ITEM 3. LEGAL PROCEEDINGS
From time to time the Company is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, management of the Company does not expect that the Company is currently a party to a proceeding that will have a materially adverse effect on the Company's financial condition, results of operations or cash flows.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders, through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to Form 10-K the following information is included in Part I of this Form 10-K.
JOHN E. ELIAS has served as the Chief Executive Officer and Chairman of the Board of Directors (the "Board") of the Company since November 1998. Mr. Elias is a member (chairman) of the Nominating Committee of the Board. From April 1993 to September 30, 1998, he served in various senior management positions, including Executive Vice President, of Seagull Energy Corporation, a company engaged in oil and natural gas exploration, development and production and pipeline marketing. Prior to April, 1993 Mr. Elias served in various positions including senior management position with Amoco Corporation, a major integrated oil and gas company. Mr. Elias has more than 35 years of experience in the oil and natural gas exploration and production business. He is 58 years old. Mr. Elias' current term as director of the Company expires in 2000.
JOHN E. CALAWAY formerly served as the Chief Executive Officer and Chairman of the Board of the Company from December 1996 through November 1998. Effective November 16, 1998, John E. Calaway resigned as Chairman of the Board, Chief Executive Officer and a director of the Company. He was the founder of the Company's predecessor corporations and served as the Chief Executive Officer and Chairman of the Board of such companies from 1986 until the Company's March 1997 initial public offering. Mr. John E. Calaway was also the Chairman of the Nominating Committee of the Board.
JAMES D. CALAWAY has served as the President and Chief Operating Officer and as a director of the Company since December 1996 and prior thereto served as a director of the Company's corporate predecessor since April 1991. Mr. James D. Calaway is also a member of the Audit and Nominating Committees of the Board. From January 1994 to March 1997, he served as Special Advisor to the Company's corporate predecessor. From 1989 to January 1994, Mr. James D. Calaway was primarily engaged in the organization and capitalization of several high technology companies, including The Forefront Group, Inc. Prior thereto, he served as Vice President of Business Development for Space Industries International, Inc., a company he co-founded in 1982 that develops, fabricates, integrates and operates spacecraft and space flight equipment. Mr. James D. Calaway received a B.A. in Economics from the University of Texas and an M.A. in Politics, Philosophy and Economics from Oxford University. Mr. James D. Calaway is 41 years old. Mr. John E. Calaway and Mr. James D. Calaway are twin brothers.
MICHAEL G. LONG has served as Senior Vice President and Chief Financial Officer of the Company since December 1996. Mr. Long served as Vice President-Finance of W&T Offshore, Inc., an oil and natural gas exploration and production company, from July 1995 to December 1996. From May 1994 to July 1995, he served as Vice President of the Southwest Petroleum Division for Chase Manhattan Bank, N.A. Prior
thereto, he served in various capacities with First National Bank of Chicago, most recently that of Vice President and Senior Corporate Banker of the Energy and Transportation Department, from March 1992 to May 1994. Mr. Long received a B.A. in Political Science and a M.S. in Economics from the University of Illinois. Mr. Long is 46 years old.
BRIAN C. BAUMLER has served as Controller of the Company since June 1997 and Treasurer since August 1997. From September 1988 to May 1997, Mr. Baumler was employed by Deloitte and Touche LLP, most recently as a Senior Manager of Audit Services. He is a Certified Public Accountant, a member of the American Institute of Certified Public Accounts, Texas Society of Certified Public Accountants and the Houston Chapter of Certified Public Accountants. He holds a B.B.A in Accounting from the University of Northern Iowa. Mr. Baumler is 33 years old.
SIGNIFICANT EMPLOYEES
MARK J. GABRISCH has served as the Vice President of Land for the Company since March 1997. From November 1994 to March 1997, he served in a similar capacity with the Company's predecessor corporation. From 1985 to October 1994, he was a landman, most recently a Senior Landman, for Shell Oil Company. Mr. Gabrisch holds a B.S. in Petroleum Land Management from the University of Houston.
JOHN O. HASTINGS, JR. has served as the Vice President of Exploration for the Company since March 1997 and prior thereto served in a similar capacity with the Company's predecessor corporation since February 1994. From 1984 to February 1994, he was an exploration geologist with Shell Oil Company, serving as Senior Geologist before his departure. Mr. Hastings holds a B.A. from Dartmouth in Earth Sciences and a M.S. in Geology from Texas A&M University.
JOHN O. TUGWELL has served as the Vice President of Production for the Company since March 1997 and prior thereto served as Senior Petroleum Engineer of the Company's predecessor corporation since May 1995. From 1986 to May 1995, he held various reservoir/production engineering positions with Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum Engineering from Louisiana State University. Mr. Tugwell is a registered Professional Engineer in the State of Texas.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) As of March 19, 1999, the Company estimates there were approximately 231 beneficial holders of its Common Stock. The Company's Common Stock is listed on the NASDAQ National Market ("NASDAQ") and traded under the symbol "EPEX". As of March 19, 1999, the Company had 7,772,032 shares outstanding and its closing price on NASDAQ was $5.375 per share. The following table sets forth, for the periods indicated, the high and low closing sales prices for Common Stock of the Company as listed on Nasdaq.
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(1) The first date of trading of the Company's common stock was February 26, 1997.
The Company has never paid a dividend, cash or otherwise and does not intend to in the foreseeable future. The payment of future dividends will be determined by the Company's Board of Directors in light of conditions then existing, including the Company's earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors. See ITEMS 1 AND 2.-- BUSINESS AND PROPERTIES--FORWARD LOOKING INFORMATION AND RISK FACTORS-- Absence of Dividends on Common Stock."
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding the Company as of and for each of the periods indicated. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's financial statements and notes thereto, which follow:
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(1) Basic and diluted income (loss) per share has been computed based on the net income (loss) shown above and assuming the 4,701,361 shares of Common Stock issued in connection with the Combination Transactions were outstanding for all periods prior to the Combination, effective March 3, 1997.
(2) EBITDA represents income (loss) before cumulative effect of accounting change, interest expense, income taxes, depletion, depreciation and amortization and impairment. Management of the Company believes that EBITDA may provide additional information about the Company's ability to meet its future requirements for debt service, capital expenditures and working capital. EBITDA is a financial measure commonly used in the oil and natural gas industry and should not be considered in isolation or as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income this measure may vary among companies. The EBITDA data presented above may not be comparable to a similarly titled measure of other companies.
(3) The Combination (as defined herein) was accounted for as a reorganization of entities under common control. Accordingly, as of and for the three years in the period ended December 31, 1996, the consolidated accounts are presented using the historical costs and results of operations of the affiliated entities as if such entities had always been combined. Accordingly the consolidated financial statements include the accounts of Edge Petroleum Corporation, a Texas corporations,("Old Edge"), and Edge Joint Venture II (the "Joint Venture). The Joint Venture interests not owned by Old Edge is recorded as minority interest.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a review of the Company's financial position and results of operations for the periods indicated. The Company's Consolidated Financial Statements and Supplementary Data and the related notes thereto contain detailed information that should be referred to in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations.
GENERAL OVERVIEW
The Company was organized as a Delaware corporation in August 1996 in connection with the initial public offering (the "Offering") and related combination of certain entities that held interests in the Joint Venture and certain other oil and natural gas properties; herein referred to as the "Combination". In a series of combination transactions the Company issued an aggregate of 4,701,361 shares of common stock and received in exchange 100% of the ownership interests in the Joint Venture and certain other oil and natural gas properties. In March 1997, and contemporaneously with the Combination, the Company completed the Offering of 2,760,000 shares of its common stock generating proceeds of approximately $40 million, net of expenses.
The Company began operations in 1983 and until 1992 generated exploratory drilling prospects based on 2-D seismic data for sale to other exploration and production companies. During 1992, as a result of the advent of economic onshore 3-D seismic surveys and the improvement and increased affordability of data interpretation technologies, the Company changed its strategy to emphasize exploration based upon the use of 3-D seismic data. From 1992 to 1995, the Company reduced its inventory of 2-D based prospects, began limited drilling for its own account and began developing prospects based on 3-D seismic data. Since early 1995, the Company has almost exclusively drilled prospects generated from 3-D seismic data, while accelerating its drilling activity and increasing its working interests in new project areas primarily in South Texas and Louisiana.
The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. The Company records depletion of its full-cost pool using the unit of production method. Investments in unproved properties are not subject to amortization until the proved reserves associated with the projects can be determined or until impaired. To the extent that capitalized costs subject to amortization in the full-cost pool (net of depletion, depreciation and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and natural gas reserves, such excess costs are charged to operations. Once incurred, an impairment of oil and natural gas properties is not reversible at a later date. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company's quarterly filings with the Commission. At December 31, 1998 the Company recorded a full cost ceiling test write down of its oil and natural gas properties of approximately $10 million.
The Company's revenues, profitability, future growth and ability to borrow funds or obtain additional capital, and the carrying value of its properties, are substantially dependent on prevailing prices of oil and natural gas. It is impossible to predict future oil and natural gas price movements with certainty. Declines in prices received for oil and natural gas may have an adverse affect on the Company's financial condition, liquidity, ability to finance capital expenditures and results of operations. Lower prices may also impact the amount of reserves that can be produced economically by the Company.
Due to the instability of oil and natural gas prices, the Company has entered into, from time to time, price risk management transactions (e.g., swaps and collars) for a portion of its natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the benefit to the Company of increases in the price of natural gas it also limits the downside risk of adverse price movements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in natural gas prices and limits potential gains from future increases in prices. The Company accounts for these transactions as hedging activities and, accordingly, gains and losses are included in oil and natural gas revenues during the period the hedged transactions occur. During 1997 and 1998 the Company had in place several natural gas commodity collars with a financial institution covering 5,000-20,000 MMbtus per day, or approximately 30%-60% of the Company's daily production. Prices received float between a floor and cap price per MMbtu, (delivered price basis, Houston Ship Channel), with settlement for each calendar month occurring five business days following the publishing of the Inside F.E.R.C. Gas Marketing Report. Included within natural gas revenues for the years ended December 31, 1998 and 1997 was approximately $482,000 and $33,000, respectively, representing net settlement gains from collar activities. There were no active collar agreements in place at December 31, 1998. During December 1998, the Company entered into a fixed price swap for $1.96 per MMbtu. This fixed price swap covers 13,000 MMbtu per day, or approximately 65% of daily production, and is effective beginning March 1, 1999 and expires on October 31, 1999. There was no material hedging activity during the year ended December 31, 1996.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO THE YEAR ENDED DECEMBER 31, 1997
REVENUE AND PRODUCTION
Oil and natural gas revenues increased 15% from $13.5 million in 1997 to $15.5 million in 1998. Production volumes for oil decreased 14% from 165,640 Bbls in 1997 to 141,774 Bbls in 1998. The decrease in oil production decreased revenues by approximately $411,000, further decreased by a 29% decrease in average oil prices that reduced revenues by approximately $698,000. Production volumes for natural gas increased 46% from 4,298,859 Mcf in 1997 to 6,284,495 Mcf in 1998. The increase in natural gas production increased revenues by approximately $4.9 million. A 12% decrease in average natural gas prices decreased revenues by approximately $1.8 million. The overall net increase in oil and natural gas production was due to 55 new gross, (22.87 net), producing exploratory and development wells drilled and completed since December 31, 1997 partially offset by production declines from existing wells. Included within natural gas revenues for the two years ended December 31, 1998 and 1997 was approximately $482,000 and $33,000, respectively, representing net gains from collar activity. The collar settlements increased the effective average natural gas prices by $0.07 per Mcf and $0.01 per Mcf, respectively, for the two years ended December 31, 1998 and 1997.
The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 1998 and 1997.
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses increased 45% from $2.3 million in 1997 to $3.4 million in 1998 due to increased production generated from new oil and natural gas wells drilled and completed in 1998. Oil and natural gas operating expenses on a unit of production basis were $0.47 per Mcfe and $0.44 per Mcfe for the years ended December 31, 1998 and 1997, respectively.
Depletion, depreciation and amortization expense ("DD&A") increased 248% from $2.9 million in 1997 to $10 million in 1998. Included within DD&A for the years ended December 31, 1997 and 1998 was $2.48 million and $9.3 million, respectively, representing depletion expense of oil and natural gas properties. A 177% increase in the overall depletion rate increased depletion expense by approximately $5.9 million. The increase in the depletion rate was primarily due to revisions of oil and natural gas reserve estimates as of December 31, 1998 and the abandonment during the fourth quarter of 1998 of certain projects, portions of projects and prospects located in non-core areas. Additionally, the depletion rate was further increased due to the change in accounting method (see Note 1 to the Consolidation Financial
Statements) which increased depletion expense by approximately $608,000 during the year ended December 31, 1998. Increased oil and natural gas production further increased depletion expense by approximately $865,000. Depletion on a unit of production basis for the years ended December 31, 1998 and 1997 was $1.30 per Mcfe and $0.47 per Mcfe, respectively. The remaining increase in DD&A was due primarily to depreciation of new computer hardware and software and office furniture purchased during the fourth quarter of 1997 and the amortization of deferred loan cost incurred as a result of a new credit facility executed during April 1998.
The Securities and Exchange Commission requires that the carrying cost of proved reserves be assessed periodically for ceiling test impairment. At December 31,1998 the discounted future net revenues of the Company's proved reserves were $22.7 million. As a result of the Company's carrying cost of proved reserves being in excess of the present value using a discount rate of 10% the Company recorded a full cost ceiling test write down of its oil and natural gas properties of approximately $10 million. There have been no write downs of its oil and natural gas properties in prior years.
General and administrative expense ("G&A") was $4.6 million for each of the years ended December 31, 1998 and 1997. Excluding the effects of the change in accounting method (referred to in Note 1 to the Consolidated Financial Statements), G&A increased by $2.3 million which was primarily attributable to the hiring of additional employees to support the Company's increased level of exploration activities and 3-D project generation and costs associated with being a public company and general office overhead. Included as a reduction in G&A for the years ended December 31, 1998 and 1997, was approximately $743,000 and $802,000, respectively, of overhead reimbursements and management fees received from various management, operating and seismic agreements. General and administrative expenses on a unit of production basis for the years ended December 31, 1998 and 1997 were $0.64 per Mcfe and $0.88 per Mcfe, respectively.
Unearned compensation expense for the year ended December 31, 1998 and 1997 was $621,191 and $513,393, respectively due to the amortization of unearned compensation expense recognized from restricted stock granted to executives at the completion of the Offering. Unearned compensation expense will continue to be recognized in the future, amortized over a vesting period of five to ten years.
The other charge of approximately $2.9 million is expense incurred as a result of John E. Calaway's resignation as Chairman of the Board and Chief Executive Officer and Director of the Company. The Company incurred the one-time charge to satisfy corporate obligations under his employment contract. Included in the $2.9 million is a $1.6 million non-cash amount relating to vesting of the remaining balance of Mr. Calaway's restricted common stock award granted concurrent with the Company's Offering. The balance of the special charge primarily represents cash payments to be paid to Mr. Calaway from the date of his resignation to January, 2000, of which $623,000 has been paid as of December 31, 1998.
Interest expense for the year ended December 31, 1998 was $90,075, net of interest capitalized to oil and natural gas properties of approximately $411,000, as compared to interest expense of $183,028 for the year ended December 31, 1997. The weighted average debt was $7 million for the year ended December 31, 1998 compared to $2 million for the same period in 1997.
Interest income for the year ended December 31, 1998 was $132,993 compared to $900,867 for the same period in 1997. A majority of the interest earned during 1997 was earned from short-term investments purchased with unused proceeds from the Offering. The Offering proceeds were fully deployed in operations by the end of the first quarter of 1998.
For the year ended December 31, 1998, the Company had a tax benefit of $982,966. As a result of the cumulative effect of the accounting change, the Company recorded a provision for taxes during the second quarter of 1998. As a result of losses generated during the second half of 1998 a tax benefit was recognized to the extent of the provision for tax recorded. Due to the availability of net operating loss carry forwards and other net deferred tax assets there is no provision for current or deferred taxes for the year ended December 31, 1997. As of December 31, 1998, the Company has available a substantial net operating loss
carryforward and other net deferred tax assets and should the Company have taxable income in future periods a provision for tax expense will be provided.
For the year ended December 31, 1998, the Company had an operating loss of $16 million as compared to operating income of $3.1 million in 1997. The significant decrease in operating income was primarily attributable to increased depletion expense, a full cost ceiling test write down and the other charge, referred to above, which was further reduced by increased operating costs and expenses related to the new well additions (55 gross, 22.87 net) and lower average commodity prices for both oil and natural gas. These decreases in operating income were partially offset by higher levels of production from new well additions. Net loss for the year ended December 31, 1998 was approximately $13.2 million, ($15 million before cumulative effect of accounting change), or basic and diluted loss per share of $1.70, as compared to net income of $3.8 million, or basic and diluted earnings per share of $0.53 and $0.52, respectively for 1997.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO THE YEAR ENDED DECEMBER 31, 1996
REVENUE AND PRODUCTION
Oil and natural gas revenues increased 74% from $7.7 million in 1996 to $13.5 million in 1997. Production volumes for oil increased 52% from 109,225 Bbls in 1996 to 165,640 Bbls in 1997. The increase in oil production increased revenues by approximately $1.1 million, which was partially offset by an 11% decrease in average oil prices that reduced revenues by approximately $348,000. Production volumes for natural gas increased 86% from 2,316,105 Mcf in 1996 to 4,298,859 Mcf in 1997. The increase in natural gas production increased revenues by approximately $4.8 million. A 2% increase in average natural gas prices increased revenues by approximately $170,000. The overall net increase in oil and natural gas production was due to 75 new gross, (29.89 net), producing exploratory and development wells drilled and completed since December 31, 1996 partially offset by normal production declines from existing wells. Included within natural gas revenues for the year ended December 31, 1997 was approximately $33,000 representing a net gain from current collar activity. The collar settlements increased the effective average natural gas prices by $0.01 per Mcf for the year ended December 31, 1997
The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 1997 and 1996.
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses increased 46% from $1.6 million in 1996 to $2.3 million in 1997 due to increased production generated from new oil and natural gas wells drilled and completed in 1997. Oil and natural gas operating expenses on a unit of production basis were $0.44 per Mcfe and $0.54 Mcfe for the years ended December 31, 1997 and 1996, respectively. The decrease on a unit of production basis is primarily attributable to the disproportionate increase in natural gas production during 1997, which has a lower average production cost per Mcfe compared to oil.
Depletion, depreciation and amortization expense ("DD&A") increased 78% from $1.6 million in 1996 to $2.9 million in 1997. Included within DD&A for the years ended December 31, 1996 and 1997 was $1.35 million and $2.48 million, respectively, representing depletion expense of oil and natural gas properties. The increase in depletion expense was primarily due to increased oil and natural gas production, which increased depletion expense by approximately $1.1 million. A 4% increase in the overall depletion rate increased depletion expense by approximately $70,000. The increase in depletion rate was primarily due to an increase in future development cost for proved undeveloped oil and natural gas properties of approximately $5 million and a 6.3 Bcfe downward revision to prior year oil and natural gas reserve volume estimates. Depletion on a unit of production basis for the years ended December 31, 1997 and 1996 was $0.47 per Mcfe and $0.45 per Mcfe, respectively. The remaining increase in DD&A was due primarily to depreciation of new computer hardware and software and office furniture purchased since December 31, 1996, which was partially offset by decreased amortization of deferred loan costs.
General and administrative expense ("G&A") increased 69% from $2.8 million in 1996 to $4.6 million in 1997. This increase was attributable to additional administrative staffing and the hiring of additional employees to support the Company's increased level of exploration activities, 3-D project generation and other activities. Included as a reduction in G&A for the years ended December 31, 1997 and 1996, was approximately $802,000 and $339,000, respectively, of overhead reimbursements and management fees received from various management, operating and seismic agreements. General and administrative expenses on a unit of production basis for the years ended December 31, 1997 and 1996 were $0.88 per Mcfe and $0.93 per Mcfe, respectively.
Unearned compensation expense for the year ended December 31, 1997 was $513,393 due to the amortization of unearned compensation expense recognized from restricted stock granted to executives at the completion of the Offering. Unearned compensation expense will continue to be recognized in the future, amortized over a vesting period of five to ten years.
Interest expense decreased 79% from $858,663 in 1996 to $183,028 in 1997. The decrease resulted from the repayment of $12.7 million of indebtedness on March 3, 1997 with proceeds of the Offering.
Interest income for the year ended December 31, 1997 was $900,867 earned from short-term investments purchased from excess proceeds from the Offering. There was no material short-term investments purchased during 1996.
Other income in 1996 consisted of $232,500 of commissions earned to market a property for a third party. There were no such commissions earned during the year ended December 31, 1997.
Due to the availability of net operating loss carry forwards and other net deferred tax assets there is no provision for current or deferred taxes for the year ended December 31, 1997. As of December 31, 1997, the Company has substantially utilized its available net operating loss carry forward and other net deferred tax assets and should the Company have taxable income in future periods a provision for tax expense will be provided. Income tax expense for the year ended December 31, 1996 was $394,675.
Minority interest for the year ended December 31, 1997 was eliminated as result of the completion of the Combination on March 3, 1997 in which the Company acquired from the predecessor entities 100% of their ownership interests in the Joint Venture.
For the year ended December 31, 1997, the Company had operating income of $3.1 million as compared to operating income of $1.8 million in 1996. The significant increase in operating income was primarily attributable to higher levels of production from new well additions offset by increases in operating costs and expenses related to the new well additions (75 gross, 29.89 net) and lower average oil and condensate prices. Operating income was further reduced by increased G&A attributable to additional administrative staffing and the hiring of additional employees to support the Company's increased level of drilling activities. Net income was $3.8 million, or basic and diluted earnings per share of $0.53 and $0.52, respectively, for the year ended December 31, 1997, as compared to net income of $300,185, or basic and diluted earnings per share of $0.06 for 1996.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, the Company completed the Offering of 2,760,000 shares of its common stock at a public offering price of $16.50 per share. The Offering provided the Company with proceeds of approximately $40 million, net of expenses. The Company used approximately $12.7 million to repay its long-term outstanding indebtedness incurred under its revolving credit facility (the "Revolving Credit Facility"), subordinated loans and equipment loans. The remaining proceeds from the Offering, together with cash flows from operations, were used to fund capital expenditures, commitments, and other working capital requirements and for general corporate purposes.
The Company had cash and cash equivalents at December 31, 1998 of $272,428, consisting primarily of short-term money market investments, as compared to $3.8 million at December 31, 1997. Working capital was $(8.3) million as of December 31, 1998 as compared to $7.6 million at December 31, 1997.
Cash flows provided by operations were $12 million, $4.1 million and $2.3 million, for the years ended December 31, 1998, 1997 and 1996, respectively. The significant increase in net cash provided by operations for the year ended December 31, 1998 as compared to 1997 was primarily due to a significant amount of collections of accounts receivable from joint interest owners and increased accrued liabilities. Operating cash flows, before changes in working capital, for the year ended December 31, 1998 decreased $917,000 primarily due to lower interest income realized during 1998 and lower average commodity prices for both oil and condensate and natural gas. The significant increase in net cash provided by operations for the year ended December 31, 1997 as compared to 1996 was primarily attributable to higher levels of production from new well additions which was partially offset by increases in operating costs and expenses related to the new successful wells and lower average commodity prices for oil and condensate. Operating cash flows were further reduced by increased G&A attributable to additional administrative staffing and the hiring of additional employees to support the Company's increased level of exploration activities.
During the year ended December 31, 1998, the Company continued to reinvest a substantial portion of its cash flows to increase its 3-D project portfolio, improve its 3-D seismic interpretation technology and fund its drilling program. As a result, the Company used $28 million in investing activities during 1998 including capital expenditures of approximately $34.8 million for oil and natural gas property development offset by proceeds from the sale of oil and natural gas prospects of $7 million. Capital expenditures of $13.5 million were attributed to the drilling of 83 gross wells, 55 of which were successful, with the majority of the remaining capital expenditures representing additions to undeveloped oil and natural gas properties which has expanded and diversified our portfolio of future drilling opportunities.
Pursuant to a rights offering by Frontera conducted in November 1998, the Company agreed to purchase 44,027 shares of Frontera Common Stock plus such additional shares, if necessary, to maintain its current 8.73% interest of diluted outstanding Frontera stock. The Company paid $116,671 in December, 1998 in connection with this offering.
During the year ended December 31, 1997, the Company used $31.2 million in investing activities including capital expenditures of approximately $29.9 million for oil and natural gas property development offset by proceeds from the sale of oil and natural gas prospects of $2.3 million. Capital expenditures of $9.8 million were attributed to the drilling of 101 gross wells, 75 of which were successful, with the majority
of the remaining capital expenditures representing additions to undeveloped oil and natural gas property, as the Company made significant investments in future drilling opportunities. Additionally during 1997, the Company purchased shares of Preferred Stock of Frontera at a price of $3.6 million which are convertible into approximately 10% of the common stock of Frontera.
The Company expects capital expenditures in 1999 to be approximately $18 million. A substantial portion of capital expenditures in 1999 will be invested in the Company's portfolio of 3-D prospects and to fund drilling activities (approximately 50 gross wells) in an effort to expand its reserve base. In addition, the Company will seek to continue to expand and improve its technological and 3-D seismic interpretation capabilities.
Cash flows from financing activities in 1998 were $12.5 million compared to $29.3 million in 1997. Financing activities during 1998 were comprised of borrowings under its amended and restated Revolving Credit Facility. The significant amount of cash flows from financing activities in 1997 was due to the completion of the Company's Offering in March 1997 offset by repayment of the Company's debt. Cash flows from financing activities in 1996 were primarily attributable to drawdowns on its Revolving Credit Facility, which were partially offset by deferred offering costs.
Due to the Company's active exploration and development and technology enhancement programs, the Company has experienced and expects to continue to experience substantial working capital requirements. The Company intends to fund its 1999 capital expenditures, commitments and working capital requirements through cash flows from operations, possible available borrowings under its existing Revolving Credit Facility, and to the extent necessary other financing activities. The projected 1999 cash flows from operations are projected not to be sufficient to fund its budgeted exploration and development program. To provide additional working capital the Company continues to market a portion of its interest in various Company generated drill ready prospects. Additionally, the Company is currently evaluating various financing and refinancing options as well as divestiture of certain non-core and under performing assets. The Company believes it will be able to generate capital resources and liquidity sufficient to fund its capital expenditures and meet such financial obligations as they come due. In the event such capital resources are not available to the Company, its drilling and other activities may be curtailed. See ITEMS 1 AND 2.--BUSINESS AND PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK FACTORS--Significant Capital Requirements."
REVOLVING CREDIT FACILITY
During July 1995, the Company entered into a revolving credit facility (the "Revolving Credit Facility") with a bank to finance temporary working capital requirements. The Revolving Credit Facility provided up to $20 million in borrowings limited by a borrowing base, as defined by the Revolving Credit Facility. The Revolving Credit Facility provided for interest at the lender's prime rate plus 0.75%. The borrowing base was subject to review by the bank on a quarterly basis and could be adjusted subject to the provisions of the Revolving Credit Facility. On March 3, 1997, the Company repaid the outstanding balance of $11,091,449 and accrued interest with proceeds from its initial public offering. Effective April 1, 1998, the Company amended and restated its Revolving Credit Facility to provide a revolving line of credit of up to $100 million bearing interest at a rate equal to prime or LIBOR plus 1.5%-2% depending on the level of borrowing base utilization. The Company's initial borrowing base authorized by the banks was approximately $15 million.
Effective September 29, 1998, the Company had its borrowing base redetermined and amended its Revolving Credit Facility. The initial borrowing base authorized by the bank was approximately $15 million. Beginning October 1, 1998 and on the first day of each month thereafter, the borrowing base was required to be reduced by $550,000.
At December 31, 1998, borrowings under this facility totaled $12.5 million with approximately $850,000 available for future borrowings. The weighted average debt and interest rate during the year ended December 31, 1998 was approximately $7 million and 7.3%, respectively.
The Revolving Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings and issues of capital stock, sales of its oil and natural gas properties or other collateral, engaging in merger or consolidation transactions and prohibitions of dividends and certain distributions of cash or properties and certain liens. The Revolving Credit Facility also contains the following financial covenants: (i) tangible net worth (total assets exclusive of certain intangibles minus liabilities) must be at least $43 million plus 50% of positive net income and 100% of equity raised for all quarterly periods subsequent to December 31, 1997; (ii) the ratio at the end of any quarter of cash flow (net income plus proceeds of certain project sales, depletion, depreciation, amortization and other non-cash expenses less non-cash net income for such quarter) to debt service must be at least 1.25 to 1.00; and (iii) the ratio at the end of any quarter of EBIT (net income plus interest expense and taxes, excluding non-cash, extraordinary expenses and income) to interest expense for the proceeding 12-month period must be at least 4.5 to 1.00. At December 31, 1998 the Company was not in compliance with two of its financial covenants, (i) and (iii) above, and accordingly has received waivers from its bank for its noncompliance. There can be no assurance that the Company will not require waivers in the future or, if required, that the bank will grant them. The Revolving Credit Facility is secured by substantially all the assets of the Company.
Subsequent to December 31, 1998, the Company undertook discussions with the bank to restructure the Revolving Credit Facility. On March 18, 1999 the Company and the Bank agreed on new terms which are as follows; 1) the proposed initial borrowing base is $12 million comprised of a two tranche financing of a $9 million Revolving Credit Facility and a $3 million term facility, 2) Beginning May 1, 1999, and on the first day of each month thereafter, the Revolving Credit Facility borrowing base is required to be reduced by $400,000, 3) 75% of prospect sales will be used to pay down the term facility with the remaining unpaid term facility balance maturing on August 31, 1999. The Bank has also agreed to amend the financial covenants on a go forward basis as follows; tangible net worth will be at least 90% of actual tangible net worth as reported at December 31, 1998 (or $33,260,720); the EBIT to Interest Expense and Cash Flow Coverage covenants will be eliminated and replaced with a quarterly fixed charge coverage test calculated as annualized EBITDA divided by the total of interest plus 50% of quarter end loan outstanding and the covenant level would be 1.25 to 1.00. The fixed charge coverage covenant does not apply until June 30, 1999.
SUBORDINATED LOAN
In December 1994, the Joint Venture entered into an agreement providing for a subordinated loan. Such agreement provided for a $1 million term loan and a $1 million line of credit. The Company borrowed $1 million under the provisions of the term loan and $300,000 under the line of credit. During March 1997, the outstanding balance of $1.3 million was repaid with proceeds from the Offering and the subordinated loan agreement was discharged.
EQUIPMENT LOANS
Prior to the Offering, the Company was a party to various equipment loans with lenders to acquire computer and related office equipment. These loans had various terms and maturities. During March 1997, all but $32,000 of the outstanding balance of $412,000 was repaid with proceeds from the Offering with the remaining loan balance repaid during 1997 with cash flows from operations.
ACCOUNTING CHANGE
The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs that are directly attributable to the Company's acquisition, exploration and development activities are capitalized in a "full-cost pool" as incurred. In the second quarter of 1998 and effective January 1, 1998, the Company changed its method of accounting for direct internal geological and geophysical ("G&G") costs to one of capitalization of such costs, which are directly attributable to acquisition, exploration and development activities, to oil and natural gas property.
Prior to the change the Company expensed these costs as incurred. The Company believes the accounting change provides for a better matching of revenues and expenses and enhances the comparability of its results of operations with those of other oil and natural gas companies that follow the full cost method of accounting (see Note 1 to the Consolidated Financial Statements).
YEAR 2000
The Company has completed its assessment of the year 2000 processing issues of its internal technology systems, considering current financial and accounting, production, land and geological computer systems and software utilized by the Company. Due to the need for improved management reporting, the Company is in the process of replacing its existing financial and accounting, production and land applications with new software which is year 2000 compliant. Implementation is expected to be completed on or before June 30, 1999 at a total cost of approximately $235,000. As of December 31, 1998, the Company has incurred approximately $180,000 converting to its new financial and accounting system and software with a majority of the remaining cost to be incurred prior to March 31, 1999. Production and land applications will be operational on or before June 30, 1999. These costs have been funded from cash flows from operations and the cost of the new software and necessary hardware upgrades have been capitalized. Based on assertions made by vendors, the Company believes its geological systems and software are year 2000 compliant. In addition the Company is performing other forms of due diligence to ensure that its geological systems are compliant.
The Company is also in the process of evaluating the risk presented by potential Year 2000 non-compliance by third parties. Because such risks vary substantially, companies are being contacted based on the estimated magnitude of risk posed to the Company by their year 2000 non-compliance. The Company anticipates that these efforts will continue through 1999 and will not result in significant costs to the Company.
The Company's assessment of its Year 2000 issues involves many assumptions. There can be no assurance that the Company's assumptions will prove accurate, and actual results could differ significantly from the assumptions. In conducting its Year 2000 compliance efforts, the Company has relied primarily on vendor representations with respect to internal computerized systems and representations from third parties with which the Company has business relationships and has not independently verified representations. There can be no assurance that these representations will prove accurate. A Year 2000 failure could result in a business interruption that adversely effects the Company's business, financial condition or results of operations. Although it is not currently aware of any likely business disruptions, the Company is developing a contingency plan to address and assess the readiness of its material suppliers, customers and other entities as it relates to year 2000 processing issues and expects this work to be completed on or before December 31, 1998. The Company is not insured for this type of loss should a loss occur.
The foregoing statements are intended to be and are hereby designated "Year 2000 Readiness Disclosures" within the meaning of the Year 2000 Information and Readiness Disclosure Act.
ACCOUNTING PRONOUNCEMENTS
DERIVATIVES--In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activity" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments and hedging activities that require an entity to recognize all derivatives as an asset or liability measured at fair value. Depending on the intended use of the derivatives, changes in its fair value will be reported in the period of change as either a component of earnings or a component of other comprehensive income.
SFAS 133 is effective for all fiscal quarters beginning after June 15, 1999. Earlier application of SFAS 133 is encouraged, but not prior to the beginning of any fiscal quarter that begins after issuance of the statement. Retroactive application to periods prior to adoption is not allowed. The Company has not quantified the impact of adoption on its financial statements or the date it intends to adopt.
COMPREHENSIVE INCOME--In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, "Reporting of Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting and displaying comprehensive income and its components. SFAS 130 is effective for periods beginning after December 15, 1997. The purpose of reporting comprehensive income is to report a measure of all changes in equity of an enterprise that results from recognized transactions and other economic events of the period other than transactions with owners in their capacity as owners. As of December 31, 1998, there are no adjustments ("Other Comprehensive Income") to net income (loss) in deriving comprehensive income.
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from changes in interest rates and commodity prices. The Company uses a Revolving Credit Facility, which has a floating interest rate, to finance a portion of its operations. The Company is not subject to fair value risk resulting from changes in its floating interest rates. The use of floating rate debt instruments provide benefit due to downward interest rate movements but does not limit the Company to exposure from future increases in interest rates. Based on December 31, 1998 floating interest rate of 7.3%, a 10% change in interest rate would result in an increase or decrease of approximately $91,000 on an annual basis. In the normal course of business the Company enters into hedging transactions, including commodity price collars and swaps, to mitigate its exposure to commodity price movements, but not for trading or speculative purposes. 1n 1998, due to the instability of oil and natural gas prices, the Company has entered into, from time to time, price risk management transactions (e.g., swaps and collars) for a portion of its natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the benefit to the Company of increases in the price of natural gas it also limits the downside risk of adverse price movements. During December 1998, the Company entered into a fixed price swap for $1.96 per MMbtu. This fixed price swap covers 13,000 MMbtu per day, or approximately 65% of daily production, and is effective beginning March 1, 1999 and expires on October 31, 1999. At December 31, 1998, the fair value of this swap was approximately $(292,000). A 10% change in the natural gas swap price per MMbtu would cause the total fair value of the swap to increase or decrease by approximately $79,000 per month.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the Consolidated Financial Statements and Supplementary information listed in the accompanying Index to Consolidated Financial Statements and Supplementary Information on page herein.
ITEM 9.
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding directors and executive officers required under ITEM 10. will be contained within the definitive Proxy Statement of the Company's 1999 Annual Meeting of Shareholders (the "Proxy Statement") under the headings "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" and is incorporated herein by reference. The Proxy Statement will be filed pursuant to Regulation 14A with the Securities and Exchange Commission not later than 120 days after December 31, 1998. Pursuant to Item 401 (b) of regulation S-K certain of the information required by this item with respects to executive officers of the Company is set forth in Part I of this report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by ITEM 11. will be contained in the Proxy Statement under the heading "Executive Compensation and Other Information" and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by ITEM 12. will be contained in the Proxy Statement under the heading "Security Ownership of Management and Certain Beneficial Owners" and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by ITEM 13. will be contained in the Proxy Statement under the heading "Transactions with Management and Certain Shareholders" and "Executive Compensation and Other Information" and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements and Schedules:
1. Financial Statements: See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.
2. Financial Statement Schedule: See Index to the Consolidated Financial Statements and Supplementary Information immediately following the signature page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
- ------------------------
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K:-- On December 1, 1998 The Company filed a Form 8-K announcing as of November 16, 1998 the election of John W. Elias as Chairman of the Board and Chief Executive Officer following the resignation of John E. Calaway, as Chairman of the Board and Chief Executive Officer and Director of the Company.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
EDGE PETROLEUM CORPORATION
Date 3/26/99 /s/ JOHN W. ELIAS - ------------------ ------------------------------------ John W. Elias CHIEF EXECUTIVE OFFICER AND CHAIRMAN OF THE BOARD
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.
Date 3/26/99 /s/ JOHN W. ELIAS - ------------------ ------------------------------------ John W. Elias CHIEF EXECUTIVE OFFICER AND CHAIRMAN OF THE BOARD
Date 3/26/99 /s/ JAMES D. CALAWAY - ------------------ ------------------------------------ James D. Calaway PRESIDENT AND CHIEF OPERATING OFFICER
Date 3/26/99 /s/ MICHAEL G. LONG - ------------------ ------------------------------------ Michael G. Long SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
Date 3/26/99 /s/ BRIAN C. BAUMLER - ------------------ ------------------------------------ Brian C. Baumler CONTROLLER AND TREASURER
Date 3/26/99 /s/ VINCENT ANDREWS - ------------------ ------------------------------------ Vincent Andrews DIRECTOR
Date 3/26/99 /s/ DAVID B. BENEDICT - ------------------ ------------------------------------ David B. Benedict DIRECTOR
Date 3/26/99 /s/ NILS P. PETERSON - ------------------ ------------------------------------ Nils P. Perterson DIRECTOR
Date 3/26/99 /s/ STANLEY S. RAPHAEL - ------------------ ------------------------------------ Stanley S. Raphael DIRECTOR
Date 3/26/99 /s/ JOHN SFONDRINI - ------------------ ------------------------------------ John Sfondrini DIRECTOR
Date 3/26/99 /s/ ROBERT W. SHOWER - ------------------ ------------------------------------ Robert W. Shower DIRECTOR
Date 3/26/99 /s/ WILLIAM H. WHITE - ------------------ ------------------------------------ William H. White DIRECTOR
EDGE PETROLEUM CORPORATION Index to Consolidated Financial Statements and Supplementary Information
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
NONE
All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors, Edge Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Edge Petroleum Corporation (a Delaware Corporation) (the "Company") as of December 31, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1998. 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 in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective January 1, 1998 the Company changed its method of accounting for direct internal geological and geophysical costs to one of capitalization of such costs, which are directly attributable to acquisition, exploration and development activities, to oil and natural gas properties.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas March 26, 1999
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying notes to the consolidated financial statements.
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to the consolidated financial statements.
EDGE PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
EDGE PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
See accompanying notes to the consolidated financial statements.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL--The Company was organized as a Delaware corporation in August 1996 in connection with the Offering and related combination of certain entities that held interests in Edge Joint Venture II (the "Joint Venture") and certain other oil and natural gas properties; herein referred to as the "Combination". In a series of combination transactions the Company issued an aggregate of 4,701,361 shares of common stock and received in exchange 100% of the ownership interests in the Joint Venture and certain other oil and natural gas properties. In March 1997, and contemporaneously with the Combination, the Company completed the Offering of 2,760,000 shares of its common stock generating proceeds of approximately $40 million, net of expenses.
NATURE OF OPERATIONS--The Company is an independent energy company engaged in the exploration, development and production of oil and natural gas. The Company conducts its operations primarily along the onshore United States Gulf Coast, with its primary emphasis in South Texas and Louisiana where it currently controls interests in excess of 222,000 gross acres held under lease or option. In its exploration efforts the Company emphasizes an integrated geologic interpretation method incorporating 3-D seismic technology and advanced visualization and data analysis techniques utilizing state-of-the-art computer hardware and software.
PRINCIPLES OF CONSOLIDATION--The consolidated financial statements as of and for the years ended December 31, 1998 and 1997 include the accounts of all majority owned subsidiaries of the Company, including Edge Petroleum Operating Company Inc., and Edge Petroleum Exploration Company, which are 100% owned subsidiaries of the Company. All intercompany transactions have been eliminated in consolidation.
PRINCIPLES OF COMBINATION--The Combination was accounted for as a reorganization pursuant to Staff Accounting Bulletin 47 due to the high degree of common ownership among the combining entities and only equity ownership interests in the entities being exchanged. Accordingly, the consolidated accounts as of and for the year ended December 31, 1996 are presented using the historical costs and results of operations of the affiliated entities as if such entities had always been combined. The consolidated financial statements include the accounts of Edge Petroleum Corporation, a Texas corporation, ("Old Edge") and the Joint Venture, both of which share common ownership and management. For the periods prior to the Combination, the Joint Venture interests not owned by Old Edge are recorded as minority interest. All intercompany balances were eliminated upon the Combination and all assets and liabilities were assumed by the Company.
ACCOUNTING CHANGE--The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs that are directly attributable to the Company's acquisition, exploration and development activities are capitalized in a "full-cost pool" as incurred. In the second quarter of 1998 and effective January 1, 1998, the Company changed its method of accounting for direct internal geological and geophysical ("G&G") costs to one of capitalization of such costs, which are directly attributable to acquisition, exploration and development activities, to oil and natural gas properties. Prior to the change the Company expensed these costs as incurred. The Company believes the accounting change provides for a better matching of revenues and expenses and enhances the comparability of it's financial statements with those of other companies that follow the full-cost method of accounting. The $1,780,835 cumulative effect of the change in prior years (after reduction for income taxes of $958,910) is included in the net loss for the year ended December 31, 1998. The effect of the accounting change (reduced G&A offset by increased DD&A) on the year ended December 31, 1998 was to decrease the net loss by $1,646,187 ($0.21 basic and diluted loss per share).
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) The following pro forma amounts reflect the effect of retroactive application of the accounting change on general and administrative expenses, depletion and related income taxes.
OTHER CHARGE--Effective November 16, 1998, John E. Calaway resigned as Chairman of the Board, and Chief Executive Officer ("CEO") and Director of the Company. As a result of his resignation the Company recorded a one-time charge of approximately $2.9 million to satisfy corporate obligations under his employment contract. Included in the $2.9 million is a $1.6 million non-cash amount relating to vesting of the remaining balance of Mr. Calaway's restricted common stock award granted concurrent with the Company's Offering (see Note 7). The balance of the special charge primarily represents cash payments to be paid to Mr. Calaway from the date of his resignation date to January, 2000, of which $623,000 has been paid as of December 31, 1998.
REVENUE RECOGNITION--The Company recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold by the Company is not significantly different from the Company's share of production.
OIL AND NATURAL GAS PROPERTY--Investments in oil and natural gas properties are accounted for using the full cost method of accounting. All costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized.
Oil and natural gas properties are amortized using the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the prospects can be determined or until impairment occurs. If the results of an assessment indicates that an unproved property is impaired, the amount of impairment is added to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rates per Mcfe for the years ended December 31, 1998, 1997 and 1996 were $1.30, $0.47 and $0.45, respectively.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. Abandonments of oil and natural gas properties are accounted for as adjustments of capitalized costs with no loss recognized.
In addition, the capitalized costs of oil and natural gas properties are subject to a "ceiling test," whereby to the extent that such capitalized costs subject to amortization in the full cost pool (net of depletion, depreciation and amortization and related deferred taxes) exceed the present value (using 10% discount rate) of estimated future net after-tax cash flows from proved oil and natural gas reserves, such excess costs are charged to operations. Once incurred an impairment of oil and natural gas properties is not reversible at a later date. Impairment of oil and natural gas properties is assessed on a quarterly basis in conjunction with the Company's quarterly filings with the Securities and Exchange Commission. At December 31, 1998 the Company recorded a full cost ceiling test write down of its oil and natural gas properties of approximately $10 million.
Depreciation of other office furniture and equipment and computer hardware and software is provided using the straight-line method based on estimated useful lives ranging from five to ten years.
INCOME TAXES--The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards No. 109--"Accounting for Income Taxes," ("SFAS No. 109") which provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences, using currently enacted tax laws, attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
From inception through February 24, 1997, except for Old Edge, the owners of interests in the Joint Venture were not required to pay federal income taxes due to their status as "pass-through" entities that are not subject to federal income taxation; instead, taxes relating to the taxable income of the Joint Venture for such periods were required to be paid by the owners of such entities. Although the effective date of the Combination is February 25, 1997, each owner of interests in the Joint Venture (or holders of interests in such owners that are "pass through" entities) was required to include in its taxable income, for all periods ending on the date of or prior to the completion of the Combination, its allocable portion of the taxable income attributable to the Joint Venture and is entitled to all tax benefits attributable to the Joint Venture through completion of the Combination.
HEDGING ACTIVITIES--Due to the instability of oil and natural gas prices, the Company has entered into, from time to time, price risk management transactions (e.g., swaps and collars) for a portion of its natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the benefit to the Company of increases in the price of natural gas it also limits the downside risk of adverse price movements. The Company's hedging arrangements apply to only a portion of its production and provide only partial price protection against declines in natural gas prices and limits potential gains from future increases in prices. The Company accounts for these transactions as hedging activities and, accordingly, gains and losses are included in oil and natural gas revenues during the period the hedged transactions occur. During 1997 and 1998 the Company had in place several natural gas commodity collars with a financial institution covering 5,000-20,000 MMbtus per day, or approximately 30%-60% of the Company's daily production. Prices received float between a floor and cap price per MMbtu, (delivered price basis, Houston Ship Channel), with settlement for each calendar month occurring five business days following the publishing of the Inside
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) F.E.R.C. Gas Marketing Report. Included within natural gas revenues for the years ended December 31, 1997 and 1998 was approximately $33,000 and $482,000, respectively, representing net settlement gains from collar activities. There were no active collar agreements in place at December 31, 1998. During December 1998, the Company entered into a fixed price swap for $1.96 per MMbtu. This fixed price swap covers 13,000 MMbtu per day, or approximately 65% of daily production, and is effective beginning March 1, 1999 and expires on October 31, 1999. There was no material hedging activity during the year ended December 31, 1996.
STATEMENTS OF CASH FLOWS--The consolidated statements of cash flows are presented using the indirect method and consider all highly liquid investments with original maturities of three months or less to be cash equivalents.
INVESTMENT IN FRONTERA--In August 1997, the Company acquired 15,171 shares of Series D Preferred Stock of Frontera Resources Corporation ("Frontera") were initially convertible into approximately 10% of the fully diluted outstanding shares of common stock of Frontera (excluding employee stock options). The Company paid $3.6 million for these shares. Frontera is a privately held international energy company based in Houston, Texas, that is seeking to develop upstream and downstream energy projects in emerging international markets. Frontera is one of the first western companies to invest in oil and natural gas rights in the former Soviet Republic of Georgia and has entered into a production sharing contract and refinery study with Saknavtobi, the Georgian state oil company, covering acreage in the Jura Basin in Block 12, eastern Georgia. In addition, Frontera is pursuing projects in Azerbaijan and Bolivia. In July, 1997, Frontera announced a strategic alliance with Baker Hughes Solutions, a subsidiary of Baker Hughes Incorporated with a view to developing oil and natural gas exploration and development opportunities in the onshore Jura Basin of Azerbaijan. In connection with the Frontera investment, Frontera elected James D. Calaway to serve as a member of its board of directors. There can be no assurance as to the results of any of Frontera's projects.
Pursuant to a rights offering conducted in November 1998, the Company agreed to purchase 44,027 shares of Frontera Common Stock plus such additional shares, if necessary, to maintain its current 8.73% interest of diluted outstanding Frontera Stock (assuming conversion of all preferred stock). The rights offering consisted of two tranches. The Company paid $116,671 in December, 1998 in connection with the first tranche and exercised an option to acquire an additional 2,123 shares in January 1999. Should the Company exercise the second tranche of the rights offering (the Company believes this will happen during the first quarter of 1999) the Company will be obligated to purchase another 44,027 shares to maintain is approximate 8.73% interest.
The Company believes that the fair market value of its investment in Frontera approximates its carrying value.
STOCK-BASED COMPENSATION--The Company accounts for Stock Based Compensation in accordance with Financial Accounting Standards Board Statement No. 123--"Accounting for Stock Based Compensation," ("SFAS No. 123"). Under SFAS No. 123, the Company is permitted to either record expenses for stock options and other employee compensation plans based on their fair value at the date of grant or to continue to apply its current accounting policy under Accounting Principles Board Opinion No. 25 ("APB No.25") and recognize compensation expense, if any, based on the intrinsic value of the equity instrument at the measurement date. The Company elected to continue following APB No. 25. The adoption of SFAS No. 123 in 1997 had no effect on the Company's results of operations (see Note 7).
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) EARNINGS PER SHARE--The Company accounts for its Earnings per share in accordance with Statement of Financial Accounting Standards No. 128--"Earnings per Share," ("SFAS No. 128") which establishes the requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires the presentation of "basic" and "diluted" EPS on the face of the income statement. Basic earnings per common share amounts are calculated using the average number of common shares outstanding during each period. Diluted earnings per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock using the treasury stock method.
As a result of the Combination the earnings per share computation assumes that the Company was incorporated during the periods presented and that the shares issued in connection with the Combination were outstanding for all periods. Net income (loss) per share has been computed based on net income as disclosed in the Consolidated Statements of Operations and assuming the 4,701,361 shares of Common Stock issued in connection with the Combination were outstanding since January 1, 1994.
FINANCIAL INSTRUMENTS--The Company's financial instruments consist of cash, receivables, payables, long-term debt and natural gas commodity hedges. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The carrying amount of long-term debt as of December 31, 1998 approximates fair value and the fair value of the natural gas commodity hedge was approximately $(292,000) at December 31, 1998.
DERIVATIVES--In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activity" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments and hedging activities that require an entity to recognize all derivatives as an asset or liability measured at fair value. Depending on the intended use of the derivatives, changes in its fair value will be reported in the period of change as either a component of earnings or a component of other comprehensive income.
SFAS 133 is effective for all fiscal quarters beginning after June 15, 1999. Earlier application of SFAS 133 is encouraged, but not prior to the beginning of any fiscal quarter that begins after issuance of the statement. Retroactive application to periods prior to adoption is not allowed. The Company has not quantified the impact of adoption on its financial statements or the date it intends to adopt.
COMPREHENSIVE INCOME--In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, "Reporting of Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting and displaying comprehensive income and its components. SFAS 130 is effective for periods beginning after December 15, 1997. The purpose of reporting comprehensive income is to report a measure of all changes in equity of an enterprise that results from recognized transactions and other economic events of the period other than transactions with owners in their capacity as owners. As of December 31, 1998, there are no adjustments ("Other Comprehensive Income") to net income (loss) in deriving comprehensive income.
USE OF ESTIMATES--The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from these estimates.
CONCENTRATION OF CREDIT RISK--Substantially all of the Company's accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) concentration of customers and joint interest owners may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, the Company has not experienced credit losses on such receivables but due to deteriorating market conditions the Company can not ensure that such losses may not be realized in the future.
RECLASSIFICATIONS--Certain prior year balances have been reclassified to conform to the current year presentation.
2. PROPERTY AND EQUIPMENT
At December 31, 1998 and 1997, property and equipment consisted of the following:
Undeveloped oil and natural gas properties are not subject to amortization and consist of the cost of undeveloped leaseholds, exploratory and developmental wells in progress, and secondary recovery projects before the assignment of proved reserves. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and natural gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development.
The following table summarizes the cost of the properties not subject to amortization for the year the cost was incurred:
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT
During July 1995, the Company entered into a revolving credit facility (the "Revolving Credit Facility") with a bank to finance temporary working capital requirements. The Revolving Credit Facility provided up to $20 million in borrowings limited by a borrowing base, as defined by the Revolving Credit Facility. The Revolving Credit Facility provided for interest at the lender's prime rate plus 0.75%. The borrowing base was subject to review by the bank on a quarterly basis and could be adjusted subject to the provisions of the Revolving Credit Facility. On March 3, 1997, the Company repaid the outstanding balance of $11,091,449 and accrued interest with proceeds from its initial public offering. Effective April 1, 1998, the Company amended and restated its Revolving Credit Facility to provide a revolving line of credit of up to $100 million bearing interest at a rate equal to prime or LIBOR plus 1.5%-2% depending on the level of borrowing base utilization. The Company's initial borrowing base authorized by the banks was approximately $15 million.
Effective September 29, 1998, the Company had its borrowing base redetermined and amended its Revolving Credit Facility. The initial borrowing base authorized by the bank was $15 million. Beginning October 1, 1998, and on the first day of each month thereafter, the borrowing base was required to be reduced by $550,000.
At December 31, 1998, borrowings under this facility totaled $12.5 million with approximately $850,000 available for future borrowings. The weighted average debt and interest rate during the year ended December 31, 1998 was approximately $7 million and 7.3%, respectively.
The Revolving Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings and issues of capital stock, sales of its oil and natural gas properties or other collateral, engaging in merger or consolidation transactions and prohibitions of dividends and certain distributions of cash or properties and certain liens. The Revolving Credit Facility also contains the following financial covenants: (i) tangible net worth (total assets exclusive of certain intangibles minus liabilities) must be at least $43 million plus 50% of positive net income and 100% of equity raised for all quarterly periods subsequent to December 31, 1997; (ii) the ratio at the end of any quarter of cash flow (net income plus proceeds of certain project sales, depletion, depreciation, amortization and other non-cash expenses less non-cash net income for such quarter) to debt service must be at least 1.25 to 1.00; and (iii) the ratio at the end of any quarter of EBIT (net income plus interest expense and taxes, excluding non-cash, extraordinary expenses and income) to interest expense for the proceeding 12-month period must be at least 4.5 to 1.00. At December 31, 1998 the Company was not in compliance with two of its financial covenants, (i) and (iii) above, and accordingly has received waivers from its bank for its noncompliance. There can be no assurance that the Company will not require waivers in the future or, if required, that the bank will grant them. The Revolving Credit Facility is secured by substantially all the assets of the Company.
At December 31, 1998, based on amounts paid and to be paid in 1999 under the Revolving Credit Facility, as restructured, current maturities of long-term debt and long-term debt consisted of the following:
There was no outstanding notes payable or long-term debt at December 31, 1997.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT (CONTINUED) Subsequent to December 31, 1998, the Company undertook discussions with the bank to restructure the Revolving Credit Facility. On March 18, 1999 the Company and the Bank agreed on new terms which are as follows; 1) the proposed initial borrowing base is $12 million comprised of a two tranche financing of a $9 million Revolving Credit Facility and $3 million of subordinated debt, 2) Beginning May 1, 1999, and on the first day of each month thereafter, the Revolving Credit Facility borrowing base is required to be reduced by $400,000, 3) 75% of prospect sales will be used to pay down the subordinated debt with the remaining unpaid subordinated balance maturing on August 31, 1999. The Bank has also agreed to amend the financial covenants on a go forward basis are as follows; tangible net worth will be 90% of actual tangible net worth as reported at December 31, 1998 (or $33,260,720); the EBIT to interest expense and cash flow coverage covenants will be eliminated and replaced with a quarterly fixed charge coverage test calculated as annualized EBITDA divided by the total of interest expense plus 50% of quarter end loan outstanding and the covenant level would be 1.25 to 1.00. The fixed charge coverage covenant does not apply until June 30, 1999.
4. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the Company's financial condition, results of operations or cash flows. The Company is not currently a party to any litigation that it believes could have a material adverse effect on the financial position of the Company.
Additionally, the Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stricter environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts the drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.
At December 31, 1998, the Company was obligated under a noncancelable operating lease for office space. Following is a schedule of the remaining future minimum lease payments under this lease:
Rent expense for the years ended December 31, 1998, 1997 and 1996 was $478,652, $214,143 and $204,376, respectively.
5. INCOME TAXES
Deferred income taxes reflect the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes in accordance with SFAS No. 109.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. INCOME TAXES (CONTINUED) Significant components of the Company's deferred tax liabilities and assets as of December 31, 1998 and 1997 are as follows:
The differences between the statutory federal income taxes and the Company's effective taxes is summarized as follows:
The differences between the statutory federal income taxes and the Company's effective taxes is summarized as follows:
At December 31. 1998, the Company had cumulative net operating loss carryforwards ("NOL") for federal income tax purposes of approximately $20.4 million which will begin to expire in 2007. The net operating loss carryforwards assume that certain items, primarily intangible drilling costs have been written off in the current year. However, the Company has not made a final determination if an election will be made to capitalize all or part of these items for tax purposes. Due to the 1997 ownership change of Old Edge and the Joint venture, future utilization of the NOLs may be limited by the Internal Revenue Code Section 382.
From inception through February 24, 1997, except for Old Edge, the owners of interests in the Joint Venture were not required to pay federal income taxes due to their status as "pass-through" entities that are not subject to federal income taxation; instead, taxes relating to the taxable income of the Joint
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. INCOME TAXES (CONTINUED) Venture for such periods were required to be paid by the owners of such entities. Although the effective date of the Combination is February 25, 1997, each owner of interests in the Joint Venture (or holders of interests in such owners that are "pass through" entities) was required to include in its taxable income, for all periods ending on the date of or prior to the completion of the Combination, its allocable portion of the taxable income attributable to the Joint Venture and is entitled to all tax benefits attributable to the Joint Venture through completion of the Combination. On a pro forma basis, had the Company been a tax paying entity from inception (April 1, 1991), the Company would not have recorded a tax provision in any period prior to the Combination. Thus the tax provision, as reported by the Company, for the year ended December 31, 1996 approximates what would have been reported on a pro forma basis had the combining entities always been combined.
6. EMPLOYEE BENEFIT PLANS
Effective July 1, 1997 the Company established a defined-contribution 401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of the Company who are age 21 or older. The Company's matching contributions to the Plan are discretionary. For the year ended December 31, 1998 and 1997 the Company contributed $68,869 and $40,954, respectively, to the Plan.
7. EQUITY AND STOCK PLANS
On March 3, 1997 the Combination Transactions were consummated resulting in the issuance of 4,701,361 shares to the predecessor owners of the combining entities involved in the Combination (see Note 1). In addition, during March 1997, the Company completed its Offering issuing 2,760,000 shares at $16.50 per share. Net proceeds totaled $40 million, net of offering cost of approximately $5.4 million.
In conjunction with the Offering, the Company established the Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan"). The Incentive Plan is discretionary and provides for the granting of awards, including options for the purchase of the Company's Common Stock ("Common Stock") and for the issuance of restricted and or unrestricted Common Stock to directors, officers, employees and independent contractors of the Company. The options and restricted stock granted to date vest over 3-10 years. An aggregate of 1,200,000 shares of Common Stock have been reserved for grants under the Incentive Plan, of which 271,483 shares were available for future grants at December 31, 1998 (these shares include only those issued under the Incentive Plan). Shares of Common Stock awarded as restricted stock are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment or service or achievement of certain performance milestones. During 1998 and 1997, 2,412 and 250,586 shares, respectively, of restricted stock were awarded having a market value of $12.38 and $16.50, respectively, per share as of the award date. The total market value of such awards has been recorded as unearned compensation-restricted stock and is shown as a separate component of stockholders' equity. The unearned compensation-restricted stock is amortized to operations over the related vesting period. Amortization of unearned compensation expense amounted to $621,191 and $513,393 in 1998 and 1997, respectively.
Effective November 16, 1998, Mr. John E. Calaway resigned as Chairman of the Board, Chief Executive Officer and a director of the Company. In connection with his resignation his remaining restricted stock, 106,916 shares, became fully vested. Included in "Other charge" is the amortization of approximately $1.6 million of unearned compensation expense resulting from the vesting of those restricted shares.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY AND STOCK PLANS (CONTINUED)
In addition, as of the date of the Combination Transactions, Old Edge had in place a stock incentive plan which was administered by non-employee members of the Board of Directors of Old Edge. Prior to the Combination, two executives of the Company each held outstanding options for the purchase of 2,193 shares of Old Edge Common Stock granted under the Old Edge incentive plan. Upon completion of the Combination Transactions, such options were converted into incentive stock options for the purchase of an aggregate of 97,844 (48,922 for each of the two individuals) shares of Common Stock of the Company (such number of shares of Common Stock as would have existed if such options had been exercised immediately prior to the Combination Transactions). After adjustment for such conversion, the option price per share of Common Stock for each of the two grants was approximately $4.09 and $2.04, respectively. These amounts are included within options granted during 1997 in the table below. Of these shares 48,922 were exercised during 1997 and 48,922 remain outstanding at December 31, 1997 and 1998.
A summary of the status of the Company's stock options and changes as of and for each of the two years ended December 31, 1998 and 1997 are presented below:
The Company applies the intrinsic value based method of APB No.25 in accounting for its stock options. Accordingly, no compensation expense has been recognized for any stock options granted. Had compensation expense for the Company's stock options granted during the years ended December 31, 1998 and 1997 been determined based on the fair value at the grant dates, consistent with the methodology prescribed by SFAS No.123, the Company's net income and earnings per share would have been reduced to the amounts indicated below based on the Black-Scholes option pricing model (the "Model") adopted for the use in valuing stock options. The estimated values under the Model are based on the following assumptions for the year ended December 31, 1998 and 1997: expected volatility based on historical volatility of daily Common Stock Prices (53% and 41%, respectively), a risk free rate of return based on a discount rate which approximates the U.S. Treasury rate at the time of the grant, no dividend yields, an
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. EQUITY AND STOCK PLANS (CONTINUED) expected option exercise period of 8 years (with the exercise occurring at the end of such period) and a forfeiture rate of 0%-10% over the vesting period of such options.
The following is presented as a reconciliation of the numerators and denominators of basic and diluted earnings per share computations, in accordance with SFAS No. 128.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. EQUITY AND STOCK PLANS (CONTINUED) For the year ended December 31, 1998, the Company reported a net loss thus the effects of stock options are antidilutive. For the year ended December 31, 1996 there were no dilutive stock options outstanding.
8. RELATED PARTY TRANSACTIONS
The Company incurred management fees from the general partners of Edge Group II of $66,623 for the year ended December 31, 1996. In conjunction with the Combination, and as a component of the Edge Group II Exchange Offer, these fees were settled with the general partners of Edge Group II during 1997.
At December 31, 1997, included in receivables from related parties was $85,681 representing amounts due from directors and employees of the Company. There were no material amounts outstanding at December 31, 1998.
In May 1992, the Company became the managing venturer of the Essex Royalty Joint Venture ("Essex") and the Company entered into a management agreement with Essex. In September 1994, the Company became the managing venturer of the Essex Royalty Joint Venture II ("Essex II") and the Company entered into a management agreement with Essex II. Under the management agreements with Essex and Essex II (collectively, the "Essex Joint Ventures"), the Company receives a monthly management fee for managing the Essex Joint Ventures, the general partner of each of which is a related party. For each of the three years ended December 31, 1998, the Company recorded management fees totaling $120,000, and have recorded these amounts as a reduction of general and administrative expenses. In addition, these agreements stipulate that the Company is entitled to be reimbursed for certain direct general and administrative expenses and other reimbursable costs. Such amounts invoiced by the Company to the Essex Joint Ventures for the three years ended December 31, 1998, 1997 and 1996 amounted to $3,074, $61,746 and $67,000, respectively. At December 31, 1998 and 1997, the Company had a receivable from the Essex Joint Ventures of $167,971 and $258,887, respectively, relating to these management fees, direct expenses, and costs.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
The sum of the individual quarterly basic and diluted earnings (loss) per share amounts may not agree with year-to-date basic and diluted earnings (loss) per share amounts as a result of each period's computation being based on the weighted average number of common shares outstanding during that period.
Included in operating expenses during the three months ended December 31, 1998 is approximately $10 million representing an impairment of oil and natural gas properties (see Note 1) and an other charge of approximately $2.9 million representing a one-time charge to satisfy corporate obligations under the former CEO's employment contract (see Note 1).
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Natural Gas Producing Activities."
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED) CAPITALIZED COSTS--Capitalized costs and accumulated depletion, depreciation and amortization relating to the Company's oil and natural gas producing activities, all of which are conducted within the continental United States, are summarized below:
COSTS INCURRED--Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
Gross costs incurred excludes sales of proved and unproved oil and natural gas properties which were accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.
RESULTS OF OPERATIONS--Results of operations for the Company's oil and natural gas producing activities are summarized below:
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
RESERVES--Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes (see Standardized Measure) for the periods presented are based on estimates prepared by Ryder Scott Company, independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.
The Companys net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below.
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
These quantities include the minority interest in the Joint Venture as the Joint Venture is consolidated with Old Edge for the year ended December 31, 1996 (see Note 1).
STANDARDIZED MEASURE--The Standardized Measure of Discounted Future Net Cash Flows relating to the Company's ownership interests in proved oil and natural gas reserves for each of the three years ended December 31, 1998 is shown below:
The Standardized Measure of Discounted Future Net Cash Flows reflects the consolidation of the Joint Venture for the year ended December 31, 1996. The minority interest's share of Standardized Measure of Discounted Future Net Cash Flows is $21,422,792 at December 31, 1996.
Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Future oil and natural gas operating expenses and development costs are computed primarily by the Company's petroleum engineers and are provided to Ryder Scott as estimates of expenditures to be incurred in developing and producing the Company's
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED) proved oil and natural gas reserves at the end of the year, based on year end costs and assuming the continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for net operating loss carryforwards and tax credits. A discount factor of 10% was used to reflect the timing of future net cash flows. The Standardized Measure of Discounted Future Net Cash Flows is not intended to represent the replacement cost or fair market value of the Company's oil and natural gas properties.
The Standardized Measure of Discounted Future Net Cash Flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
CHANGES IN STANDARDIZED MEASURE--Changes in Standardized Measure of Discounted Future Net Cash Flows relating to proved oil and gas reserves are summarized below:
Sales of oil and natural gas, net of oil and natural gas operating expenses are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after tax basis.
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