-----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, NhzbR6idee65aMV0IRdo1DKLnp/IU7ixc0Y+DoavrcYfAPK0V+qU+88rSvFjZLYi etpUbslQ62rKnkOFnR+C7w== 0000930661-97-000837.txt : 19970409 0000930661-97-000837.hdr.sgml : 19970409 ACCESSION NUMBER: 0000930661-97-000837 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970407 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: 97575473 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, 1996 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 28, 1997, the aggregate market value of the voting stock held by nonaffiliates of the registrant was $32,827,000 based on the closing price reported by NASDAQ National Market. As of February 28, 1997, there were 17,171,804 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...................................................................................... 5 Item 3. Legal Proceedings............................................................................... 9 Item 4. Submission of Matters to a Vote of Security Holders............................................. 9 PART II Item 5. Market for Company's Common Stock and Related Shareholder Matters............................................................................. 10 Item 6. Selected Financial Data......................................................................... 11 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................................. 12 Item 8. Consolidated Financial Statements and Supplementary Data........................................ 17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................................. 41 PART III Item 10. Directors and Executive Officers of the Company................................................. 42 Item 11. Executive Compensation.......................................................................... 42 Item 12. Security Ownership of Certain Beneficial Owner and Management.................................................................................. 42 Item 13. Certain Relationships and Related Transactions.................................................. 42 PART IV Item 14. Exhibits, Consolidated Financial Statement Schedules, and Reports on Form 8-K......................................................................... 43 Signatures ................................................................................................ 46
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 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 15.5% of the Company's common stock as of December 31, 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, if necessary, and has also reserved approximately 319,300 shares of common stock for issuance upon exercise of options under its current incentive stock option plan. 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 bank credit facility. See Note 12 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 - ---------------------- 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. Trax headquarters will remain in Calgary. The acquisition purchase price was approximately $7,645,000 at January 31, 1996. The Company changed the name of Trax to Arch Petroleum Ltd. ("APL") effective March 31, 1997. 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 through its bank credit facility. 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. 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 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 of Texas ("RRC") amended the field rules for the Keystone Ellenburger Field ("Keystone") reducing the allowable production. Subsequent to this ruling, the Company has not been able to produce enough gas to satisfy the monthly delivery obligations to Enron. This created a gas delivery deficiency under the volumetric production payment. See Item 7, Management's Discussion and Analysis of Financial Condition, for additional discussion of this matter. Natural Gas Pipeline Operations - ------------------------------- In January 1993 the Company acquired a 50% membership interest in Onyx Pipeline Company, L.C. ("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 3 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. 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 purchased CSE's 20% membership interest in Saginaw and ING. The Company now owns a 95% membership interest in Saginaw and ING. 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, 1996, the Company had three customers that represented 67% of total revenues from oil and gas sales, Genesis Crude Oil, L.P. (32%), Enron Gas Marketing (23%) and Chevron U.S.A. Inc. (12%). During 1996 Onyx sold natural gas to approximately 60 customers. CPL is the largest customer of the Company, representing 61% 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. 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 4 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 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. 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 28, 1997, 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. APL leases approximately 4,951 square feet of office space in Calgary, Alberta, Canada. 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 maintains 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 domestic 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. The APL (Canadian) oil and gas reserves were estimated by Sproule Associates Limited, independent petroleum engineers in Canada. All such estimations were made in accordance with regulations promulgated by the Securities and Exchange Commission ("SEC"). The reserve reports are available for examination at the corporate headquarters. 5 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, 1995. All of the Company's production, acreage and drilling activity is located in the United States and Western Canada. 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.
United States Canada Total --------------- --------------- --------------- Present value of discounted future net revenues before income taxes: December 31, 1996 $ 101,701,100 $ 11,775,700 $ 113,476,800 December 31, 1995 64,296,200 - 64,296,200 December 31, 1994 61,078,500 - 61,078,500 Proved developed and undeveloped reserves: Oil (Bbls) December 31, 1996 3,861,000 856,900 4,717,900 December 31, 1995 4,030,300 - 4,030,300 December 31, 1994 3,586,400 - 3,586,400 Gas (Mcf) December 31, 1996 57,060,000 1,136,000 58,196,000 December 31, 1995 61,286,400 - 61,286,400 December 31, 1994 61,546,200 - 61,546,200 Proved developed reserves: Oil (Bbls) December 31, 1996 3,128,400 809,900 3,938,300 December 31, 1995 2,993,600 - 2,993,600 December 31, 1994 3,390,600 - 3,390,600 Gas (Mcf) December 31, 1996 54,981,200 504,000 55,485,200 December 31, 1995 55,628,500 - 55,628,500 December 31, 1994 60,666,200 - 60,666,200
The United States figures above exclude 8.7 Bcf, 11.9 Bcf and 15.5 Bcf of proved gas reserves and $2,960,600, $11,672,700 and $12,566,300 of discounted future net revenues at December 31, 1996, 1995 and 1994, 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. 6 Wells Drilled: The following table shows the wells drilled by or participated in by the Company since 1994. 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, 1996: Exploratory 1 2 3 .3 1.3 1.6 Development 150 - 150 24.4 - 24.4 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
Included in 1996 are 5 gross wells (1 exploratory, 3 development and 1 dry) and 2.1 net wells (.3 exploratory, 1.1 development and .7 dry) drilled by APL in Canada. Leases and Wells Owned: At December 31, 1996, the Company owned interests in the following acreage.
United States Canada Total ----------------- ------------ ----------- Developed acres: Gross 65,777 28,066 93,843 Net 16,560 3,468 20,028 Undeveloped acres: Gross 75,355 122,052 197,407 Net 23,672 61,497 85,169
See the discussion of Proposed Drilling Activity and Acquisitions. As of December 31, 1996, the Company's interests in wells owned were as follows:
Total United States Canada ------------------------ ---------------------- ------------------------ Gross Net Gross Net Gross Net Type Wells Wells Wells Wells Wells Wells ---- ----- ----- ----- ----- ----- ----- Oil 1,170 336.4 1,051 322.3 119 14.1 Gas 119 55.9 117 55.8 2 .1 ------ ----- ----- ----- ----- ---- 1,289 392.3 1,168 378.1 121 14.2 ====== ===== ====== ===== ===== ====
7 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.
1996 1995 1994 --------------- ------------- ------------- Oil volumes (Bbl): United States 459,300 382,100 281,300 Canada 120,300 - - --------------- ------------- ------------- Total 579,600 382,100 281,300 --------------- ------------- ------------- Average Oil Prices ($/Bbl): United States $21.59 $17.28 $16.18 Canada 18.81 - - --------------- ------------- ------------- Composite $21.02 $17.28 $16.18 --------------- ------------- ------------- Gas Volumes (Mcf): United States (1) 6,596,400 7,382,900 2,488,900 Canada 152,200 - - --------------- ------------- ------------- Total 6,748,600 7,382,900 2,488,900 --------------- ------------- ------------- Average Gas Prices ($/Mcf): United States (1) $1.73 $1.32 $1.67 Canada 1.06 - - --------------- ------------- ------------- Composite $1.72 $1.32 $1.67 --------------- ------------- ------------- Average Lifting Cost per Equivalent Barrel (2): United States $4.87 $4.45 $5.07 Canada 3.37 - - --------------- ------------- ------------- Composite $4.74 $4.45 $5.07 --------------- ------------- -------------
(1) Includes the effect of production payment volumes of 2,751,100 Mcf, 3,090,400 Mcf and 183,300 Mcf at an average price of $0.83, $1.11 and $1.28 for the years ended December 31, 1996, 1995 and 1994, respectively. (2) Equivalent barrels are calculated using a conversion factor of six Mcf of gas to one barrel of oil. Costs include severance and ad valorem taxes. Proposed Drilling Activity and Acquisitions: The Company was very successful drilling new wells (developmental and exploratory) and recompleting existing wells in 1996. This coming year the Company has budgeted $15 million to its oil and gas capital expenditures program. Domestically, the Company continues its very successful infill drilling program in Lea County, New Mexico. Twenty-eight new wells and twelve recompletions will command expenditures of $7.7 million to the Company's interest. This area continues to lead the Company's growth both in production and additional reserves. In total, current plans call for drilling more than fifty new wells and recompleting more than twenty-five existing wells in the United States for approximately $10.8 million. The Company was equally successful in 1996 in its exploratory drilling efforts by its 100% owned Canadian subsidiary, APL. Accordingly, current plans include twenty new wells for approximately $4.2 million. APL also increased its acreage positions and expanded its 3-D seismic coverage in 1996. The Company's pipeline subsidiaries also anticipate expansion and growth opportunities in the coming year. In addition to the existing businesses of gas transportation and marketing, our subsidiaries are evaluating participation in several power generation projects. Most of these projects represent opportunities for profitable activities in our existing lines of business while adding another dimension to our future potential. 8 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, 1996. 9 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, 1995, through December 31, 1996. 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 28, 1997, the closing price for the Company's common stock was $2-9/16.
1996 1995 ---------------------------- ------------------------------- Period High Low High Low --------- ---------- --------- --------- lst quarter $ 2-15/16 $ 1-15/16 $ 2-3/16 $1-11/16 2nd quarter 2-11/16 2 2-15/16 1-3/4 3rd quarter 2-3/4 1-11/16 3-1/16 2-1/4 4th quarter 3-1/32 2-1/4 2-11/16 1-11/16
There were approximately 1,550 shareholders of record as of December 31, 1996. 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 10 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.
Year Ended December 31, ----------------------------------------------------- (In Thousands) 1996 1995 1994 1993 1992 --------- --------- ---------- --------- -------- OPERATING DATA: - -------------- Operating revenues (1) $99,926 $66,590 $82,696 $44,148 $7,226 Exploration expense 593 898 1,641 157 24 Net income (loss) 3,022 (164) (1,830) 176 68 Preferred stock dividends 1,600 1,600 311 - - Net income (loss) available per common share .08 (.10) (.12) .01 - Weighted average common and common equivalent shares outstanding 17,246 17,195 17,244 17,142 16,884 BALANCE SHEET DATA: - ------------------ Total assets $101,039 $79,672 $78,025 $51,069 $40,993 Deferred revenue 12,528 16,037 20,690 21,499 23,559 Long-term debt 30,134 17,821 9,632 6,500 - Convertible subordinated notes 5,000 5,000 5,000 - - Convertible preferred stock 20,000 20,000 20,000 - - Shareholders' equity 9,065 7,595 9,490 11,679 11,855
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) - Operating revenues for 1996 include a gain of $1,037,000 from the sale of certain oil and gas properties. See Note 2. 11 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, reserve estimates, interest rate flucuations, the regulatory and political environments, estimated volumes of gas to be delivered pursuant to the volumetric production payment and other risks indicated in filings with the Securities and Exchange Commission. 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. The following review of operations for the years ended December 31, 1996, 1995 and 1994 should be read in conjunction with the consolidated financial statements presented elsewhere. CAPITAL RESOURCES AND LIQUIDITY Financial Position. At December 31, 1996 the Company's total assets increased to $101.0 million from $79.7 million at December 31, 1995. Oil and gas properties increased $9.4 million as a result of the APL Canadian acquisition and $7.9 million as a result of development drilling as well as the recompletion of existing wells, chiefly in New Mexico. The Company's working capital ratio was 1.04 and 0.91 at December 31, 1996 and 1995, respectively. 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 (now APL), the Credit Agreement among APL and Bank of Montreal, the Canadian Agent bank (the "Canadian Revolver"). The two credit facilities are separate bank revolvers. The consolidated borrowing base was increased to $35,000,000 from $30,000,000 by amendment to the revolvers on March 1, 1997 and the maturity date of the revolvers was extended from May 1, 1997 to May 1, 1998. The Domestic Revolver is a modification of the Company's former revolver with Bank One, Texas, N.A. and its participant, the Bank of Scotland. The principal changes to the former revolver were the inclusion of the Bank of Montreal as an additional participant and 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 domestic borrowing base is at $31,000,000. The security collateral requirements and the bank covenants and default provisions are essentially unchanged from the former revolver. The 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 certain of the Company's oil and gas properties which serve as collateral for any loan which may be outstanding under the Domestic Revolver. The borrowing base is reviewed semiannually by the bank at their discretion. 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 are secured by, among other things, a first lien on 65% of the issued and outstanding shares of Northern Arch Resources Ltd.'s ("Northern Arch") common stock and a first lien on the oil and gas properties of the Company which serve as security in the Domestic Revolver. Northern Arch is a 100% owned Canadian subsidiary of the Company that owns 100% of the APL common stock. The Guaranty is intended to rank pari passu with the Company's obligations under the Domestic Revolver. The facility's commitment is U.S. $14,000,000 and the current Canadian borrowing base is U.S. $4,000,000.The borrowing base 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 proceeds of each advance may be used to acquire additional borrowing base properties, to drill and recomplete oil and gas wells and for general corporate purposes. 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 unpaid principal ($2,501,000 at December 31, 1996), is payable in eighteen quarterly installments ending on March 31, 1999. Current maturities of the Onyx Note total $1.1 million at December 31, 1996. 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. The Domestic Revolver, Canadian Revolver and Onyx Note each 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 12 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. 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 1996 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 1996 the Company paid $488,000 in interest. Gross proceeds from the Placement were used to pay down the Company's bank debt existing at that time. 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) are produced and delivered to Enron. The Company recorded revenues of $2.3 million, $3.5 million and $0.2 million on deliveries of 2.8 Bcf, 3.1 Bcf and 0.5 Bcf during 1996, 1995 and 1994, respectively. The Company does not benefit or suffer from any future increases or decreases in gas prices with respect to the production payment volumes delivered according to the original production payment delivery schedule. The Company is responsible for all costs of production, development and marketing of the dedicated gas. The Company has remitted approximately $1.2 million, $1.2 million and $0.6 million to Enron during 1996, 1995 and 1994, respectively, as provided by the agreement as discussed in Note 4 to the consolidated financial statements. These payments, which are provided by a portion of the proceeds from 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 were in lieu of natural gas volumes deliveries, did not materially impact the Company's operations. Pursuant to the agreement, the remedies for under deliveries are confined to sales from Company operated properties in Keystone. Cashflows are impacted to the extent of the actual monthly oil and gas sales from that field. Effective February 1, 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 dollar obligation ("Remedy Adjustment") related to the previous under deliveries. However, during 1995 the RRC once again restricted the allowables thereby impeding the Company's ability to meet its scheduled deliveries. 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 additional volumes, if any, which will be necessary to satisfy the Remedy Adjustment is dependent upon future gas prices. Sources and Uses of Capital Resources. In 1996 the Company's chief sources of funds were $11.1 million (net) from its bank credit facilities and $6.7 million from operations (excluding production payment remedy adjustment). These funds were used to: purchase its Canadian subsidiary, APL, for $7.6 million, to drill new wells and develop existing leases domestically and in APL for a total of $7.9 million, to pay $1.6 million of preferred stock dividends and to fund $1.8 million in working capital changes. In 1995 the Company's principal sources of funds were $8.2 million (net) from its bank credit facilities 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, fund $18.7 million in developed and undeveloped oil and gas property acquisitions, fund $5.8 million in development of existing properties in New Mexico and Texas, including the Keystone Ellenburger Field properties, fund $2.9 million in pipeline acquisition and construction costs and fund $1.6 million of the Company's 3-D seismic activities in Stonewall County and the Panhandle of Texas. The deferred revenue associated with the production payment is recognized as the dedicated gas is delivered to Enron. In May 1993 the 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 gas delivery deficiency under the volumetric production payment. The Keystone Ellenburger Field 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 13 vast reserves of natural gas are produced. There had arisen a difference of opinion among the operators in prior years concerning the appropriate rules necessary to maximize the economic recovery of oil and natural gas reserves in the field. Effective February 1, 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 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 was delivered to Enron. Proceeds from the sale of a portion of the remaining net volumes is being used to offset past delivery volume deficiencies. In November 1995 the operators of Keystone agreed (with the RRC's approval) to reduce, by approximately one-half, the daily production from the field. This modification to field allowables was designed to provide the operators with additional information concerning the reservoir dynamics. The Company's net production from operated and nonoperated leases is now approximately 9.7 million cubic feet of natural gas per day. This curtailment continues to impact the Company's scheduled deliveries under the production payment agreement, and accordingly, additional volume delivery deficiencies are occurring. As a result of the deficiency arising from the curtailment, the Company will be unable to satisfy all of the scheduled deliveries by the end of the contract in July 1998. Under the terms of provisions in the production payment agreement the Company must satisfy the deficiency from the remaining volumes from Keystone. As such, the Company will continue to recognize revenue over the total volumes to be delivered pursuant to the production payment agreement. See Note 4 to the Company's Consolidated Financial Statements. The Company was successful drilling new wells (developmental and exploratory) and recompleting existing wells in 1996. This coming year the Company has budgeted $15 million to its oil and gas capital expenditures program. Domestically, the Company continues its very successful infill drilling program in Lea County, New Mexico. Twenty-eight new wells and twelve recompletions command expenditures of $7.7 million to the Company's interest. This area continues to lead the Company's growth both in production and additional reserves. In total, current plans call for drilling more than fifty new wells and recompleting more than twenty-five existing wells in the United States for approximately $10.8 million. The Company was equally successful in 1996 in its exploratory drilling efforts by its 100% owned Canadian subsidiary, APL. Accordingly, current plans include twenty new wells for approximately $4.2 million. APL also increased its acreage positions and expanded its 3-D seismic coverage in 1996. The Company's pipeline subsidiaries also anticipate expansion and growth opportunities in the coming year. In addition to the existing businesses of gas transportation and marketing, our subsidiaries are evaluating participation in several power generation projects. Most of these projects represent opportunities for profitable activities in our existing lines of business while adding another dimension to our future potential. The Company believes it has sufficient cash flows and borrowing base in the Revolvers to fund its anticipated drilling, development and acquisition programs for 1997 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. RESULTS OF OPERATIONS Year ended December 31, 1996 compared to ---------------------------------------- year ended December 31, 1995 ---------------------------- The Company recorded net income before dividends of $3,022,000 in 1996 as compared to a net loss of $164,000 before dividends in 1995. Net income increased due to higher oil and gas sales and improved margins on pipeline sales. In addition, the Company recognized a pre-tax gain of $1,037,000 on the sale of certain oil and gas properties located in West Texas, in April 1996. There was also a corresponding increase in almost all categories of costs and expenses. Pipeline sales increased $25,060,000 in 1996 as compared to 1995, but were offset by an increase in natural gas purchases of $24,859,000. The increase in sales and purchases is due primarily to the increase in the cost of gas which averaged $2.19 in 1996 as compared to $1.52 in 1995. During 1996 natural gas was sold at an average price of $2.38 as compared to $1.58 in 1995. Gross margin increased by $600,000 in 1996 to $3,300,000. Revenues from oil and gas sales increased $7,369,000 in 1996 as compared to 1995. Oil and gas revenues attributable to APL were $2,425,000 during 1996. Increased production from the New Mexico properties as a result of the development and exploitation 14 program and higher average oil and gas prices also contributed to the increase in sales. Oil production increased to 580,000 barrels in 1996 as compared to 382,000 barrels in 1995, resulting in a $3,414,000 increase in sales. The increase in oil production is due to the Company's successful drilling and development program in New Mexico as well as the APL production (120,000 barrels). The average price received for oil was $21.02 in 1996 as compared to $17.28 in 1995, resulting in a $2,163,000 increase in sales. Gas production in 1996 decreased to 6,749,000 Mcf as compared to 7,383,000 Mcf in 1995, resulting in a $840,000 decrease in sales. The decrease in gas production is attributable primarily to the reduced allowable production from the Keystone Ellenburger field. The average price received for gas increased to $1.72 in 1996 as compared to $1.32 in 1995, resulting in a $2,629,000 increase in sales. The average price received for gas excluding certain production payment volumes was $2.32 in 1996. Lease operating expenses ("LOE") related to oil and gas properties increased $905,000 primarily as a result of the addition of the APL operations. APL LOE was $699,000 during 1996. The new wells successfully completed in New Mexico also added to LOE. Lifting costs per equivalent barrel (including APL operations) increased in 1996 to $4.74 from $4.45 in 1995. Exploration expense decreased $305,000 in 1996 as compared to 1995. Depletion, depreciation and amortization ("DD&A") increased $1,515,000 in 1996 as a result of increased production, primarily from the New Mexico operations, as well as the added APL operations. APL DD&A was $1,139,000 in 1996. The Company continues to evaluate the acreage associated with its Stratford and Double Mountain prospects. To perform its evaluation, management considered its previous drilling results, its future drilling plans for the prospects, farm outs to date, drilling activity surrounding the acreage and the future expiration of the related lease options. Based upon this review and the fact the lease options primarily begin to expire in 1998, management considered it prudent to establish a reserve for impairment totaling $75,000 during 1996. However, management still considers these prospects to be viable prospects for the Company and will continue to evaluate the feasability of these prospects during 1997. General and administrative expenses increased $852,000 in 1996 as compared to 1995, as a result of increased personnel costs and the addition of APL. APL general and administrative expense was $589,000 in 1996. Interest expense increased $992,000 as a result of the increased outstanding bank debt during 1996. For the years ended December 31, 1996, 1995 and 1994, the Company recorded a provision (benefit) for income taxes of $1,438,000, ($86,000) and ($941,000) respectively, resulting in effective tax rates of 32.3%, (34.0%) and (34.0%). The Company's provision for income taxes was less than the statutory federal rate of 34% due to statutory depletion deductions. The Company also recognized a deferred tax asset related to its Canadian subsidiary (APL). No valuation allowance was provided against this deferred tax asset since it is management's belief that it is more likely than not that this deferred tax asset will be utilized. See Note 7 to the Company's Consolidated Financial Statements 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 and 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 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 by $1,530,000 in 1995 to $2,390,000. 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 program in New Mexico and a full year of production as compared to 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 15 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. 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. 16 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ARCH PETROLEUM INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
Page ---- Report of Independent Accountants.......................................................................................... 18 Consolidated Balance Sheets at December 31, 1996 and 1995.................................................................. 19 Consolidated Statements of Operations for years ended December 31, 1996, 1995 and 1994 .............................................................................................. 21 Consolidated Statements of Changes in Shareholders' Equity for years ended December 31, 1996, 1995 and 1994 ..................................................................... 22 Consolidated Statements of Cash Flows for years ended December 31, 1996, 1995 and 1994 .............................................................................................. 23 Notes to Consolidated Financial Statements................................................................................. 24 Unaudited Supplemental Oil and Gas Disclosures............................................................................. 37 Index to Exhibits.......................................................................................................... 43
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. 17 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. Price Waterhouse LLP Fort Worth, Texas March 25, 1997 18 ARCH PETROLEUM INC. CONSOLIDATED BALANCE SHEETS
December 31, December 31, 1996 1995 ------------------ ------------------ ASSETS Current Assets: Cash and cash equivalents $ 3,192,000 $ 2,574,000 Accounts receivable - trade 15,948,000 6,986,000 Accounts receivable - related parties 275,000 - Prepaid expenses and other 968,000 542,000 ------------------ ------------------ Total current assets 20,383,000 10,102,000 Property and Equipment, at cost: Oil and gas properties accounted for by successful efforts method 81,620,000 66,375,000 Natural gas pipelines 12,361,000 11,448,000 Furniture, fixtures and other equipment 1,038,000 957,000 ------------------ ------------------ 95,019,000 78,780,000 Less accumulated depletion, depreciation and amortization 19,617,000 12,968,000 ------------------ ------------------ Net property and equipment 75,402,000 65,812,000 Accounts receivable - related parties 1,551,000 939,000 Notes receivable - related parties 1,759,000 1,645,000 Deferred income taxes 705,000 - Other 1,239,000 1,174,000 ------------------ ------------------ $ 101,039,000 $ 79,672,000 ================== ==================
The accompanying notes are an integral part of these consolidated financial statements. 19 ARCH PETROLEUM INC. CONSOLIDATED BALANCE SHEETS
December 31, December 31, 1996 1995 ------------------ ------------------ LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable $ 16,253,000 $ 9,552,000 Accounts payable - related parties 1,911,000 75,000 Current maturities of long-term debt 1,119,000 1,111,000 Preferred stock dividends payable 311,000 311,000 ------------------ ------------------ Total current liabilities 19,594,000 11,049,000 Long-term debt, less current maturities 30,134,000 17,821,000 Deferred revenue 12,528,000 16,037,000 Convertible subordinated notes 5,000,000 5,000,000 Deferred federal income taxes 3,450,000 1,711,000 Other liabilities 186,000 - Minority interest in consolidated subsidiaries 1,082,000 459,000 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, 17,271,804 and 17,141,404 shares issued and outstanding, respectively 172,000 172,000 Additional paid-in capital 6,012,000 5,944,000 Employee notes for stock purchases (1,022,000) (965,000) Treasury stock, 100,000 shares (206,000) (206,000) Cumulative translation adjustment 37,000 - Retained earnings 4,072,000 2,650,000 ------------------ ------------------ Total shareholders' equity 9,065,000 7,595,000 Commitments and contingencies (Note 10) ------------------ ------------------ $ 101,039,000 $ 79,672,000 ================== ==================
The accompanying notes are an integral part of these consolidated financial statements. 20 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ------------------------------------------ 1996 1995 1994 ----------- ------------ ------------ Revenues: Oil and gas sales $23,748,000 $ 16,379,000 $ 8,730,000 Pipeline sales 74,309,000 49,249,000 73,525,000 Interest and other 832,000 962,000 441,000 Gain on sale of properties 1,037,000 - - ----------- ------------ ------------ 99,926,000 66,590,000 82,696,000 Costs and Expenses: Oil and gas lease operations 8,081,000 7,176,000 3,527,000 Natural gas purchases and pipeline operations 71,309,000 46,859,000 72,665,000 Exploration 593,000 898,000 1,641,000 Depletion, depreciation and amortization 6,904,000 5,389,000 2,907,000 General and administrative 5,060,000 4,208,000 3,617,000 Interest 2,857,000 1,865,000 1,634,000 Foreign currency transaction loss 40,000 - - Minority interest in income (loss) of consolidated subsidiaries 622,000 445,000 (524,000) ----------- ------------ ------------ 95,466,000 66,840,000 85,467,000 ----------- ------------ ------------ Income (loss) before income taxes and dividends 4,460,000 (250,000) (2,771,000) Deferred federal income tax expense (benefit) 1,438,000 (86,000) (941,000) ----------- ------------ ------------ Net income (loss) 3,022,000 (164,000) (1,830,000) Dividends on preferred stock 1,600,000 1,600,000 311,000 ----------- ------------ ------------ Net income (loss) available to common shareholders $ 1,422,000 $ (1,764,000) $ (2,141,000) =========== ============ ============ Net income (loss) available per common share $ 0.08 $ (0.10) $ (0.12) =========== ============ ============ Weighted average common and common equivalent shares outstanding 17,246,000 17,195,000 17,244,000 =========== ============ ============
The accompanying notes are an integral part of these consolidated financial statements. 21 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 1996, 1995 and 1994
Employee Additional Notes Cumulative Common Treasury Common Paid-in Treasury for Stock Translation Retained Shareholders' Shares Shares Stock Capital Stock Purchases Adjustment Earnings Equity ---------- --------- -------- ----------- ------------ ---------- ----------- ---------- ------------- Balance - December 31, 1993 17,181,848 - $ 171,000 $ 5,801,000 $ - $ (848,000) $ - $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 5,809,000 - (905,000) - 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 17,241,404 100,000 172,000 5,944,000 (206,000) (965,000) - 2,650,000 7,595,000 Preferred stock dividends - - - - - - - (1,600,000) (1,600,000) Exercise of stock options 400 - - 1,000 - - - - 1,000 Issue common stock as compensation 30,000 - - 67,000 - - - - 67,000 Interest on employee notes - - - - - (57,000) - - (57,000) Translation adjustment - - - - - - 37,000 - 37,000 Net income - - - - - - - 3,022,000 3,022,000 ----------- --------- --------- ---------- ----------- ---------- ----------- ---------- ------------ Balance - December 31, 1996 17,271,804 100,000 $ 172,000 $ 6,012,000 $ (206,000) $(1,022,000) $ 37,000 $ 4,072,000 $ 9,065,000 =========== ========= ========= ========== =========== ========== =========== ========== ============
The accompanying notes are an integral part of these consolidated financial statements. 22 ARCH PETROLEUM INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, -------------------------------------------------------------- 1996 1995 1994 ------------------ ------------------- ------------------ Cash flows from operating activities: Net income (loss) $ 3,022,000 $ (164,000) $ (1,830,000) Adjustments to reconcile to net cash provided (used) by operations: Depletion, depreciation and amortization 6,904,000 5,389,000 2,907,000 Deferred taxes 1,438,000 (86,000) (941,000) Deferred revenue (2,309,000) (3,457,000) (235,000) Interest on notes receivable and other (213,000) (198,000) (133,000) Issue common shares for compensation 64,000 35,000 - Minority interest in net income (loss) of consolidated subsidiaries 622,000 445,000 (524,000) Foreign currency transaction loss 40,000 - - Gain on sale of properties (1,037,000) - - ------------------ ------------------ ------------------ 8,531,000 1,964,000 (756,000) Change in accounts receivable (8,266,000) 319,000 (673,000) Change in other current assets (406,000) 93,000 (317,000) Change in accounts receivable - related parties (612,000) - - Change in accounts payable and other current liabilities 7,466,000 (352,000) 1,491,000 Production payment remedy adjustment (1,200,000) (1,196,000) (574,000) ------------------ ------------------ ------------------ Net operating cash flows 5,513,000 828,000 (829,000) ------------------ ------------------ ------------------ Cash flows from investing activities: Capital expenditures (8,947,000) (6,088,000) (27,443,000) Proceeds from sale of properties 1,601,000 - - Notes receivable and other assets (181,000) (101,000) (15,000) Acquisition of subsidiary (7,645,000) - - ------------------ ------------------ ------------------ Net investing cash flows (15,172,000) (6,189,000) (27,458,000) ------------------ ------------------ ------------------ Cash flows from financing activities: Proceeds from bank borrowings 26,504,000 11,800,000 32,921,000 Proceeds from preferred stock sale - - 20,000,000 Proceeds from subordinated debt sale - - 5,000,000 Proceeds from note payable - minority interestholder 744,000 - - Payments of bank debt (15,371,000) (3,612,000) (28,678,000) Debt issue costs - - (916,000) Purchase of treasury shares from related party - (206,000) - Preferred stock dividends (1,600,000) (1,600,000) - Other - - (66,000) ------------------ ------------------ ------------------ Net financing cash flows 10,277,000 6,382,000 28,261,000 ------------------ ------------------ ------------------ Change in cash and cash equivalents 618,000 1,021,000 (26,000) Cash and cash equivalents at beginning of period 2,574,000 1,553,000 1,579,000 ------------------ ------------------ ------------------ Cash and cash equivalents at end of period $ 3,192,000 $ 2,574,000 $ 1,553,000 ================== ================== ==================
The accompanying notes are an integral part of these consolidated financial statements. 23 ARCH PETROLEUM INC. Notes to Consolidated Financial Statements 1. SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES Organization and Basis of Presentation: Arch Petroleum Inc., a Delaware corporation, (together with its subsidiaries,"the Company") engages primarily in oil and natural gas exploration, development, production, transportation and marketing in the Southwestern United States and 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 15.5% of the Company's common stock as of December 31, 1996. Two of TDC's shareholders are also officers and directors of the Company. On January 31, 1996, the Company acquired Trax Petroleums Ltd., which was subsequently renamed Arch Petroleum Limited ("APL") effective March 31, 1997. See Note 3 "Acquisition of Trax Petroleums Ltd.". The Company's consolidated financial statements include the results of APL from the January 31, 1996 acquisition date. In a special meeting on January 31, 1995, the Company's shareholders 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 6), if necessary, and has also reserved 319,300 shares of common stock for issuance upon exercise of options under its current incentive stock option plan. The consolidated financial statements include the accounts of the Company and its subsidiaries: APL, a Canadian company, wholly-owned, 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. 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. Supplemental Cash Flow Information: Cash paid for interest was $2,731,000, $1,466,000, and $1,638,000 during 1996, 1995, and 1994, respectively. During 1996, the Company issued stock as compensation to a third party totaling $64,000. During 1996, 1995 and 1994 the Company paid no income taxes. 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, 1996 and 1995. 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, 1996 and 1995, the Company had net imbalance receivables of $298,000 and $192,000 respectively. Foreign Currency Translation: Asset and liability accounts of APL are translated at year-end or historical rates of exchange and revenue and expenses of APL are translated at average exchange rates prevailing during the year. Translation gains and losses related to net assets located outside the United States are shown as a separate component of shareholders' equity. The Canadian dollar is the functional currency of APL and currency transaction gains and losses are recorded in income. Transaction losses were approximately $40,000 in 1996. Cash and Cash Equivalents: Cash and cash equivalents consist of cash in banks and cash investments in immediately available interest bearing accounts. 24 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 and Western Canada. 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. 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 and $127,000 was capitalized for the years ended December 31, 1995 and 1994, respectively. No interest was capitalized in 1996. Costs of unproved properties that are individually significant are evaluated at least annually for impairment of net book value. An impairment reserve of $75,000 was provided in 1996. 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. Impairment of Assets: Effective January 1, 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", which had no impact upon the Company's financial condition or results of operations. As required, the Company evaluates the realizability of its long-lived assets based upon expectations of undiscounted cash flows before interest. An impairment loss is recognized if the sum of the undiscounted cash flows from the use of the asset is less than the book value of the asset. Generally, the amount of impairment loss is measured as the difference between the net book value and the estimated fair value of the assets. 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 that period. 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 from this field. Concurrent with the new field rules, the Company ceased to capitalize water lifting program costs on January 31, 1995 and commenced amortization of the deferred water production costs as the bonus production allowable is produced. The Company capitalized water production costs of $0.2 million and $3.2 million during 1995 and 1994, respectively, and had deferred $4.6 million and $5.1 million of net water production costs at December 31, 1996 and 1995, respectively. These costs are included in proved oil and gas properties. The Company has amortized approximately $563,000 and $609,000 of the deferred water production costs in 1996 and 1995, respectively. 25 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), by the weighted average number of common shares 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 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: Deferred tax liabilities and assets are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company's assets and liabilities using the enacted tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Stock Based Employee Compensation: In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, "Accounting for Stock-Based Compensation", which establishes accounting and reporting standards for various stock based compensation plans. SFAS No. 123 encourages the adoption of a fair value based method of accounting for employee stock options, but permits continued application of the accounting method prescribed by Accounting Principles Board Opinion No. 25 ("Opinion 25"), "Accounting for Stock Issued to Employees". The Company has elected to continue to apply the provisions of Opinion 25. Under Opinion 25, if the exercise price of the Company's stock options equals the market value of the underlying stock on the date of grant, no compensation expense is recognized. SFAS No. 123 requires disclosure of pro forma information regarding net income and earnings per share as if the Company had accounted for its employee stock options under the fair value method of the statement. See Note 11 "Stock Options". 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, 1996 and 1995, as compared with the carrying value of $20 million at December 31, 1996 and 1995, respectively. The estimated fair value of the Notes was $4.7 million at December 31, 1996 and 1995, as compared to the carrying value of $5 million at December 31, 1996 and 1995, respectively. Reclassification: Certain amounts in prior years have been reclassified to conform to classifications adopted in 1996. 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. The Company performs ongoing credit evaluations and generally does not require collateral. The Company's cash and cash equivalents are maintained in major banks. As a result, the Company believes the credit risk in such instruments is minimal. 26 2. PROPERTY AND EQUIPMENT A summary of property and equipment is as follows:
December 31, December 31, 1996 1995 ------------------ ------------------ Oil and gas properties: Unproved properties $ 3,059,000 $ 958,000 Proved properties 78,561,000 65,417,000 ------------------ ------------------ 81,620,000 66,375,000 Less accumulated depreciation and depletion of proved properties 17,821,000 11,658,000 ------------------ ------------------ Net oil and gas properties 63,799,000 54,717,000 Natural gas pipelines 12,361,000 11,448,000 Less accumulated depreciation 1,202,000 786,000 ------------------ ------------------ Net natural gas pipelines 11,159,000 10,662,000 Furniture, fixtures and other equipment 1,038,000 957,000 Less accumulated depreciation 594,000 524,000 ------------------ ------------------ Net furniture, fixtures and other equipment 444,000 433,000 ------------------ ------------------ Net property and equipment $ 75,402,000 $ 65,812,000 ================== ==================
Effective April 30, 1996, the Company sold its working and royalty interests in certain oil and gas properties located in West Texas for net proceeds of $1,570,000. The Company recognized a pre-tax gain of $1,037,000 on the sale of the properties. 3. 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 Trax headquarters remains in Calgary. The aggregate acquisition purchase price was approximately $7,645,000 at January 31, 1996. As described in Note 1, Trax changed its name to Arch Petroleum Limited ("APL") effective March 31, 1997. The Company accounted for the acquisition of APL as a purchase. No goodwill was recorded as the total purchase price was allocated to the net assets of APL. 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 consolidated financial results as they may be in the future or as they might have been for the period had the acquisition been consummated at the beginning of such period.
Year ended December 31, ----------------------------------- (In thousands, except per share data) 1996 1995 ---------------- ------------- Revenues $ 100,204 $ 69,023 Net income (loss) before dividends 2,872 (3,223) Net income (loss) per common share 0.07 (0.28)
4. 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 gas reserves dedicated to Enron on this production payment are excluded from the Unaudited Supplemental Oil and Gas Disclosures herein. 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 revenues related to the production payment of $2,309,000, $3,457,000 and $235,000 during 1996, 1995 and 1994, respectively. The Company remitted $1,200,000, $1,196,000 and $574,000 to Enron during 1996, 1995 and 1994, respectively, in satisfaction of the Remedy Adjustment discussed below. 27 Due to certain rulings by the RRC, the volumes of natural gas that all operators, including the Company, could remove has been limited thereby reducing 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. The agreement with Enron provides a mechanism to remedy both under and over delivery of production payment volumes. The under deliveries of 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. At December 31, 1996, the estimated remaining volumes deliverable to Enron under the production payment agreement were 8.7 Bcf of natural gas (including 3.5 Bcf of natural gas attributable to volume delivery delays resulting from limitations imposed by the RRC in prior periods). These gas reserves dedicated to Enron are excluded from the Unaudited Supplemental Oil and Gas Disclosures herein. During 1997, the Company anticipates the RRC will continue to impose production limitations for Keystone which will create additional delays in scheduled volume deliveries. The amount of additional volumes, if any, which will be necessary to satisfy the Remedy Adjustment is dependent upon future gas prices. As of December 31, 1996, the estimated annual amortization of the remaining deferred revenue balance based on current economic and regulatory conditions is as follows: 1997 $ 2,256,000 1998 3,469,000 1999 5,145,000 2000 1,658,000 ------------- $ 12,528,000 =============
5. LONG-TERM DEBT A summary of long-term debt is as follows:
December 31, --------------------------------------- 1996 1995 ----------------- ----------------- Bank credit facilities $ 28,009,000 $ 15,321,000 Term note 2,500,000 3,611,000 Note payable - minority interest holder 744,000 - Less current maturities 1,119,000 1,111,000 ----------------- ----------------- $ 30,134,000 $ 17,821,000 ================= =================
The term note and note payable - minority interest holder mature as follows: 1997 - $1,119,000 (included in current liabilities), 1998 - $1,111,000 and 1999 - $1,022,000. Maturities of the bank credit facilities is discussed below. 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 (now APL), the Credit Agreement among APL and Bank of Montreal, the Canadian Agent bank (the "Canadian Revolver"). The consolidated borrowing base was increased to $35,000,000 from $30,000,000 by amendment to both revolvers on March 1, 1997 and the maturity date of the revolvers was extended from May 1, 1997 to May 1, 1998. Each of the revolvers is described briefly, as follows: Domestic Revolver ----------------- The Domestic Revolver is a modification of the Company's former revolver with Bank One, Texas, N.A. and its participant, the Bank of Scotland. The principal changes to the former revolver were the inclusion of the Bank of Montreal as an additional participant and 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's commitment remains at $50,000,000 and the current domestic borrowing base is $31,000,000. 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, so long as no event of default has occurred 28 and is continuing, the Company may allocate all or any portion of its Consolidated Borrowing Base (the U.S., Domestic Revolver borrowing base plus the APL 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 current allocation of the CBB is $24,000,000 to the Domestic Revolver and $11,000,000 to the Canadian Revolver. The Company may select an interest rate option with each borrowing advance ($500,000 minimum, in intervals of $100,000) 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 in place two business days before the commencement of an interest period of a Eurodollar advance. A Eurodollar advance is the principal amount under a note with respect to which an IOR is selected. For purposes of the IOR, the effective interest rate occurring on Eurodollar advance notes 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. The effective interest rate increase ranges from a low of 1.75% if the BBP is less than 25% to a high of 2.50% if the BBP is more than 75%. 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 average actual interest rate was 7.90% in 1996 and the interest rate is 8.25% at December 31, 1996. The security collateral requirements include essentially all of the Company's oil and gas properties. 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 Guaranty is intended to rank pari passu with the Companys' obligations under the Domestic Revolver. The Canadian Revolver is also guaranteed by Northern Arch. The facility's commitment is U.S. $14,000,000 and the current Canadian borrowing base is set at U.S. $4,000,000. The various interest rates used in the Canadian Revolver are based on the LIBO or Prime Rate and are adjusted for applicable margins based on the ratio of aggregate outstanding balances relative to CBB (similar to the Domestic Revolver) and range from a low of 0.75% if the CBB is less than 25% to a high of 2.25% if the CBB is more than 75%. The proceeds of each advance may be used 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 average actual interest rate was 7.85% in 1996 and the interest rate is 8.25% at December 31, 1996. 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 APL borrowing base, which is currently US $4,000,000, 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. Term Note --------- 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 (8.75% at December 31, 1996). Interest on the unpaid principal amount of the note is payable quarterly. The unpaid principal ($2,501,000 at December 31, 1996), is payable in eighteen quarterly installments ending on March 31, 1999. Current maturities of the Onyx Note total $1,111,000 at December 31, 1996. 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. Onyx also has a note payable of $785,000 including interest of $41,000 as of December 31, 1996, payable to Sejita Natural Gas, L.C., a 50% interest holder in Onyx. This note is subordinated to the Company's bank debt and is due on August 31, 1999. Both the Domestic and Canadian Revolvers 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, APL and Onyx are currently in compliance with the loan agreements. Neither the Company nor Onyx has any other unused lines of credit. 6. 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 29 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 bank debt. The Company incurred $916,000 of debt issuance costs related to the Placement, which is being amortized over the period the Preferred Stock 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 and commenced April 20, 1995. The Company paid $1,600,000 in dividends on the Preferred Stock in 1996 and 1995. 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 (17,171,804) of the Company's common stock outstanding at December 31, 1996, if all the Preferred Stock and Notes were converted into common stock of the Company, 26,262,713 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. The Company paid $488,000 in interest on the Notes in 1996 and 1995. 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. 30 7. 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:
1996 1995 --------------- --------------- Domestic: Gross deferred tax liabilities: Depreciation, depletion and intangible drilling costs $ 9,628,000 $ 8,755,000 Volumetric production payment 547,000 1,249,000 --------------- --------------- 10,175,000 10,004,000 Gross deferred tax assets: Net operating loss carryforwards 4,884,000 6,712,000 Statutory depletion carryforwards 1,042,000 888,000 Alternative minimum tax credit carryforwards 698,000 592,000 Investment tax credit carryforwards 98,000 101,000 Other 3,000 - --------------- --------------- 6,725,000 8,293,000 --------------- --------------- Long term deferred tax liability $ 3,450,000 $ 1,711,000 =============== =============== Foreign: Gross deferred tax assets: Net operating loss carryforwards $ 24,000 $ - Excess of net tax basis over book basis of property 477,000 - Excess of net tax basis over book basis of liabilities 122,000 - Other 82,000 - --------------- --------------- Long term deferred tax asset $ 705,000 $ - =============== ===============
The components of income (loss) before income taxes are as follows:
Year Ended December 31, --------------------------------------------------------- 1996 1995 1994 --------------- -------------- ---------------- Domestic $ 5,260,000 $ (250,000) $ (2,771,000) Foreign (800,000) - - --------------- -------------- ---------------- $ 4,460,000 $ (250,000) $ (2,771,000) =============== ============== ================
The income tax provision consisted of the following:
Year Ended December 31, --------------------------------------------------------- 1996 1995 1994 --------------- -------------- ---------------- Current: U.S. Federal $ 107,000 $ - $ - Foreign - - - --------------- -------------- ---------------- 107,000 - - Deferred: U.S. Federal 1,611,000 (86,000) (941,000) Foreign (280,000) - - --------------- -------------- ---------------- 1,331,000 (86,000) (941,000) --------------- -------------- ---------------- Income tax expense (benefit) $ 1,438,000 $ (86,000) $ (941,000) =============== ============== ================
31 The provision for income taxes differs from the amount determined by applying the U.S. federal statutory rate to income before income taxes as a result of the following differences:
Year Ended December 31, --------------------------------------------------------- 1996 1995 1994 --------------- -------------- ---------------- Provision based on federal statutory rate 34.0% (34.0%) (34.0%) Statutory depletion (3.1%) (21.2%) (0.9%) Effects on foreign taxes (0.2%) - - State tax and other 1.6% 21.2% 0.9% --------------- -------------- ---------------- 32.3% (34.0%) (34.0%) =============== ============== ================
At December 31, 1996, the Company has gross domestic tax benefit carryforwards of approximately $13,024,000, $2,780,000, $698,000 and $98,000 relating to net operating losses, statutory depletion, alternative minimum tax credits and investment tax credits, respectively, and gross foreign tax benefits of $55,000 relating to net operating losses which expire at various dates beginning in 1997, except for statutory depletion which does not have an expiration date. As a result of the acquisition of Trax, the utilization of a portion of the Company's deferred assets are subject to limitations imposed by various Canadian tax authorities. However, based upon the Company's Canadian reserves and its estimated future net income related thereto, it is management's belief that it is more likely than not that its Canadian deferred tax assets will be utilized. 8. TRANSACTIONS WITH RELATED PARTIES 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 Domestic 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 $1,022,000 and $965,000 at December 31, 1996 and 1995, respectively. These amounts are offset against equity on the consolidated balance sheet. No new notes were authorized during 1996 and 1995. 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 Domestic 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 $1,759,000 and $1,645,000 at December 31, 1996 and 1995, respectively. The Company recognized interest income on all its outstanding notes receivable from officers, directors and key employees of $174,000, $188,000 and $150,000 during 1996, 1995 and 1994, respectively. Cash advances to officers totaled $115,000 during 1995. There were no cash advances made during 1996. The Company intends to extend the due date of the notes if they are not repaid before May 13, 1997. Onyx has transactions in the ordinary course of business with Corpus Christi Gas Marketing ("CCGM"). CCGM's president serves as one of Onyx's Managers. At December 31, 1996, Onyx had a gas imbalance payable of $120,000 to CCGM. The consolidated financial statements include certain amounts and balances that arise from transactions with related parties:
At December 31, 1996 At December 31, 1995 ---------------------------------------- ---------------------------------------- Accounts Accounts Accounts Accounts Receivable Payable Receivable Payable ------------------ ------------------ ------------------- ----------------- TDC, net $ 1,551,000 $ - $ 939,000 $ - CCGM 275,000 1,911,000 60,000 17,000 Sejita Natural Gas - - 1,000 - PURECO - - - 24,000 Cedar Energies, Inc. - 60,000 - 44,000 ------------------ ------------------ ------------------- ----------------- $ 1,826,000 $ 1,971,000 $ 1,000,000 $ 85,000 ================== ================== =================== =================
32
For Year Ended For Year Ended At December 31, 1996 At December 31, 1995 ---------------------------------------- ---------------------------------------- Purchases Sales Purchases Sales From To From To ------------------ ------------------ ------------------- ----------------- CCGM $ 10,196,000 $ 1,120,000 $ 39,000 $ 265,000 Sejita Natural Gas - - 8,000 - Libra Marketing - - 5,000 - Cedar Energies, Inc. 266,000 - 239,000 - Puma Resources - - - 171,000 ------------------ ------------------ ------------------- ----------------- $ 10,462,000 $ 1,120,000 $ 291,000 $ 436,000 ================== ================== =================== =================
For the year ended December 31, 1994, transactions with related parties in the normal course of business were as follows: Purchases from Libra Marketing, PURECO and Cedar Energies Inc. of $260,000, $2,523,000 and $394,000, respectively. Sales to Libra Marketing, PURECO, Cedar Energies, Inc. and Puma Resources of $37,000, $9,000, $312,000 and $627,000, respectively. 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 $20,000, $39,000 and $20,000 for the years ended December 31, 1996, 1995 and 1994, 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. Amounts receivable from TDC at December 31, 1996 and 1995, are classified as long-term and did not accrue interest. The increase in the receivable from TDC in 1996 primarily relates to 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 associated with the wells. Under agreement with TDC, the Company has the right of offset with TDC. Accordingly, the 1996 and 1995 TDC balances are shown net in the financial statements. During 1996 revenue exceeded LOE by TDC on Arch's behalf by approximately $651,000 accounting for the largest portion of the increase in the amount due from TDC. Commencing January 1, 1997, TDC will no longer offset revenue against related LOE and the unpaid balance due to the Company by TDC will accrue interest at the Company's commercial borrowing rate (8.25% at December 31, 1996). All other related party receivables and payables related to the Company's gas marketing and transmission segment. 9. MAJOR CUSTOMERS The following major customers represent 10% or more of total operating revenues by segment for the years ended December 31, 1996, 1995 and 1994:
Oil and Gas 1996 1995 1994 ------------ ---- ---- ---- Genesis Crude Oil, L.P. 32% 13% * Enron Gas Marketing 23% 31% * Chevron U.S.A. Inc. 12% 31% 40%
The Company's principal products are oil and natural gas. The principal market for such products is primarily the Southwestern United States and Western Canada 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 1996 1995 1994 --------------------- ---- ---- ---- Central Power and Light 61% 58% 35% Entergy Corp. * * 17%
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% in period. 10. 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 $249,000, $202,000 and $215,000 in the years ended December 31, 1996, 1995 and 1994, respectively. Aggregate future minimum rental payments required pursuant to noncancellable leases follow: 1997 - $379,000, 1998 - $333,000, 1999 - $255,000, 2000 - $185,000 and 2001 - $110,000. 33 Contingencies: The Company has entered into employment agreements with certain key employees on July 19, 1996, amended January 27, 1997. In the event that following a change of control employment is terminated for those key employees for reasons specified in the agreements, the employees would receive a lump sum payment equal to two years' base salary at the time of termination. There is a calculated ceiling in the agreement. As of February 28, 1997, the maximum payout attributable to these employment agreements is approximately $900,000. 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. 11. STOCK OPTIONS The Company's 1993 Stock Option 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 $1.81 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, 1996, 1995 and 1994, 400, none and 4,556 of the options were exercised under the 93 Plan, respectively. During 1995, 50,000 and 25,000 options were granted at $1.81 and $2.19, respectively, under the 93 Plan to two employees. These options have expiration dates of March 20, 2000 and May 22, 2000, respectively. There were no additional options granted in 1996. Unaudited pro forma information regarding net income and earnings per share is required by SFAS No. 123, if material, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 1995: no dividend yield, expected volatility of 37%, risk free interest rate of 7% and expected lives of five years each. As noted above, there were no option grants during 1996. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. Applying the effect of the pro forma expense did not materially affect the Company's 1996 and 1995 reported net income (loss) and income (loss) per common share. Stock option transactions, in the period from January 1, 1995 to December 31, 1996 are summarized below:
1996 1995 1994 --------------------------- --------------------------- --------------------------- Wtd. Avg. Wtd. Avg. Wtg. Avg. Exercise Exercise Exercise Shares Price Shares Price Shares Price --------------------------- --------------------------- --------------------------- Outstanding at beginning of year 361,700 $ 1.84 292,700 $ 1.81 334,000 $ 1.81 Granted - 75,000 1.94 - Exercised (400) 1.81 - (4,500) 1.81 Forfeited (42,000) 1.81 (6,000) 1.81 (36,800) 1.81 --------------------------- --------------------------- --------------------------- Outstanding at end of year 319,300 1.84 361,700 1.84 292,700 1.81 Exercisable at end of year 259,300 1.82 230,300 1.82 - - Weighted average fair value of options granted during the year $ - $ 0.85 -
34 The following table summarizes information about the options outstanding at December 31, 1996:
Wtd. Avg. Wtd. Avg. Wtd. Avg. Contractual Exercise Exercise Range of Prices Outstanding Life in Years Price Exercisable Price - ------------------------------------------------------------------------------------------------------------------------ $ 1.81 294,300 1.81 $ 1.81 254,300 $ 1.81 2.19 25,000 3.39 2.19 5,000 2.19 ----------------------------------------------------------------------------------------- $1.81 - $2.19 319,300 1.93 $ 1.84 259,300 $ 1.82 =========================================================================================
At December 31, 1996, 1,335,800 shares were available for grant. 12. GEOGRAPHIC AND INDUSTRY SEGMENT INFORMATION The Company operates in two industry segments: oil and gas exploration, development and production and natural gas marketing, transportation and distribution. In addition, the Company has oil and gas operations in the United States and Western Canada. Operating profit by segment is defined as revenues less operating expenses. Income and expense items excluded from operating profit 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 all 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. Financial information by geographic and industry segment for the years ended December 31, 1996, 1995 and 1994 follows. Prior to 1996, the Company operated only in the United States.
Natural Gas (In thousands) Oil and Gas Pipelines Total ------------------ ------------------ ------------------ 1996 Identifiable assets $ 75,785 $ 25,254 $ 101,039 Revenues (1) 24,914 74,309 99,223 Exploration costs and expenses 593 - 593 Depletion, depreciation and amortization 6,460 444 6,904 Operating income 5,758 1,475 7,233 Capital expenditures 8,034 913 8,947 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
35
(In thousands) United States Canada Total ------------------- ------------------ ------------- 1996 Identifiable assets $ 89,672 $ 11,367 $ 101,039 Revenues (1) 96,785 2,438 99,223 Exploration costs and expenses 200 393 593 Depreciation and amortization 5,763 1,141 6,904 Operating income (loss) 7,447 (214) 7,233 Capital Expenditures 6,915 2,032 8,947
(1) - Includes gain on sale of domestic oil and gas properties of $1,037,000. 13. UNAUDITED QUARTERLY FINANCIAL DATA A summary of consolidated financial data for 1996 and 1995 follows (in thousands, except per share amounts):
First Second Third Fourth Quarter Quarter Quarter Quarter ------------------ ------------------ ------------------ ------------------ Year Ended December 31, 1996 - ---------------------------- Operating revenues $ 19,765 $ 23,416 $ 23,071 $ 33,674 Exploration costs and expenses 51 127 312 103 Gross profit 2,485 3,552 2,715 4,247 Net income 488 938 595 1,001 Net income per share (1) $ 0.01 $ 0.03 $ 0.01 $ 0.03 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 1,625 Net income (loss) (279) 435 (327) 7 Net income (loss) per share (1) $ (0.04) $ - $ (0.04) $ (0.02)
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. 36 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, 1996, 1995 and 1994, and the changes therein. All of the Company's oil and gas activities are located within the United States and Western Canada. None of the Company's reserves are subject to long-term supply agreements with a governmental agency.
United States Canada Total ------------------- ------------------ ------------------ Natural Gas (Mcf) Net proved reserves, December 31, 1993 43,553,600 - 43,553,600 Purchases of minerals in place 19,840,700 - 19,840,700 Extensions and discoveries 5,000 - 5,000 Production (1,974,800) - (1,974,800) Revision of previous estimates 121,700 - 121,700 ------------------- ------------------ ------------------ Net proved reserves, December 31, 1994 61,546,200 - 61,546,200 Extensions and discoveries 4,138,000 - 4,138,000 Production (4,291,900) - (4,291,900) Revision of previous estimates (106,000) - (106,000) ------------------- ------------------ ------------------- Net proved reserves, December 31, 1995 61,286,300 - 61,286,300 Purchases of minerals in place - 1,015,200 1,015,200 Sales of minerals in place (1,191,500) - (1,191,500) Extensions and discoveries 1,776,000 273,000 2,049,000 Production (3,845,200) (152,200) (3,997,400) Revisions of previous estimates 1,095,300 - 1,095,300 ------------------- ----------------- ------------------ Net proved reserves, December 31, 1996 59,120,900 1,136,000 60,256,900 ================== ================== ================== Oil (Bbl) Net proved reserves, December 31, 1993 1,585,700 - 1,585,700 Purchases of minerals in place 2,675,800 - 2,675,800 Extensions and discoveries 6,900 - 6,900 Production (282,300) - (282,300) Revision of previous estimates (399,700) - (399,700) ------------------ ------------------- ------------------ Net proved reserves, December 31, 1994 3,586,400 - 3,586,400 Extensions and discoveries 1,126,000 - 1,126,000 Production (382,100) - (382,100) Revision of previous estimates (300,100) - (300,100) ------------------ ------------------- ------------------ Net proved reserves, December 31, 1995 4,030,200 - 4,030,200 Purchases of minerals in place - 682,500 682,500 Sales of minerals in place (37,700) - (37,700) Extensions and discoveries 395,000 294,700 689,700 Production (459,300) (120,300) (579,600) Revision of previous estimates (67,200) - (67,200) ------------------ ------------------ ------------------ Net proved reserves, December 31, 1996 3,861,000 856,900 4,717,900 ================== ================== ==================
37 Proved developed reserves: Natural gas (Mcf) December 31, 1994 60,666,200 - 60,666,200 December 31, 1995 55,628,500 - 55,628,500 December 31, 1996 54,981,200 504,000 55,485,200 Oil (Bbl) December 31, 1994 3,390,600 - 3,390,600 December 31, 1995 2,993,600 - 2,993,600 December 31, 1996 3,128,400 809,900 3,938,300
The Company's proved reserves exclude 8.7 Bcf, 11.9 Bcf and 15.5 Bcf of gas reserves at December 31, 1996, 1995 and 1994, 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 1.7 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 terms of the production payment agreement may vary from the original contracted amount as discussed in Note 4. Costs Incurred in Oil and Gas Activities - ---------------------------------------- Costs incurred in oil and gas property acquisition, exploration and development activities are set forth below:
United States Canada Total ------------------ ------------------ ------------------ 1994 Acquisition of properties: Proved $ 18,172,000 $ - $ 18,172,000 Unproved 590,000 - 590,000 Exploration 1,641,000 - 1,641,000 Development 5,799,000 - 5,799,000 1995 Acquisition of properties: Proved $ 274,000 $ - $ 274,000 Unproved 108,000 - 108,000 Exploration 898,000 - 898,000 Development 4,937,000 - 4,937,000 1996 Acquisition of properties: Proved $ 442,000 $ 6,667,000 $ 7,109,000 Unproved - 2,185,000 2,185,000 Exploration 125,000 1,590,000 1,715,000 Development 5,514,000 400,000 5,914,000
38 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein - ---------------------------------------------------------------------------- Relating to Proved Oil and Gas Reserves - ---------------------------------------
United States Canada Total ------------------ ------------------ ------------------ 1994 Future cash inflows $ 163,551,600 $ - $ 163,551,600 Future production and development costs 54,407,600 - 54,407,600 Future income tax expenses 22,440,700 - 22,440,700 ------------------ ------------------ ------------------ Future net cash flows undiscounted 86,703,300 - 86,703,300 10% annual discount for estimated timing of cash flows 38,182,900 - 38,182,900 ------------------ ------------------ ------------------ Standardized measure of discounted future net cash flows $ 48,520,400 $ - $ 48,520,400 ================== ================== ================== 1995 Future cash inflows $ 182,785,400 $ - $ 182,785,400 Future production and development costs 66,311,500 - 66,311,500 Future income tax expenses 22,434,000 - 22,434,000 ------------------ ------------------ ------------------ Future net cash flows undiscounted 94,039,900 - 94,039,900 10% annual discount for estimated timing future net cash flows 42,127,800 - 42,127,800 ------------------ ------------------ ------------------ Standardized measure of discounted future net cash flows $ 51,912,100 $ - $ 51,912,100 ================== ================== ================== 1996 Future cash inflows $ 309,315,400 $ 29,589,400 $ 338,904,800 Future production and development costs 118,878,800 12,846,900 131,725,700 Future income tax expenses 50,507,300 3,898,600 54,405,900 ------------------ ------------------ ------------------ Future net cash flows undiscounted 139,929,300 12,843,900 152,773,200 10% annual discount for estimated timing of cash flows 65,201,200 3,758,500 68,959,700 ------------------ ------------------ ------------------ Standardized measure of discounted future net cash flows $ 74,728,100 $ 9,085,400 $ 83,813,500 ================== ================== ==================
Future net cash flows were computed using year end prices and costs. For the reserve report as of December 31, 1996, the average domestic prices were $24.97 for oil and $3.60 for gas. As of December 31, 1995, the average domestic prices were $18.82 for oil and $1.76 for gas. As of December 31, 1994, the average domestic prices were $16.02 for oil and $1.74 for gas. As of December 31, 1996, the average foreign prices were $25.41 for oil and $1.84 for gas. Oil and gas prices of December 31, 1996, were higher than those realized on average by the Company over the past five years. Also, prices at the end of the first quarter of 1997 are below those at the end of 1996. Changes in prices could have a material effect on reserve estimates and related future net cash flow amounts. The standardized measure of discounted future net cash flows at December 31, 1996, 1995 and 1994, as presented in the table above, excludes future net cash flows associated with the volumetric production payment as described in Note 4. The discounted future net cash flows related to the volumetric production payment approximates $2,960,600, $11,672,700 and $12,566,300 which amounts are net of discounted future production costs of $3,831,000, $1,912,700 and $2,557,800 at December 31, 1996, 1995 and 1994, respectively. 39 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:
United States Canada Total ------------------- ------------------ ------------------ December 31, 1993 $ 31,789,000 $ - $ 31,789,000 Purchases of minerals in place 28,124,500 - 28,124,500 Net changes in prices and costs, exclusive of properties purchased and sold (5,041,400) - (5,041,400) Net change in income taxes (1,594,000) - (1,594,000) Sales of oil and gas produced, net of production costs (4,364,600) - (4,364,600) Revisions of previous quantity estimates (1,619,800) - (1,619,800) Extensions and discoveries, less related costs 73,600 - 73,600 Changes in estimated future development costs (237,300) - (237,300) Development costs incurred previously estimated 40,200 - 40,200 Accretion of discount 3,178,900 - 3,178,900 Timing and other (1,828,700) - (1,828,700) ------------------- ------------------ ------------------ December 31, 1994 48,520,400 - 48,520,400 Net changes in prices and costs, exclusive of properties purchased and sold 2,736,100 - 2,736,100 Net change in income taxes 174,100 - 174,000 Sales of oil and gas produced, net of production costs (6,001,800) - (6,001,800) Revisions of previous quantity estimates (1,464,900) - (1,464,900) Extensions and discoveries, less related costs 9,241,100 - 9,241,100 Changes in estimated future development costs (5,899,500) - (5,899,500) Development costs incurred previously estimated 740,700 - 740,700 Accretion of discount 4,852,000 - 4,852,000 Timing and other (986,100) - (986,100) ------------------- ------------------ ------------------- December 31, 1995 51,912,100 - 51,912,100 Purchases of minerals in place 2,176,600 9,473,800 11,650,400 Sales of minerals in place (595,800) - (595,800) Net changes in prices and costs, exclusive of properties purchased and sold 46,473,300 - 46,473,300 Net change in income taxes (14,589,000) (2,757,700) (17,346,700) Sales of oil and gas produced, net of production costs (11,479,600) (1,420,500) (12,900,100) Revisions of previous quantity estimates 961,900 - 961,900 Extensions and discoveries, less related costs 5,719,000 3,789,800 9,508,800 Changes in estimated future operating costs (13,709,200) - (13,709,200) Changes in estimated future development costs (232,400) - (232,400) Development costs incurred previously estimated 3,742,000 - 3,742,000 Accretion of discount 5,191,200 - 5,191,200 Timing and other (842,000) - (842,000) ------------------- ------------------ ------------------ December 31, 1996 $ 74,728,100 $ 9,085,400 $ 83,813,500 ================== ================== ==================
40 Results of Operations from Oil and Gas Producing Activities - -----------------------------------------------------------
United States Canada Total ----------------- ----------------- ----------------- 1994 Revenues $ 8,933,000 $ - $ 8,933,000 Production costs (3,527,000) - (3,527,000) Exploration expenses (1,641,000) - (1,641,000) Depletion, depreciation and amortization (2,604,000) - (2,604,000) ---------------- ---------------- --------------- 1,161,000 - 1,161,000 Income tax expense (395,000) - (395,000) ---------------- ---------------- --------------- Results of operations $ 766,000 $ - $ 766,000 ================ ================ =============== 1995 Revenues $ 16,599,000 $ - $ 16,599,000 Production costs (7,176,000) - (7,176,000) Exploration expenses (898,000) - (898,000) Depletion, depreciation and amortization (4,973,000) - (4,973,000) ---------------- ---------------- --------------- 3,552,000 - 3,552,000 Income tax expense (1,208,000) - (1,208,000) ---------------- ---------------- --------------- Results of operations $ 2,344,000 $ - $ 2,344,000 ================= ================ =============== 1996 Revenues $ 21,439,000 $ 2,438,000 $ 23,877,000 Production costs (7,591,000) (490,000) (8,081,000) Exploration expenses (200,000) (393,000) (593,000) Depletion, depreciation and amortization (5,321,000) (1,139,000) (6,460,000) ---------------- ---------------- --------------- 8,327,000 416,000 8,743,000 Income tax (expense) benefit (2,681,000) 280,000 (2,401,000) ---------------- ----------------- --------------- Results of operations $ 5,646,000 $ 696,000 $ 6,342,000 ================= ================= ===============
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 41 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 26, 1997, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on May 8, 1997, 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 26, 1997, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on May 8, 1997, 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 26, 1997, pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on May 8, 1997, 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 26, 1997 , pursuant to Regulation 14A in connection with its Annual Meeting of Shareholders to be held on May 8, 1997, which is incorporated herein by reference. 42 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 17. 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 51) 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, 1996. 43 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. 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. 44 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 Consent of Price Waterhouse LLP. 45 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 25, 1997 Director, President and Chief Executive Officer (Principal Executive Officer) By: /s/ Fred Cantu ----------------------------------------------------- Fred Cantu, March 25, 1997 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 Vinson ----------------------------------------------------- Johnny Vinson, March 25, 1997 Director By: /s/ Randall W. Scroggins ----------------------------------------------------- Randall W. Scroggins, March 25, 1997 Director By: /s/ Richard O. Harris ----------------------------------------------------- Richard O. Harris, March 25, 1997 Director By: /s/ C. Randall Hill ----------------------------------------------------- C. Randall Hill, March 25, 1997 Director By: /s/ John F. Gilsenan ----------------------------------------------------- John F. Gilsenan, March 25, 1997 Director 46 EX-27 2 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1996 JAN-31-1996 DEC-31-1996 3,192,000 0 16,223,000 0 0 20,383,000 95,019,000 19,617,000 101,039,000 19,594,000 0 20,000,000 0 172,000 8,893,000 101,039,000 98,057,000 99,926,000 79,390,000 79,390,000 7,497,000 0 2,857,000 4,460,000 1,438,000 3,022,000 0 0 0 3,022,000 0.08 0
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