relating to net operating losses, statutory depletion, alternative minimum tax credits and investment tax credits, respectively, which expire at various dates beginning in 1996, except for statutory depletion which does not have an expiration date. 36 9. TRANSACTIONS WITH RELATED PARTIES The Company rents, on an as-needed basis, an aircraft from TDC. Charges for this service are billed to the Company based on time used. Rental charges amounted to $39,000, $20,000 and $25,000 for the years ended December 31, 1995, 1994 and 1993, respectively. With the approval of the board of directors, on April 11, 1995, the Company purchased 100,000 shares of common stock for its treasury from TDC valued at $206,000 at the then current market price. The Board of Directors of the Company authorized notes receivable from key employees and directors in 1991, 1992 and 1993, for purposes of exercising stock options. The notes bear interest at the Revolver interest rate and all of the notes are secured by the stock certificates that were issued upon exercise of the stock options by each employee. The notes mature May 13, 1997. The balances due to the Company in this regard including interest were $962,000 and $905,000 at December 31, 1995 and 1994, respectively. These amounts are offset against equity on the consolidated balance sheet. No new notes were authorized during 1995 and 1994. The Board of Directors of the Company also authorized cash advances to certain officers in 1993 in exchange for notes receivable. These notes also bear interest at the Revolver rate and are secured by stock certificates of the Company owned by those individuals. The notes mature May 13, 1997. The notes, including interest, total $1,645,000 and $1,412,000 at December 31, 1995 and 1994, respectively. Cash advances to officers totalled $115,000 and $15,000 during 1995 and 1994, respectively. The Company recognized interest income on its outstanding notes receivable from officers, directors and key employees of $188,000, $150,000 and $91,000 during 1995, 1994 and 1993, respectively. Onyx has transactions in the ordinary course of business with PURECO and Sejita which each own 25% interests in Onyx. Onyx also has transactions in the ordinary course of business with other companies in which the owners of PURECO and Sejita have ownership interests. The consolidated financial statements include certain amounts and balances that arise from transactions with related parties in the normal course of business. The following table quantifies those transactions.
At December 31, 1995 At December 31, 1994 -------------------- -------------------------------- Accounts Accounts Accounts Accounts Receivable Payable Receivable Payable ---------- -------- ---------- -------------------- TDC, net in 1995 $939,000 $ - $1,746,000 $1,301,000 Libra Marketing - - 2,000 - PURECO - 31,000 9,000 1,000 Puma Resources - - 2,000 5,000 Cedar Energies, Inc. - 44,000 53,000 68,000 Other - - 3,000 - ---------- ------- ---------- ---------- $939,000 $75,000 $1,815,000 $1,375,000 ========== ======= ========== ==========
37
For Year Ended For Year Ended December 31, 1995 December 31, 1994 ------------------- ----------------------------- Purchases Sales Purchases Sales From To From To --------- -------- ---------- ----------------- Libra Marketing $ 5,000 $ - $ 260,000 $ 37,000 PURECO - - 2,523,000 9,000 Cedar Energies, Inc. 239,000 - 394,000 312,000 Puma Resources - 171,000 - 627,000 Sejita Pipeline 8,000 - - - -------- -------- ---------- -------- $252,000 $171,000 $3,177,000 $985,000 ======== ======== ========== ========
Amounts receivable from TDC are classified as long-term and do not accrue interest. The increase in the receivable from TDC in 1995 primarily relates to operations on producing wells jointly owned by the related parties and operated by TDC. TDC receives revenue from the purchase of the oil and gas and pays related LOE and capital costs associated with the wells. Under agreement with TDC in 1995, the Company has the right of offset with TDC. Accordingly, the 1995 TDC balances are presented net in the financial statements. The 1994 TDC balances are presented gross in the financial statements. During 1995 the Company's share of revenue exceeded its share of LOE and capital expenditures on the jointy owned properties by approximately $365,000, accounting for the largest portion of the increase in the net amount due from TDC. All other related party receivables and payables related to the Company's gas marketing and transmission segment. 10. MAJOR CUSTOMERS The following major customers represent 10% or more of total operating revenues by segment for the years ended December 31, 1995, 1994 and 1993:
Oil and Gas 1995 1994 1993 ----------- ----- ----- ----- Chevron U.S.A. Inc. 31% 40% * Enron Gas Marketing 31% * 34%
The Company's principal products are oil and natural gas. The principal market for such products is primarily the Southwestern United States wherein the Company's oil and gas properties are physically located. The methods of distribution of such products are by the sale of such products at the wellhead to appropriate gathering companies operating in the geographic area of production.
Natural Gas Pipelines 1995 1994 1993 --------------------- ----- ----- ----- Central Power and Light 58% 35% 72% Entergy Corp. * 17% * Aquila Southwest Marketing * * 10%
In its natural gas marketing and transmission activities, the Company buys and resells natural gas, receiving a gross margin or spread equal to the difference between the purchase price and the resale price of such natural gas. In addition, the Company receives a fee for transmission of natural gas over pipeline systems owned by the Company. * - Less than 10%. 38 11. COMMITMENTS AND CONTINGENCIES COMMITMENTS: The Company leases office space, office equipment and vehicles under various lease agreements with primary lease terms ranging from three to five years. Rental expense on these leases was $202,000, $215,000, and $175,000 in the years ended December 31, 1995, 1994 and 1993, respectively. Aggregate future minimum rental payments required pursuant to noncancellable leases follow: 1996 - $326,000, 1997 - $192,000, 1998 -$150,000 and 1999 - $127,000. CONTINGENCIES: From time to time the Company is involved in litigation arising in the normal course of business. In the opinion of management, the Company's ultimate liability, if any, from lawsuits currently pending would not materially affect the Company's financial condition or operations. 12. STOCK OPTIONS In the annual meeting of shareholders held on May 27, 1993, the shareholders of the Company approved the Arch Petroleum Inc. 1993 Stock Option plan ("the 93 Plan"). The 93 Plan is an incentive stock option plan under which 1,660,000 shares are reserved for issuance to employees in the ten year period commencing June 1, 1993. The exercise price will be set by the 93 Plan Committee in its best judgement but shall not be less than 100% of the fair market value per share at grant date. On July 7, 1993, the 93 Plan Committee granted 334,000 options at $1.8125 with an expiration date of May 31, 2003, to twenty-three employees. The first third of these options were exercisable six months from grant date and thereafter, an additional third of the options may be exercised each anniversary year after the initial first six months date. During the years ended December 31, 1995, 1994 and 1993, none, 4,556 and none of the options were exercised under the 93 Plan, respectively. During 1995, 50,000 and 25,000 options were granted at $1.8125 and $2.1875, respectively, under the 93 Plan to two employees. These options have expiration dates of March 20, 2000 and May 22, 2000, respectively. Stock option transactions, in the period from December 31, 1993 to December 31, 1995 are summarized below:
Number Option Price of Shares Per Share ---------- -------------------- December 31, 1992 760,000 $0.232 - $ 1.313 Granted 334,000 1.813 Exercised (760,000) 0.232 - 1.313 -------- December 31, 1993 334,000 1.813 Cancelled (37,000) 1.813 Exercised (4,000) 1.813 -------- December 31, 1994 293,000 1.813 Granted 75,000 1.813 - 2.1875 Cancelled (6,000) 1.813 -------- December 31, 1995 362,000 1.813 - 2.1875 ========
39 13. INDUSTRY SEGMENT INFORMATION The Company operates in two industry segments: oil and gas exploration, development and production and natural gas marketing, transportation and distribution. Operating income by segment is defined as revenues less operating expenses. Income and expense items excluded from operating income include: interest income, other income, interest expense, minority interest and income taxes. Identifiable assets are those assets used exclusively in the operations of each business segment. Operating results for the oil and gas segment of the Company are significantly affected by the Company's ability to acquire reserves in the future through the development of existing properties and also its ability to select and acquire suitable prospects for exploratory drilling or development. The buying, selling and transporting of natural gas by the Company's pipeline segment is a highly competitive business. The Company markets natural gas to customers who can purchase natural gas from various suppliers. Marketing of both oil and natural gas is affected in part by domestic production levels, imports, the proximity of pipelines to producing properties and the regulation by states of allowable rates of production. Cash flow from operations for both segments may be affected to a significant degree by fluctuations in prices that are brought on by factors beyond the Company's control. All of these variable factors are dependent on economic and political forces which cannot be accurately predicted in advance. The following table shows industry segment information for the years ended December 31, 1995, 1994 and 1993.
Natural Gas (In thousands) Oil and Gas Pipelines Total ------------ ------------ -------- 1995 Identifiable assets $61,547 $18,125 $79,672 Revenues 16,599 49,249 65,848 Exploration costs and expenses 898 - 898 Depletion, depreciation and amortization 4,973 416 5,389 Operating income 648 670 1,318 Capital expenditures 5,824 264 6,088 1994 Identifiable assets $60,908 $17,117 $78,025 Revenues 8,933 73,525 82,458 Exploration costs and expenses 1,641 - 1,641 Depletion, depreciation and amortization 2,604 303 2,907 Operating loss (1,135) (764) (1,899) Capital expenditures 24,591 2,852 27,443 1993 Identifiable assets $36,139 $14,930 $51,069 Revenues 8,354 35,572 43,926 Exploration costs and expenses 157 - 157 Depletion, depreciation and amortization 1,944 152 2,096 Operating income (loss) (516) 956 440 Capital expenditures 5,902 5,697 11,599
40 14. SUBSEQUENT EVENT - ACQUISITION OF TRAX PETROLEUMS LIMITED Effective January 31, 1996, the Company acquired Trax Petroleums Limited ("Trax"), a Canadian oil and gas exploration and development company headquartered in Calgary, Alberta, Canada. The Company's January 9, 1996, cash offer of Cdn. $0.71 for each of Trax's approximately 14,100,000 shares was accepted by more than 91% of Trax shareholders. Effective February 12, 1996, the Company completed the statutory compulsory acquisition of the remaining shares of Trax through the depository, Montreal Trust Company of Canada. The acquisition of 100% of the common stock of Trax was made through Northern Arch Resources Ltd.("Northern Arch"), a wholly-owned Canadian subsidiary of the Company. The current Trax staff of employees and its headquarters will remain in Calgary. The acquisition purchase price was approximately Cdn. $10,000,000 (approximately US $7,400,000 at January 31, 1996). UNAUDITED --------- Trax's November 30, 1995, oil and gas reserves, as estimated by its independent engineers, totalled 964,000 barrels of oil and 1.38 billion cubic feet of natural gas (1,193,000 BOE). The estimated future net income attributable to these reserves (discounted at 15%) is Cdn. $11,100,000 (approximately US $8,100,000 at January 31, 1996). Estimated daily production currently approximates 600 BOE. In addition to the existing reserve base, Trax holds a large interest in approximately 40,000 net undeveloped acres. This acreage includes more than thirty distinct, high quality prospects which are in various stages of development. 15. SUBSEQUENT EVENT - NEW BANK CREDIT AGREEMENTS On February 20, 1996, the Company entered into two new bank credit facilities: the Third Restated Revolving Credit Loan Agreement among the Company and Bank One, Texas, N.A., the Agent bank, and other banks (the "Domestic Revolver") and through its new 100% - owed subsidiary, Trax, the Credit Agreement among Trax and Bank of Montreal, the Canadian Agent bank, and other financial institutions (the "Canadian Revolver"). The two credit facilities are separate bank revolvers. The lenders in the Domestic Revolver (the "U.S. lenders") and the lenders in the Canadian Revolver (the "Canadian lenders") have entered into an associated Intercreditor Agreement also on February 20, 1996. In this Intercreditor Agreement the Canadian lenders and the U.S. lenders have agreed that they shall rank pari passu with one another in respect of certain payments or recoveries and that certain matters related to the administration of the Canadian Revolver and the Domestic Revolver shall be made on the basis of their combined commitments. Each of the revolvers is described briefly, as follows: THE DOMESTIC REVOLVER --------------------- The Domestic Revolver is a modification of the Company's existing Revolver. The principal change to the former Revolver was the introduction of certain language, terms and concepts such that the Domestic Revolver and the Canadian Revolver will be accommodated in pari passu sharing and general administration. This facility amends, restates and supersedes in its entirety the former Revolver. The facility remains at $50,000,000 and the current borrowing base also remains at $30,000,000. The borrowing base is designated the "U.S. Allocated Borrowing Base" to distinguish it from the related "Canadian Allocated Borrowing Base" contained and described in the Canadian Revolver below. As of the first business day of each calendar quarter (commencing April 1, 1996), the Company may allocate all or any portion of its Consolidated Borrowing Base (the U.S., Domestic Revolver borrowing base plus the Trax properties, Canadian borrowing base, the "CBB") to the Canadian facility provided that such amount shall not be less than the outstanding balance of the Canadian Revolver at that time. The initial allocation of the CBB was $20,000,000 41 to the Domestic Revolver and $10,000,000 to the Canadian Revolver. The Company may select an interest rate option with each borrowing advance between a Floating Base Rate ("FBR") or an Interbank Offered Rate ("IOR"). The FBR is the rate of interest announced from time to time by the Agent bank and usually will track the U.S. national prime rate. The IOR is generally the London interbank market rate. For purposes of the IOR, the effective interest rate occurring will be increased relative to Borrowing Base Percentage ("BBP"), the aggregate of the unpaid principal balance of the Domestic Revolver and the Canadian Revolver to the CBB, as follows: BBP IOR plus --- -------- Less than 25% 1.75% More than 25%, but less than 50% 2.0% More than 50%, but less than 75% 2.25% More than 75% 2.50% There is a commitment fee of one half of one percent for the unused borrowing base which accrues and is payable quarterly commencing April 1, 1996. The Domestic Revolver matures on May 1, 1997. The security collateral requirements and the bank covenants and default provisions are essentially unchanged from the former Revolver. THE CANADIAN REVOLVER --------------------- The Canadian Revolver is similar to the Domestic Revolver in all significant aspects. The loans under the Canadian Revolver are guaranteed by the Company ("the Guaranty") and is secured by, among other things, a first lien on 65% of the issued and outstanding shares of Northern Arch's common stock and a first lien on the oil and gas properties of the Company which serve as security in the Domestic Revolver. The facility's initial commitment is U.S. $11,000,000. The Canadian lenders agree to make revolving credit loans to Trax in one or more advances (U.S. $500,000 minimum, in intervals of U.S. $100,000, "Revolving Loans") of LIBO Rate loans, Prime Rate loans, Base Rate loans and/or purchase Bankers' Acceptances. The various interest rates used in the Canadian Revolver are adjusted for applicable margins based on the ratio of aggregate outstanding balances relative to CBB (similar to the Domestic Revolver) as follows:
Type of Loan CBB Ratio Applicable Margin -------------- ---------------------------------- ----------------- LIBO Rate & BA Less than 25% 1.75% Prime Rate 0.75% LIBO Rate & BA More than 25%, but less than 50% 2.00% Prime Rate 1.00% LIBO Rate & BA More than 50%, but less than 75% 2.25% Prime Rate 1.25% LIBO Rate & BA More than 75% 2.50% Prime Rate 1.50% Base Rate At all times 0.00%
42 The proceeds of each advance may be used to fund additional borrowing base properties, to drill and recomplete oil and gas wells and for general corporate purposes. Repayments shall be made relative to the currency used in each borrowing. The Canadian Revolver matures on May 1, 1997. There is a commitment fee of one half of one percent for the unused borrowing base which accrues and is payable on the first day of each quarter. The Trax borrowing base, which was undetermined at date of closing, is the loan value determined by the Canadian Agent bank in its sole discretion based on its calculations of value of borrowing base properties utilizing current and customary procedures and standards for petroleum industry customers. The Canadian Agent bank is currently studying and evaluating Trax's properties. The cross border allocation of borrowing base procedures described above in the Domestic Revolver are contained in the Canadian Revolver, also, and are referenced to each other in both facilities. UNAUDITED QUARTERLY FINANCIAL DATA (In thousands, except per share amounts) Unaudited quarterly financial data is as follows:
First Second Third Fourth Quarter Quarter Quarter Quarter -------- -------- -------- -------- Year Ended December 31, 1995 - ------------------------------------ Operating revenues $14,047 $16,813 $18,741 $16,989 Exploration costs and expenses 304 19 507 68 Gross profit 898 2,275 1,342 1,753 Net income (loss) (279) 435 (327) 7 Net income (loss) per share (1) $ (0.04) $ - $ (0.04) $ (0.02) Year Ended December 31, 1994 - ------------------------------------ Operating revenues $17,451 $25,510 $26,764 $12,971 Exploration costs and expenses (2) 132 12 14 1,483 Gross profit (loss) (2) 504 860 1,115 (523) Net loss (2) (250) (170) (169) (1,241) Net loss per share (1)(2) $ (0.01) $(0.01) $ (0.01) $ (0.09)
Gross profit represents income before income taxes excluding general and administrative expense, interest expense and minority interest in income (loss) of consolidated subsidiaries. (1) - After dividends on preferred stock. (2) - In the fourth quarter of 1994, the Company expensed $1,452,000 of costs related to a 3-D seismic program performed throughout 1994 on undeveloped acreage in Stonewall County and the Panhandle of Texas. These costs were deferred during the first three quarters of 1994 as the Company was soliciting participation by third parties in these exploration projects and expected to proportionately recover its investment in these properties, plus the 3-D seismic costs incurred, from these potential participants. As of December 31, 1994, an agreement was not completed. Accordingly, the seismic costs were expensed. 43 ARCH PETROLEUM INC. Unaudited Supplemental Oil and Gas Disclosures Estimates of Reserves and Future Production Performance Are Subjective and May Change Materially as Actual Production Information Becomes Available The following table sets forth the proved oil and gas reserves of the Company for the years ended December 31, 1995, 1994 and 1993, and the changes therein. All of the Company's oil and gas activities are located within the United States. None of the Company's reserves are subject to long-term supply agreements with a governmental agency.
Oil Gas Oil and Gas Reserve Quantities (Bbl) (Mcf) - -------------------------------------------- ---------- ----------- PROVED DEVELOPED AND UNDEVELOPED RESERVES: Quantity, December 31, 1992 2,485,200 46,544,900 Extensions and discoveries 29,300 54,000 Production (159,500) (2,277,500) Revisions of previous estimates (769,300) (767,800) --------- ---------- Quantity, December 31, 1993 1,585,700 43,553,600 Purchases of minerals in place 2,675,800 19,840,700 Extensions and discoveries 6,900 5,000 Production (282,300) (1,974,800) Revision of previous estimates (399,700) 121,700 --------- ---------- Quantity, December 31, 1994 3,586,400 61,546,200 Extensions and discoveries 1,126,000 4,138,000 Production (382,100) (4,291,900) Revision of previous estimates (300,100) (106,000) --------- ---------- Quantity, December 31, 1995 4,030,200 61,286,300 ========= ========== PROVED DEVELOPED RESERVES: As of December 31, 1993 1,368,600 41,785,500 As of December 31, 1994 3,390,600 60,666,200 As of December 31, 1995 2,993,600 55,628,500
The Company's proved reserves exclude 11.9 Bcf, 15.5 Bcf and 16.1 Bcf of gas reserves at December 31, 1995, 1994 and 1993, respectively, which were sold under a volumetric production payment to a major gas company in December 1992 for $1.30 per Mcf. The Company is required to deliver this gas production over the next 2.7 years under the terms of the production payment agreement. The revenue associated with these reserves, which is deferred, is recognized as production is delivered. The ultimate quantity of gas to be delivered pursuant to the term of the producion payment agreement may vary from the original contracted amount as discussed in Note 5. 44 Costs Incurred in Oil and Gas Activities - ---------------------------------------- Costs incurred in oil and gas property acquisition, exploration and development activities are set forth below:
Year Ended December 31, ---------------------------------------- 1995 1994 1993 ------------ ------------ ------------ Acquisition of properties: Proved $ 274,000 $ 18,142,000 $ 279,000 Unproved 108,000 590,000 260,000 Exploration 898,000 1,641,000 157,000 Development 4,937,000 5,799,000 5,176,000
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein - ---------------------------------------------------------------------------- Relating to Proved Oil and Gas Reserves - ---------------------------------------
December 31, ---------------------------------------- 1995 1994 1993 ------------ ------------ ------------ Future cash inflows $182,785,400 $163,551,600 $125,914,300 Future production and development costs 66,311,500 54,407,600 46,702,000 Future income tax expenses 22,434,000 22,440,700 18,816,200 ------------ ------------ ------------ Future net cash flows undiscounted 94,039,900 86,703,300 60,396,100 10% annual discount for estimated timing of cash flows 42,127,800 38,182,900 28,606,800 ------------ ------------ ------------ Standardized measure of discounted future net cash flows $ 51,912,100 $ 48,520,400 $ 31,789,300 ============ ============ ============
Future net cash flows were computed using year end prices and costs. For the reserve report as of December 31, 1995, the average prices were $18.82 for oil and $1.76 for gas. As of December 31, 1994, the average prices were $16.02 for oil and $1.74 for gas. As of December 31, 1993, the average prices were $13.38 for oil and $2.13 for gas. The standardized measure of discounted future net cash flows at December 31, 1995, 1994 and 1993, as presented in the table above, excludes future net cash flows associated with the remaining original volumes of gas to be delivered pursuant to the volumetric production payment agreement as described in Note 5. The discounted future net cash flows, before future income tax expenses, related to the volumetric production payment approximates $11,672,700, $12,566,300 and $12,860,100 which amounts are net of discounted future production costs of $1,912,700, $2,557,800 and $3,156,500 at December 31, 1995, 1994 and 1993, respectively. 45 The Company operates in an industry that is subject to volatile prices for its products. The standardized measure of discounted future net cash flows may be affected to a significant degree by fluctuations in prices that are brought on by factors beyond the Company's control. The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31, ---------------------------------------- 1995 1994 1993 ------------ ------------ ------------ Standardized measure of discounted future net cash flows at beginning of period $48,520,400 $31,789,000 $42,133,000 Changes resulting from: Purchases of minerals in place - 28,124,500 - Net changes in prices and costs, exclusive of properties sold 2,736,100 (5,041,400) (9,553,400) Net change in income taxes 174,100 (1,594,000) 3,071,100 Sales of oil and gas produced, net of production costs (6,001,800) (4,364,600) (1,852,000) Revisions of previous quantity estimates (1,464,900) (1,619,800) (3,857,500) Extensions and discoveries, less related costs 9,241,100 73,600 256,200 Changes in estimated future development costs (5,899,500) (237,300) 2,495,900 Development costs incurred previously estimated 740,700 40,200 287,900 Accretion of discount 4,852,000 3,178,900 4,213,400 Timing and other (986,100) (1,828,700) (5,405,600) ----------- ----------- ----------- Standardized measure of discounted future net cash flows at end of period $51,912,100 $48,520,400 $31,789,000 =========== =========== ===========
46 Results of Operations from Oil and Gas Producing Activities - -----------------------------------------------------------
Year Ended December 31, ---------------------------------------- 1995 1994 1993 ------------ ------------ ------------ Revenues $16,599,000 $ 8,933,000 $ 8,354,000 Production costs (7,176,000) (3,527,000) (4,291,000) Exploration expenses (898,000) (1,641,000) (157,000) Depletion, depreciation and amortization (4,973,000) (2,604,000) (1,944,000) ----------- ----------- ----------- 3,552,000 1,161,000 1,962,000 Income tax expense (1,208,000) (395,000) - ----------- ----------- ----------- Results of operations $ 2,344,000 $ 766,000 $ 1,962,000 =========== =========== ===========
47 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY Reference is made to the material under the captions, "Election of Directors" in the Registrant's definitive Proxy Statement to be filed on or about March 22, 1996, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on April 25, 1996, which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Reference is made to the material under the caption, "Compensation of Executive Officers and Directors" in the Registrant's definitive Proxy Statement to be filed on or about March 22, 1996, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on April 25, 1996, which is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is made to the material under the caption, "Outstanding Voting Securities of the Company and Certain Shareholders" in the Registrant's definitive Proxy Statement to be filed on or about March 22, 1996, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on April 25, 1996, which is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is made to the material under the caption "Certain Relationships and Related Transactions" in the Registrant's definitive Proxy Statement to be filed on or about March 22, 1996 , pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on April 25, 1996, which is incorporated herein by reference. 48 PART IV ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K A. Consolidated Financial Statements and Schedules 1. Consolidated Financial Statements --------------------------------- Consolidated financial statements and supplemental data are shown by index thereto, page 20. 2. Consolidated Financial Statement Schedules ------------------------------------------ There are no consolidated financial statement schedules which are required to be filed (SEC Release No. 33-7118) or the related amounts are not present in amounts sufficient to require submission of the schedule. 3. Exhibits -------- The exhibits listed on the accompanying index to exhibits (page 50) are filed by reference as part of this Form 10-K. B. Reports on Form 8-K No reports on Form 8-K were filed by the Company during the quarter ended December 31, 1995. 49 ARCH PETROLEUM INC. INDEX TO EXHIBITS Exhibit 4.1 Term Loan Agreement, dated March 30, 1994, between Onyx Pipeline Company, L.C., Onyx Gathering Company, L.C., Onyx Gas Marketing Company, L.C. and Bank of Scotland, incorporated herein by reference to Exhibit 4.4 to Amendment No. 1 to Forms S-3 dated July 14, 1994. Exhibit 4.2 Certificate of Designation of Preferences and Rights of Exchangeable Convertible Preferred Stock of the Company, dated October 20, 1994, filed with the Secretary of State of Delaware, incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 20, 1994. Exhibit 10.1 Purchase and Sale Agreement, dated November 24, 1992, between the Company and Enron Reserve Acquisition Corp., incorporated herein by reference to Exhibit 10.1 to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.2(a) Financing Statement, dated January 15, 1993, between the Company and Onyx Gathering Company, L.C., incorporated herein by reference to Exhibit 10.2(a) to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.2(b) Pledge Agreement, dated January 15, 1993, between the Company and Onyx Gathering Company, L.C., incorporated herein by reference to Exhibit 10.2(b) to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.2(c) Promissory Note, dated January 15, 1993, between the Company and Onyx Gathering Company, L.C., incorporated herein by reference to Exhibit 10.2(c) to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.2(d) Loan Agreement, dated January 15, 1993, between the Company and Onyx Gathering Company, L.C., incorporated herein by reference to Exhibit 10.2(d) to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.3 Agreement of Purchase and Sale, dated January 15, 1993, between Onyx Gathering Company, L.C. and Onyx Pipeline Company, incorporated herein by reference to Exhibit 10.3 to Form 10-K/A- 1 for the year ended December 31, 1993. Exhibit 10.5(a) Second Restated Revolving Credit Loan Agreement, dated March 31, 1994, between the Company and Bank One, Texas, N.A., incorporated herein by reference to Exhibit 10.5 (a) to Form 10- K/A-1 for the year ended December 31, 1993. Exhibit 10.5(b) Revolving Promissory Note, dated March 31, 1994, between the Company and Bank One, Texas, N.A., incorporated herein by reference to Exhibit 10.5 (b) to Form 10-K/A-1 for the year ended December 31, 1993. Exhibit 10.6 Asset Sale Agreement, dated January 20, 1994, between the Company and Chevron U.S.A. Inc., incorporated herein by reference to Item 7(C) to Form 8-K dated March 31, 1994. 50 Exhibit 10.7(a) Securities Purchase Agreement, dated as of October 15, 1994, between the Company and Travelers Indemnity, incorporated herein by reference to Exhibit 10.1 to Form 8-K dated October 20, 1994. Exhibit 10.7(b) Securities Purchase Agreement, dated as of October 15, 1994, between the Company and Travelers Life, incorporated herein by reference to Exhibit 10.2 to Form 8-K dated October 20, 1994. Exhibit 10.7(c) Securities Purchase Agreement, dated as of October 15, 1994, between the Company and Connecticut General, incorporated herein by reference to Exhibit 10.3 to Form 8-K dated October 20, 1994. Exhibit 10.7(d) Securities Purchase Agreement, dated as of October 15, 1994, between the Company and Cigna Mezzanine, incorporated herein by reference to Exhibit 10.4 to Form 8-K dated October 20, 1994. Exhibit 10.8(a) Cash Offer Circular by Arch Petroleum Inc. to purchase all of the Common Shares of Trax Petroleums Limited, incorporated herein by reference to Exhibit 10.8(a) to From 8-K/A-1 dated January 31, 1996. Exhibit 10.8(b) Notice of Guaranteed Delivery, incorporated herein by reference to Exhibit 10.8(b) to Form 8-K/A-1 dated January 31, 1996. Exhibit 10.8(c) Letter of Acceptance and Transmittal, incorporated herein by reference to Exhibit 10.8(c) to Form 8-K/A-1 dated January 31, 1996. Exhibit 10.9 Third Restated Revolving Credit Loan Agreement dated February 20, 1996, among Arch Petroleum Inc. and Bank One, Texas, N.A., as Agent, and other Banks, incorporated herein by reference to Exhibit 10.9 to Form 8-K/A-1 dated January 31, 1996. Exhibit 10.10 Credit Agreement, dated as of February 20, 1996, among Trax Petroleums Limited and Bank of Montreal, as Agent, and other Financial Institutions, incorporated herein by reference to Exhibit 10.10 to Form 8-K/A-1 dated January 31, 1996. Exhibit 24 Independent Accountant's Consent. 51 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized. ARCH PETROLEUM INC. ------------------- Registrant By: /s/Larry Kalas --------------- Larry Kalas, March 20, 1996 Director, President and Chief Executive Officer (Principal Executive Officer) By: /s/Fred Cantu -------------- Fred Cantu, March 20, 1996 Treasurer and Chief Financial Officer (Principal Accounting and Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. By: /s/Johnny H. Vinson -------------------- Johnny H. Vinson, March 20, 1996 Director By: /s/Randall W. Scroggins ------------------------ Randall W. Scroggins, March 20, 1996 Director By: /s/Dick Harris --------------- Dick Harris, March 20, 1996 Director By: /s/C. Randall Hill ------------------- C. Randall Hill, March 20, 1996 Director By: /s/John F. Gilsenan -------------------- John F. Gilsenan, March 20, 1996 Director 52 EX-27 2 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1995 JAN-01-1995 DEC-31-1995 2,574,000 0 6,986,000 0 0 10,102,000 78,780,000 12,968,000 79,672,000 11,049,000 0 20,000,000 0 172,000 7,423,000 79,672,000 65,628,000 66,590,000 54,035,000 54,035,000 6,287,000 0 1,865,000 (250,000) (86,000) (164,000) 0 0 0 (164,000) (0.10) 0
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