ITEM 3. LEGAL PROCEEDINGS
From time to time we are a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to us, could have a potential material adverse effect on our financial condition, results of operations or cash flows except for the litigation described below. We do not believe that the ultimate outcome of this litigation will have a material adverse effect on us.
In October 2001, the Company was sued by certain mineral owners in its Mew lease, upon which the Company and its partners drilled and completed the Mew No. 1 well in the Brandon Area, Duval County, Texas. The suit names the Company, Santos USA and Mark Smith, an independent landman, as Defendants, and is filed in the 229th Judicial District Court of Duval County, Texas. The suit seeks a declaratory judgment to set aside certain quitclaim deeds between the Mew lessors that were intended to result in a partition of the
mineral estate between the various members of the Mew family in the land where the well is located and other lands. The pleadings allege failure of consideration, fraud, failure to consummate the partition, bad faith trespass and conversion. As part of the leasing effort for the prospect, some members of the Mew family had sought to partition their minerals under the tracts where they owned the surface in full. The Mew heirs, from whom the Company acquired leases, could lose a portion of their mineral interest if the quitclaim deeds are set aside. Were this to happen, it could have the effect of voiding the Company's leases as to an undivided one-third of the unit acreage for the Mew well and the Mew lease. Plaintiffs seek unspecified actual and exemplary damages against the Company and Santos arising out of the alleged fraud committed by the Company and Mark Smith. They also seek damages from Santos for the value of the oil and natural gas produced and saved from the Mew well, or alternatively, for the value of the oil and natural gas produced less the cost of drilling, completing and operating the well. The Company has a 12.5% working interest in the well. To date, the Mew well has produced $5.7 million in net revenue and has cost $3.6 million to drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and 4.6 Bcf. The Company has filed an answer in the case. Santos has filed a plea of abatement asking that the case be dismissed for failure to join necessary and indispensable parties. At this point, it is not possible to determine the ultimate outcome of this litigation or the exposure, if any, the Company may have.
In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in the N. LaCopita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seeks unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that it acted in good faith and intends to vigorously defend its position. The Company, along with GMT and the other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a 23% working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. Due to the uncertainty of the final outcome, the Company has ceased to record revenue from the properties as of August 1, 2001, which net to the Company averaged approximately 1.4 MMcfe/d of production at the time the well was shut-in. In addition, the Company removed associated reserves of 1.4 Bcfe from its total proved reserves. The Company believes this potential loss is not material to its financial condition or results of operations.
The Company, as one of three original plaintiffs, filed a lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial District Court of Duval County, Texas, for fraud and breach of contract in connection with an agreement whereby BNP was obligated to drill a test well in an area known as the Slick Prospect in Duval County, Texas. The allegations of the Company in this litigation were, in general, that BNP gave the Company inaccurate and incomplete information on which the Company relied in entering into the transaction and in making its decision not to participate in the test well and the prospect, resulting in the loss of the Company's interest in the lease, the test well and four subsequent wells drilled in the prospect. The Company sought to enforce its interest in the prospect and sought damages or rescission, as well as costs and attorneys' fees. The case was originally filed in Duval County, Texas on February 25, 2000. The Company filed a lis pendens to protect its interest in the real property at issue.
In mid-March, 2000, the defendants filed an original answer and certain counterclaims against plaintiffs, seeking unspecified damages for slander of title, tortious interference with business relations and exemplary damages. The case proceeded to trial before the court (without a jury) on June 19, 2000, after the plaintiffs were found by the court to have failed to comply with procedural requirements regarding the request for a jury. After several days of trial, the case was recessed and later resumed on September 5, 2000. The court at that time denied the plaintiffs' motion for mistrial based on the court's denial of a jury trial. The court also ordered that the defendants' counterclaims would be the subject of a separate trial that would commence on December 11, 2000. The parties proceeded to try issues related to the plaintiffs' claims on September 5-13, 2000. Defendants filed a second amended answer and counterclaim and certain supplemental responses to a request for disclosure in which they stated that they were seeking damages in the amount of $33.5 million by virtue of an alleged lost sale of the subject properties, $17 million in alleged lost profits from other prospective contracts, and unspecified incidental and consequential damages from the alleged wrongful suspension of funds under their gas sales contract with the gas purchaser on the properties, alleged damage to relationships with trade creditors and financial institutions, including the inability to leverage the Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in defending against plaintiffs' claims and for 40% of any aggregate recovery in prosecuting their counterclaims. In subsequent deposition testimony, the defendants verbally alleged $26 million of damages by virtue of the alleged lost sale of the properties (as opposed to the $33.5 million previously sought), $7.5 million of damages by virtue of loss of a lease development opportunity and $100 million of damages by virtue of the loss of a business opportunity related to BNP's alleged inability to participate in a 3-D seismic project.
The Company also alleged that BNP, Seiskin Interests, LTD and Pagenergy Company, LLC breached a confidentiality agreement with the plaintiffs by obtaining oil and gas leases within an area restricted by that contract. This breach of contract allegation is the subject of an additional lawsuit by plaintiffs in the 165th District Court in Harris County, Texas. In this separate action, the Company is seeking damages as a result of defendants' actions as well as costs and attorneys' fees.
During the week of December 11-15, 2000, in Duval County BNP tried its counterclaims against Edge, and Edge presented its defenses to the counterclaims. BNP presented evidence that its damages were in the amounts of $19.6 million for the alleged lost sale of the properties, $35 million for the alleged loss of the lease development opportunity, and $308 million for the alleged loss of the opportunity related to participation in the 3-D seismic project. During the course of the trial, Edge presented its motion for summary judgment on the counterclaims based on the doctrine of absolute judicial proceeding privilege. The judge partially granted Edge's motion for summary judgment as it related to the filing of the lis pendens, but denied it with regard to the other allegations of BNP. The judge also granted Edge's plea in abatement relating to the breach of the confidentiality agreement, ruling that the District Court in Harris County has dominant jurisdiction of that issue.
On November 5, 2001, the court filed with the clerk and provided to the Company a final judgment that had been signed by the court, but not provided to the Company, on October 26, 2001. Pursuant to the terms of the judgment, the Company takes nothing on its claims against BNP and is denied any recovery of its interest in the lease, the prospect, or the wells of the Slick Prospect. Instead, the court confirmed title in the lease, prospect, and wells in BNP's affiliate. In addition, the Company was found to have tortiously and maliciously interfered with two different BNP contracts or prospective contracts, and BNP was awarded actual damages against the Company in the amount of $10 million and punitive damages in the amount of $5.1 million. The judgment does not reflect a credit in the amount of $1,945,000 to which the Company believes that it is entitled by reason of certain settlements by its two co-plaintiffs and co-counterdefendants.
On December 6, 2001, the Company agreed to settle this litigation. Pursuant to the settlement, the Company agreed to pay $2.5 million and to release its claims to interest in an area known as the Slick Prospect in Duval County, Texas. The parties to the settlement agreed to the dismissal of all claims, both in the 229th Judicial District Court of Duval County, Texas and in the 165th District Court in Harris County, Texas. The parties also agreed to set aside the judgment of the 229th Judicial District Court of Duval County, Texas against the Company and to a mutual release of all claims.
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 W. ELIAS has served as the Chief Executive Officer and Chairman of the Board of the Company since November 1998. Mr. Elias is a member 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 for more than 30 years, including senior management positions with Amoco Corporation, a major integrated oil and gas company. Mr. Elias has more than 40 years of experience in the oil and natural gas exploration and production business. He is 61 years old.
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 49 years old.
JOHN O. TUGWELL has served as Senior Vice President Production since December 2001 and prior to that served as Vice President of Production for the Company since March 1997. He 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. Mr. Tugwell is 38 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.
KIRSTEN A. HINK has served as Controller of the Company since December 31, 2000 and prior to that served as Assistant Controller from June 2000 to December 2000. She served as Controller of Benz Energy Inc., an oil and gas exploration company, from 1998 to June 2000. Prior thereto she served in financial and SEC reporting positions with Western Atlas, Inc. and Apache Corporation. Mrs. Hink received a B.S. in Accounting from Trinity University, San Antonio, Texas. Mrs. Hink is a Certified Public Accountant in the State of Texas.
C.W. MACLEOD has served as the Vice President Business Development and Planning for the Company since January 2002. From November 1999 to December 2001, he was Vice President Investment Banking
with Raymond James and Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick Energy Associates, Inc. where he was responsible for originating corporate finance and research products for energy clients. His previous experience includes positions as an independent petroleum geologist, a manager of exploration and production for an independent oil and gas producer and geologic positions with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S. in Geology and earned his M.B.A. from the University of Tulsa. Mr. MacLeod is a registered professional geologist in the state of Wyoming.
ROBERT C. THOMAS has served as Vice President, General Counsel and Corporate Secretary since March 1997. From February 1991 to March 1997, he served in similar capacities for the Company's corporate predecessor. From 1988 to January 1991, he was associate and acting general counsel for Mesa Limited Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D. degree in Law from the University of Texas at Austin.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 15, 2002, we estimate there were approximately 3,618 beneficial holders of our Common Stock. Our Common Stock is listed on the NASDAQ National Market ("NASDAQ") and traded under the symbol "EPEX". As of March 15, 2002, we had 9,351,215 shares outstanding and our closing price on NASDAQ was $5.30 per share. The following table sets forth, for the periods indicated, the high and low closing sales prices for our Common Stock as listed on NASDAQ.
We have never paid a dividend, cash or otherwise, and do not intend to in the foreseeable future. The payment of future dividends will be determined by our Board of Directors in light of conditions then existing, including our 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 -- We do not intend to pay dividends and our ability to pay dividends is restricted".
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 our financial statements and notes thereto, which follow:
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(1) Certain prior year balances have been reclassified to conform to the current year presentation.
(2) Deferred compensation expense includes the amortization of compensation costs related to restricted stock grants and the non-cash charge or credit related to requirements under FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation. At December 31, 2000, a charge was required under FIN 44 when the daily average market price of our stock exceeded the strike price of certain options. At December 31, 2001, our daily average market price was below the strike price of these options and as a result, a credit was required to reduce compensation expense except as it related to repriced options exercised in 2001.
(3) Basic and diluted earnings (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 (as defined below in ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a review of our financial position and results of operations for the periods indicated. Our 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
We were organized as a Delaware corporation in August 1996 in connection with our initial public offering (the "Offering") and the related combination of certain entities that held interests in the 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, we issued an aggregate of 4,701,361 shares of common stock and received in exchange for 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, we completed the Offering of 2,760,000 shares of our common stock generating proceeds of approximately $40 million, net of expenses.
We have evolved over that time from a prospect generation organization focused solely on high-risk, high-reward exploration to a team driven organization focused on a balanced program of exploration, exploitation, development and acquisition of oil and natural gas properties. Following a top-level management change in late 1998, a disciplined style of business planning and management was integrated into our technology-driven drilling activities. After giving effect to the time needed to make those changes, there have been significant activities that have resulted in growth in reserves, production and financial strength.
We use the full-cost method of accounting for our 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 our acquisition, exploration and development activities, are capitalized in a "full-cost pool" as incurred. We record depletion of our 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. For each of the years ended December 31, 2001, 2000 and 1999, respectively, no full cost ceiling test write down was necessary.
Due to the instability of oil and natural gas prices, we have entered into, from time to time, price risk management transactions (e.g., swaps, collars and floors) for a portion of our oil and 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 may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. Our hedging arrangements typically apply to only a portion of our production, providing only partial price protection against declines in oil and natural gas prices. We account for these transactions as hedging activities and, accordingly, gains and losses are included in oil and natural gas revenue during the period the hedged production occurs. At December 31, 2001, we were not a party to any hedging transactions. At December 2000, a natural gas collar was in place. The natural gas collar covered 4,000 MMbtus per day for the period January 1, 2001 to December 31, 2001 at a $4.50 per MMbtu floor and a $6.70 per MMbtu ceiling. On January 3, 2001, we closed out the hedge for the period February 1, 2001 to December 31, 2001 at a cost of $547,760. At December 31, 2000 and 1999, the fair value, gain (loss), of outstanding hedges was approximately $(1.1) million and $15,000, respectively. (See Note 5 to our consolidated financial statements).
Our revenue, profitability and future rate of growth and ability to borrow funds or obtain additional capital, and the carrying value of our properties, are substantially dependent upon prevailing prices for oil and natural gas. These prices are dependent upon numerous factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. A substantial or extended decline in oil and natural gas prices could have a material adverse effect on our financial condition, results of operations and access to capital, as well as the quantities of oil and natural gas reserves that we may economically produce.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000
Revenue and Production
Oil and natural gas revenue increased 25% from $23.8 million in 2000 to $29.8 million in 2001. For 2001, natural gas production comprised 86% of total production and contributed 88% of total revenue, oil and condensate comprised 10% of total production and contributed 9% of total revenue, and NGL's comprised 4% of total production and contributed 3% of total revenue. For 2000, natural gas production comprised 83% of total production and 84% of total revenue while oil and condensate production accounted for 9% of total production and 11% of revenue and NGLs production comprised 8% of total production and 5% of oil and gas revenue.
The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the years ended December 31, 2001 and 2000.
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(1) Includes the effect of hedging.
Natural gas revenue increased 31% from $20.0 million for the year ended December 31, 2000 to $26.2 million for 2001. Increased production and the favorable impact of higher natural gas prices were partially offset by the impact of a hedging loss. For the year ended December 31, 2001, natural gas production increased 19% from 14.2 Mcf/d in 2000 to 17.0 Mcf/d in 2001 resulting in an increase in revenue of approximately $4.1 million (based on 2000 comparable period prices). The average natural gas sales price for production in 2001 was $4.32 per Mcf, exclusive of hedging activity, compared to $4.14 per Mcf for 2000, exclusive of hedging activity. This increase in average price realized resulted in increased revenue of approximately $1.1 million (based on current year production). Included within natural gas revenue for the year ended December 31, 2001 and 2000 was $(0.9) million and $(1.5) million, respectively, representing losses from hedging activity. These losses decreased the effective natural gas sales price by $(0.15) per Mcf and $(0.30) per Mcf, for the years ended December 31, 2001 and 2000, respectively.
Revenue from the sale of oil and condensate totaled $2.8 million for the year ended December 31, 2001, an increase of 9% from the prior year total of $2.5 million. The year ended December 31, 2000 included net losses from oil hedge activity of $223,455. No oil hedges were in place for 2001. Production volumes for oil and condensate increased 19% to 317 Bbls/d for the year ended December 31, 2001 compared to 265 Bbls/d for the same prior year period. The increase in oil and condensate production caused an increase in revenue of approximately $535,300 (based on 2000 comparable period average prices). The average realized price for oil and condensate for the year ended December 31, 2001 was $23.94 per barrel compared to $28.47 per barrel, excluding the impact of net oil hedge losses of $(2.31) per barrel, in 2000. Lower average prices for the year 2001 resulted in a decrease in revenue of $524,000 (based on current year production).
Revenue from the sale of NGLs totaled $0.8 million for the year ended December 31, 2001, a decrease of 36% from the 2000 total of $1.3 million. Production volumes for NGLs for the year ended December 31, 2001 decreased 41%, from 210 Bbls/d to 125 Bbls/d, as compared to the year ended December 31, 2000. The decrease in NGL production decreased revenue by $509,600 (based on 2000 comparable period average prices). This decrease in production was largely due to high natural gas prices decreasing the economic value of NGL's and a resulting decision by management not to process our gas during several months of 2001. Favorable pricing for the year ended December 31, 2001 resulted in an increase in revenue of $62,500 (based on current year production). The average realized price for NGLs for the year ended December 31, 2001 was $17.74 per barrel compared to $16.37 per barrel for the same period in 2000.
Production of oil and natural gas was significantly impacted by our drilling results in the second half of 2000 and in 2001. We successfully drilled and completed 17 gross (7.081 net) wells in the year ended December 31, 2001 that added additional production and revenue for 2001. Gas production increases were due primarily to the drilling of, and strong performance from, the O'Connor Ranch wells, the Ibarra and La Jolla Parr wells on our La Jolla prospect, the Mire #1 well on our Horeb prospect and the Robertson #1 well on our Duson Frio prospect. Partially offsetting the favorable results of drilling were production declines on our older wells, primarily the Margo #1 and #2 wells.
Costs and Operating Expenses
Operating expenses for the year ended December 31, 2001 totaled $2.8 million compared to $2.0 million in the same period of 2000, an increase of 44%. Current year results were impacted by the increased number of wells operating in 2001 compared to the prior year as well as higher treating costs at the Austin facility for a portion of 2001, higher salt water disposal costs on our older wells, and higher well control insurance costs incurred in 2001 compared to the prior year. Operating expenses averaged $0.39 per Mcfe for the year ended December 31, 2001 compared to $0.31 per Mcfe for the prior year period. The increase in operating expenses on a Mcfe basis was due to the factors resulting in an overall increase in operating expenses described previously.
Severance and ad valorem taxes for the year ended December 31, 2001 increased 9% from $2.0 million in 2000, to $2.2 million in 2001, due to higher severance taxes paid on the increased revenue, primarily in the first quarter of 2001. On an equivalent basis, severance and ad valorem taxes were $0.30 per Mcfe and $0.32 per Mcfe for the years ended December 31, 2001 and 2000, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the year ended December 31, 2001 totaled $9.4 million compared to $7.6 million for the year ended December 31, 2000. Full cost DD&A on our oil and natural gas properties totaled $8.7 million for 2001 compared to $7.0 million in 2000. Depletion expense on a unit of production basis for the year ended December 31, 2001 was $1.22 per Mcfe, 10% higher than the 2000 rate of $1.11 per Mcfe. The higher depletion rate per Mcfe resulted in an increase in depletion expense of $0.8 million. For the year ended December 31, 2001, higher oil and natural gas production compared to the prior year period resulted in an increase in depletion expense of $1.0 million. The increase in the depletion rate was primarily due to a higher amortizable base in 2001 compared to the prior year.
In December 2001, we recorded costs of $3.5 million related to the settlement of our litigation with BNP. See Note 6 to our consolidated financial statements.
General and administrative expenses ("G&A") for the year ended December 31, 2001, excluding the deferred compensation expense discussed below, totaled $5.0 million, a 32% increase from the 2000 total of $3.8 million. The increase in costs was due primarily to bad debt expense of $525,000 reserved in 2001 ($225,000 of which related to purchases by an Enron affiliate), costs of $100,000 to purchase options from a former employee, higher salaries and related benefits, and higher legal and audit fees. For the years ended December 31, 2001 and 2000, G&A costs were reduced by overhead reimbursement fees of approximately $137,200 and $120,300, respectively. G&A on a unit of production basis for the year ended December 31, 2001 was $0.70 per Mcfe ($0.62 per Mcfe excluding the bad debt expense and the purchase of options) compared to $0.61 per Mcfe for the comparable 2000 period.
Deferred compensation cost reported in accordance with FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation was a credit of $(850,281) for the year ended December 31, 2001 compared to a charge of $899,548 in the comparable prior year period. FIN 44 requires, among other things, a non-cash charge to compensation expense if the price of our common stock on the last trading day of a reporting period is greater than the exercise price of certain options. FIN 44 could also result in a credit to compensation expense to the extent that the trading price declines from the trading price as of the end of the prior period, but not below the exercise price of the options. We adjust deferred compensation expense upward or downward on a monthly basis based on the trading price at the end of each such period as necessary to comply with FIN 44. We are required to report under this rule as a result of non-qualified stock options granted to employees and directors in prior years and re-priced in May of 1999, as well as certain options newly issued in conjunction with the repricing.
Also included in deferred compensation is amortization related to restricted stock awards granted during 2000 and 2001. For the years ended December 31, 2001 and 2000, such amortization totaled $353,371 and $105,250, respectively.
No unearned compensation was reported in 2001. Unearned compensation expense for the year ended December 31, 2000 totaled $22,696 and relates to restricted stock granted to executives at the completion of the Offering.
Included in other income (expense) was interest expense of $214,619 for the year ended December 31, 2001 compared to $171,783 in the same 2000 period. Interest expense, including facility fees, was $137,623 for the year 2001 on weighted average debt of $0.7 million compared to interest expense of $546,340 on weighted average debt of approximately $5.6 million for the same prior year period. Also included in interest expense for the years ended December 31, 2001 and 2000 was $101,398 and $24,720, respectively, representing amortization of deferred loan costs associated with a new credit facility. Capitalized interest for the year ended December 31, 2001 totaled $24,402 compared to $399,277 in the prior year. The reduction in capitalized interest resulted from lower interest costs incurred during the year ended December 31, 2001 compared to the same prior year period. Although gross interest expense has decreased compared to the prior year, the effect of less interest being capitalized to oil and natural gas properties has resulted in higher net interest costs reported in our results of operations.
Interest income totaled $127,717 for the year ended December 31, 2001 compared to $97,860 for the same period in 2000. The increase in interest income is due to the overall increase in funds invested in overnight money market funds.
Other income (expense) for the year ended December 31, 2000 also included a loss on the sale of our investment in Frontera of $(354,733) or $(0.04) per share.
An income tax benefit was recorded for the year ended December 31, 2001 of $818,897. As of December 31, 2001, approximately $18.2 million of net operating loss carryforwards have been accumulated that begin to expire in 2012. Based on our year-end 2001 projections, we now believe that we will fully realize our recorded tax assets. Accordingly, $818,897 in associated valuation reserves was reversed in 2001. Future financial statement income will necessitate income tax provisions at our effective rate. Currently, we do not anticipate a federal tax liability or making federal tax payments in 2002. For the year ended December 31,
2000, no tax expense or benefit was recorded because an allowance was provided to offset the tax benefits of certain tax assets.
For the year ended December 31, 2001, the Company had net income of $8.1 million, or $0.87 basic earnings per share, as compared to net income of $6.9 million, or $0.75 basic earnings per share, in 2000.
Weighted average shares outstanding increased from approximately 9.2 million for the year ended December 31, 2000 to 9.3 million in the comparable 2001 period. The increase was due primarily to options exercised and vesting of restricted stock during 2001.
YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999
Revenue and Production
Oil and natural gas revenue increased 64% from $14.5 million in 1999 to $23.8 million in 2000. For 2000, natural gas production comprised 83% of total production and contributed 84% of total revenue, oil and condensate comprised 9% of total production and contributed 11% of total revenue, and NGL's comprised 8% of total production and contributed 5% of total revenue. For 1999, natural gas production comprised 83% of total production and 81% of total revenue while oil and condensate production accounted for 10% of total production and 13% of revenue and NGLs production comprised 7% of total production and 6% of oil and gas revenue.
The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the years ended December 31, 2000 and 1999.
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(1) Includes the effect of hedging.
Natural gas revenue increased 70% from $11.8 million for the year ended December 31, 1999 to $20.0 million for 2000. The favorable impact of higher natural gas prices was partially offset by the impact of hedging losses and decreased production. The average natural gas sales price for production in 2000 was $4.14 per Mcf, exclusive of hedging activity, compared to $2.26 per Mcf for 1999, exclusive of hedging activity. This increase in average price realized resulted in increased revenue of approximately $9.7 million (based on current year production). Included within natural gas revenue for the year ended December 31, 2000 and 1999
was $(1.5) million and $(1.1) million, respectively, representing losses from hedging activity. These losses decreased the effective natural gas sales price by $(0.30) per Mcf and $(0.19) per Mcf, for the years ended December 31, 2000 and 1999, respectively. For the year ended December 31, 2000, natural gas production decreased 8% from 15.6 Mcf/d in 1999 to 14.2 Mcf/d in 2000 resulting in a decrease in revenue of approximately $1.1 million (based on 1999 comparable period prices).
Revenue from the sale of oil and condensate totaled $2.5 million for the year ended December 31, 2000 (including net losses from oil hedge activity of $223,454), an increase of 40% from the prior year total of $1.8 million. Favorable pricing for the year 2000 resulted in an increase in revenue of $1.2 million (based on current year production). The average realized price for oil and condensate for the year ended December 31, 2000 was $28.47 per barrel, excluding the impact of net oil hedge losses of $(2.31) per barrel, compared to $16.15 per barrel for the same period in 1999. Production volumes for oil and condensate decreased 14% to 265 Bbls/d for the year ended December 31, 2000 compared to 307 Bbls/d for the same prior year period. The decrease in oil and condensate production caused a decrease in revenue of approximately $244,900 (based on 1999 comparable period average prices).
Revenue from the sale of NGLs totaled $1.3 million for the year ended December 31, 2000, an increase of 38% from the 1999 total of $913,462. Favorable pricing for the year ended December 31, 2000 resulted in an increase in revenue of $323,500 (based on current year production). The average realized price for NGLs for the year ended December 31, 2000 was $16.37 per barrel compared to $12.16 per barrel for the same period in 1999. Production volumes for NGLs for the year ended December 31, 2000 increased 2%, from 206 Bbls/d to 210 Bbls/d, as compared to the year ended December 31, 1999. The increase in NGL production increased revenue by $20,700 (based on 1999 comparable period average prices).
Production of oil and natural gas was significantly impacted by the sale of certain oil and natural gas properties effective July 1, 1999 and April 1, 2000. Offsetting these declines was the adjustment in June 2000 for 19 months of revenue associated with payout on our McFaddin properties that reached payout in July 1998, but was not determined until June 2000. This adjustment resulted in recognition in 2000 of $391,300 on production of 173,800 Mcfe. In addition, we successfully drilled and completed 24 gross (9.06 net) wells in the year ended December 31, 2000 that added additional production and revenue for the current year period.
Costs and Operating Expenses
Operating expenses for the year ended December 31, 2000 totaled $2.0 million compared to $1.7 million in the same period of 1999, an increase of 13%. Results for 2000 were impacted by the recording in June 2000 of 19 months of lifting costs totaling approximately $119,000, associated with our McFaddin properties that reached payout in July 1998 but was not determined until June 2000. In addition, 2000 costs increased due to compression charges and salt water disposal costs on certain older properties. These additional costs more than offset the effect of lower costs resulting from the disposition of proved producing properties effective July 1, 1999, and corporate efforts focused on improving the operating structure in the field. Operating expenses averaged $0.31 per Mcfe for the year ended December 31, 2000 compared to $0.26 per Mcfe for the prior year period. The increase in operating expenses on a Mcfe basis was due to the factors resulting in an overall increase in operating expenses described previously and the sale of certain properties during the third quarter of 1999 that had lower overall average operating costs.
Severance and ad valorem taxes for the year ended December 31, 2000 increased 54% from $1.3 million in 1999 to $2.0 million in 2000 due primarily to higher severance taxes paid on the increased revenue, primarily in the fourth quarter of 2000. On an equivalent basis, severance and ad valorem taxes were $0.32 per Mcfe and $0.19 per Mcfe for the years ended December 31, 2000 and 1999, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the year ended December 31, 2000 totaled $7.6 million compared to $8.5 million for the year ended December 31, 1999. Full cost DD&A on our oil and natural gas properties totaled $7.0 million for 2000 compared to $7.8 million in 1999. Depletion expense on a unit of production basis for the year ended December 31, 2000 was $1.11 per Mcfe, 3% lower than the 1999 rate of $1.15 per Mcfe. For the year ended December 31, 2000, lower oil and natural gas
production compared to the prior year period resulted in a decrease in depletion expense of $218,400. The decrease in the depletion rate was primarily due to year-end reserve base additions and revisions.
General and administrative expenses ("G&A") for the year ended December 31, 2000, excluding the deferred compensation expense discussed below, totaled $3.8 million, a 16% decrease from the 1999 total of $4.5 million. The decrease in costs was due primarily to lower salaries and related benefits attributable to a work force reduction during January 2000. For the year ended December 31, 2000 and 1999, G&A was reduced by overhead reimbursement fees of approximately $120,300 and $285,000, respectively. G&A on a unit of production basis for the year ended December 31, 2000 was $0.61 per Mcfe compared to $0.67 per Mcfe for the comparable 1999 period.
A non-cash charge to compensation expense of $899,548, or $0.10 per share, was required in 2000 in accordance with FASB Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation." FIN 44 requires, among other things, a non-cash charge to compensation expense if the price of Edge's common stock on the last trading day of a reporting period is greater than the exercise price of certain options. FIN 44 could also result in a credit to compensation expense to the extent that the trading price declines from the trading price as of the end of the prior period, but not below the exercise price of the options. We adjust deferred compensation expense upward or downward on a monthly basis based on the trading price at the end of each such period as necessary to comply with FIN 44. The charge was related to non-qualified stock options granted to employees and directors in prior years and re-priced in May of 1999, as well as certain options newly issued in conjunction with the repricing.
Also included in deferred compensation for the year ended December 31, 2000 is amortization of $105,250 related to restricted stock awards granted during 2000.
Unearned compensation expense for the year ended December 31, 2000 totaled $22,696 compared to $349,623 in the prior year period. The amortization of unearned compensation expense is recognized from restricted stock granted to executives at the completion of the Offering. The decrease was due to the resignation of the former President and Chief Operating Officer in December 1999 at which time he vested in his remaining restricted stock grant. We charged to expense the unamortized unearned compensation associated with his restricted stock upon his resignation.
The other charge during 1999 of approximately $1.7 million primarily represented expenses incurred as a result of the resignation of our former President and Chief Operating Officer in 1999. As a result of his resignation we recorded a one-time charge of approximately $1.5 million to satisfy corporate obligations under his employment contract. Included in the $1.5 million was a $1.1 million non-cash amount relating to the vesting of the remaining balance of the executive's restricted common stock award granted concurrent with our Offering (see Note 9 to our consolidated financial statements). The balance of the charge primarily represented an accrual for workforce reduction and cash payments to be paid to the former executive from the date of his resignation to December 31, 2000.
Other income (expense) for the year ended December 31, 2000 consisted primarily of a loss on the sale of our investment in Frontera of $(354,733).
Also included in other income (expense) was interest expense of $171,783 for the year ended December 31, 2000 compared to $130,067 in the same 1999 period. Interest expense was $546,340 for the year 2000 on weighted average debt of $5.6 million compared to interest expense of $662,067 on weighted average debt of approximately $8.4 million for the same prior year period. Also included in interest expense for the year ended December 31, 2000 was $24,720 representing amortization of deferred loan costs associated with a new credit facility. Capitalized interest for the year ended December 31, 2000 totaled $399,277, a decrease of 25% over the prior year amount of $532,000 for the same period. The reduction in capitalized interest resulted from lower exploration activities during the year ended December 31, 2000 compared to the same prior year period. Although interest expense has decreased compared to the prior year, the effect of less interest being capitalized to oil and natural gas properties has resulted in higher net interest costs reported in our results of operations.
Interest income totaled $97,860 for the year ended December 31, 2000 compared to $51,855 for the same period in 1999. The increase in interest income is due to the overall increase in funds invested in overnight money market funds.
Due to our significant deferred tax assets, no tax expense was recorded for the year ended December 31, 2000 or 1999. Because of the uncertainty at December 31, 2000 and 1999 as to whether we would have future profitability, an allowance was provided to offset the tax benefits of certain tax assets.
For the year ended December 31, 2000 we had net income of $6.9 million, or $0.75 basic earnings per share, as compared to a net loss of $(3.7) million, in 1999.
Weighted average shares outstanding increased from approximately 8.7 million for the year ended December 31, 1999 to 9.2 million in the comparable 2000 period. The increase was due primarily to the private placement of 1.4 million shares of common stock in May 1999.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, we completed the Offering of 2,760,000 shares of our common stock at a public offering price of $16.50 per share. The Offering provided us with proceeds of approximately $40 million, net of expenses. We used approximately $12.7 million to repay our long-term outstanding indebtedness incurred under our revolving credit facility in place at the time, 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.
On May 6, 1999, we completed a "Private Offering" of 1,400,000 shares of common stock at a price of $5.40 per share. We also issued warrants, which were purchased for $0.125 per warrant, to acquire an additional 420,000 shares of common stock at $5.35 per share and are exercisable through May 6, 2004. At our election, the warrants may be called at a redemption price of $0.01 per warrant at any time after any date at which the average daily per share closing bid price for the immediately proceeding 20 consecutive trading days exceeds $10.70. No warrants have been exercised as of December 31, 2001. Total proceeds, net of offering costs, were approximately $7.4 million of which $4.9 million was used to repay debt under our revolving credit facility in place at the time, with the remainder being utilized to satisfy working capital requirements and to fund a portion of our exploration program. Pursuant to the terms of the private placement, we filed a registration statement with the Commission registering the resale of the shares of Common Stock and the warrants sold in the private placement, as well as the resale of any shares of Common Stock issued pursuant to such warrants.
We had cash and cash equivalents at December 31, 2001 of $793,287 consisting primarily of short-term money market investments, as compared to $247,981 at December 31, 2000. Working capital was $0.7 million as of December 31, 2001, as compared to $2.9 million at December 31, 2000. Excluding the current portion of long-term debt, working capital was $5.9 million at December 31, 2000.
Cash flows provided by operations were $22.2 million, $9.6 million and $5.6 million, for the years ended December 31, 2001, 2000, and 1999, respectively. The significant increase in cash flows provided by operations for the year ended December 31, 2001 is primarily due to higher net income in 2001, lower accounts receivable balances at December 31, 2001 compared to the prior year and higher accrued liabilities at the current year-end. High commodity prices during the fourth quarter of 2000 resulted in substantial accounts receivable balances for production revenue received in 2001 but prices were significantly lower at December 31, 2001 resulting in lower accounts receivable balances. Operating cash flows, before changes in working capital, for the years ended December 31, 2001, 2000 and 1999 were $16.8 million, $16.0 million and $6.3 million, respectively. The increase in operating cash flows from 2000 to 2001 was due primarily to higher oil and natural gas revenue partially offset by increased operating costs, including the $3.5 million litigation settlement in December 2001. The increase from 1999 to 2000 was due primarily to higher oil and natural gas revenue during 2000 as a result of higher production and average commodity prices.
We reinvest a substantial portion of our cash flows in our drilling, acquisition, land and geophysical activities. As a result, we used $29.0 million in investing activities during 2001, all of which were capital expenditures. Capital expenditures of $15.9 million were attributable to the drilling of 22 gross wells, 17 of which were successful. Acquisition costs totaled $6.7 million for the year ended December 31, 2001, and an additional $6.0 million in expenditures was attributable to land holdings, including $2.6 million for increased seismic data and other geological and geophysical expenditures. The remaining capital expenditures were associated with computer hardware and office equipment.
During the year ended December 31, 2000, we used $5.4 million in investing activities, including capital expenditures of $10.7 million. Capital expenditures of $5.7 million were attributed to drilling 26 gross wells, 24 of which were successful. Capital expenditures of $3.2 million were attributable to land holdings and $1.8 million was attributable to increased seismic data and other geological and geophysical expenditures. These expenditures were offset by proceeds from the sale of oil and natural gas properties of $1.8 million and net proceeds from the sale of our investment in Frontera of $3.5 million.
During the year ended December 31, 1999, we used $7.3 million of cash in investing activities including capital expenditures of approximately $14.6 million. Capital expenditures of $6.7 million were attributed to the drilling of 19 gross wells, 14 of which were successful. Capital expenditures of $2.7 million were attributable to increased land holdings and $5.1 million was attributable to increased seismic data and other geologic and geophysical expenditures. Capital expenditures of approximately $100,000 were used for the acquisition of computer hardware and office equipment. Capital expenditures were offset by proceeds from the sale of oil and natural gas prospects of $3.5 million. During August 1999, we completed a transaction in which we sold, effective July 1, 1999, our working interests in proved producing and undeveloped properties within our BTA and Spartan Extension 3-D project areas in Goliad and Victoria Counties, Texas. Proceeds from the sale were approximately $4.0 million.
Pursuant to a rights offering conducted by Frontera in November 1998, we agreed to purchase 44,027 shares of Frontera Common Stock plus such additional shares, if necessary, to maintain our then current 8.73% interest of the partially diluted outstanding Frontera Common Stock (assuming conversion of all preferred stock). As a result, we paid Frontera $116,671 in December 1998 for 44,027 shares of Frontera Common Stock, $5,626 in January 1999 for 2,123 shares of Frontera Common Stock and $116,672 in April 1999 for 44,027 shares of Frontera Common Stock bringing our total investment in Frontera to $3,867,233. We sold our interest in Frontera in June 2000 for net proceeds of $3.5 million.
We currently anticipate capital expenditures in 2002 to be approximately $18 million. Approximately $10.8 million is allocated to our expected drilling and production activities; $4.2 million is allocated to land and seismic activities; and $3.0 million relates to capitalized interest and G&A and other. We plan to fund these expenditures largely from cash flow from operations plus some modest incremental borrowings. We have not explicitly budgeted for acquisitions; however, we do expect to spend considerable effort evaluating acquisition opportunities. We expect to fund acquisitions through traditional reserve-based bank debt and, if required, through additional debt and equity financings.
Cash flows provided by financing activities totaled $7.4 million for the year ended December 31, 2001 including $11.0 million in borrowings and $4.0 million in repayments under our current credit facility. In addition, we received $390,421 in proceeds from the issuance of common stock related to options exercised in 2001. Cash flows used in financing activities in 2000 were $(4.0) million, including borrowings of $5.4 million and repayments of $9.2 million under our revolving credit facility and the predecessor facility. We also incurred loan costs of approximately $202,900 in establishing our new credit facility. Financing activities during 1999 were comprised of a private offering of common stock that generated net proceeds of $7.4 million offset by a net repayment of debt of $5.7 million.
Due to our active exploration, development and acquisition activities, we have experienced and expect to continue to experience substantial working capital requirements. We intend to fund our 2002 capital expenditures, commitments and working capital requirements through cash flows from operations, and to the extent necessary other financing activities. The projected 2002 cash flows from operations are estimated to be sufficient to fund our budgeted exploration and development program. We believe we will be able to generate
capital resources and liquidity sufficient to fund our capital expenditures and meet such financial obligations as they come due. In the event such capital resources are not available to us, our drilling and other activities may be curtailed. See ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- FORWARD LOOKING INFORMATION AND RISK FACTORS -- Significant Capital Requirements."
Credit Facility
In October 2000, we entered into a new credit facility (the "Credit Facility") with a bank. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December 31, 2001, $10.0 million in borrowings were outstanding under the Credit Facility. The Credit Facility matures October 6, 2003 and is secured by substantially all of our assets. Proceeds from the borrowings in 2001 under the Credit Facility were used to fund the December 2001 property acquisition and the payment to BNP for the litigation settlement.
Originally the borrowing base under the Credit Facility was $5 million and was subject to automatic reductions at a rate of $300,000 per month beginning October 31, 2000. In March 2001, the Credit Facility was amended to increase the borrowing base to $14 million, and to eliminate the $300,000 per month automatic reduction. In January 2002, the borrowing base was increased to $18 million. The borrowing base will be re-determined again during the second quarter of 2002 and is expected to include adjustments for the recent success of the Thibodeaux well in Louisiana, other drilling successes and the acquisition in late December 2001 of properties in South Texas that were not factored into the January 2002 borrowing base of $18 million, offset in part by ordinary declines in reserves from production.
The Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings and issues of capital stock, sales of oil and natural gas properties or other collateral, engaging in merger or consolidation transactions. The Credit Facility also prohibits dividends and certain distributions of cash or properties and certain liens. The Credit Facility also contains certain financial covenants. The EBITDA to Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in the agreement, for the four fiscal quarters then ended to (b) our consolidated interest expense for the four fiscal quarters then ended, to not be less than 3.5 to 1.0. The Working Capital ratio requires that the amount of our consolidated current assets less our consolidated current liabilities, as defined in the agreement, be at least $1.0 million. The Allowable Expenses ratio requires that (a) the aggregate amount of our year-to-date consolidated general and administrative expenses for the period from January 1 of such year through the fiscal quarter then ended to (b) our year-to-date consolidated oil and gas revenues, net of hedging activity, for the period from January 1 of such year through the fiscal quarter then ended, to be less than 0.40 to 1.0.
ACCOUNTING PRONOUNCEMENTS
Derivatives We adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in fair value of the derivative instrument will generally be reported in Other Comprehensive Income ("OCI"). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item.
When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in earnings prospectively.
We account for our natural gas and crude oil hedge derivative instruments as cash flow hedges under SFAS 133. Although the fair value of our derivative instruments fluctuates daily, as of January 1, 2001, the fair value of our natural gas hedge derivative instruments was approximately ($1.1) million, which was recorded in the Consolidated Balance Sheet on January 1, 2001. The ($1.1) million was recorded as a liability on our balance sheet as part of the transition adjustment related to our adoption of SFAS 133. The offset to this balance sheet adjustment was a decrease to "Accumulated Other Comprehensive Income", a component of stockholders' equity. In early January 2001, we closed out of our hedge obligation for the period from February 1, 2001 to December 31, 2001. In accordance with SFAS 133, the cost to close out of the hedge was recognized in net income over the period in which the hedged production occurred. As of December 31, 2001, the full loss from the close out of $547,760 has been recorded to net income. As of December 31, 2001, we were not a party to any hedging activity.
On June 29, 2001, the Financial Accounting Standards Board ("FASB") approved its proposed SFAS No. 141, ("SFAS 141") "Business Combinations," and SFAS No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets." Under SFAS 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001.
SFAS 142 will apply to all acquired intangible assets whether acquired singly, as part of a group, or in a business combination. The statement will supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible Assets," and will carry forward provisions in APB Opinion No. 17 related to internally developed intangible assets. Under this statement, goodwill will no longer be amortized but will be subject to annual impairment analysis. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. We do not have any goodwill or intangible assets recorded as of December 31, 2001.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement of obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. We are currently evaluating the effect of adopting Statement No. 143 on our financial statements and have not determined the timing of adoption.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of" and APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS No. 121. The standard also expands the scope of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. We adopted SFAS No. 144 effective January 1, 2002. The adoption did not have a material impact on the consolidated financial statements.
We do not expect the adoption of any of the above-mentioned standards to have a material effect on our consolidated financial statements.
HEDGING ACTIVITIES
In December 2000, we entered into a natural gas collar that covered 4,000 MMbtu per day for the period January 1, 2001 to December 31, 2001 at a floor of $4.50 per MMbtu and a ceiling of $6.70 per MMbtu. On
January 3, 2001, we closed out the hedge for the period February 1, 2001 to December 31, 2001 at a cost of $547,760.
As of December 31, 2001, we had no hedges in place. We believe that hedges should be used as a financial tool to protect against the effects of a leveraged capital structure, ensure project rates of return from acquisitions and to help management budget and plan. Recommendations with respect to hedging opportunities are made by both the financial and marketing departments to our management committee and Chief Executive Officer for approval. The administration of hedges, if any, is handled jointly by the finance, marketing and production departments.
In March 2002, we purchased a natural gas floor at $2.65 per MMbtu covering 18,000 MMbtus per day for the period April 1, 2002 to June 30, 2002 at a cost of $163,800. See ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- MARKETING."
TAX MATTERS
At December 31, 2001, we have cumulative net operating loss carryforwards ("NOLs") for federal income tax purposes of approximately $18.2 million that will begin to expire in 2012. We anticipate that all of these NOLs will be utilized in connection with federal income taxes payable in the future. In the fourth quarter of 2001 we reversed a valuation allowance that previously offset our deferred tax assets. To the extent that we have financial statement income in the future, we will require a tax provision in our consolidated statement of operations.
NOLs assume that certain items, primarily intangible drilling costs have been written off for tax purposes in the current year. However, we have not made a final determination if an election will be made to capitalize all or part of these items for tax purposes in the future.
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk from changes in interest rates and commodity prices. We use a credit facility, which has a floating interest rate, to finance a portion of our operations. We are not subject to fair value risk resulting from changes in our floating interest rates. The use of floating rate debt instruments provide a benefit due to downward interest rate movements but does not limit us to exposure from future increases in interest rates. Based on the year-end December 31, 2001 outstanding borrowings and a floating interest rate of 4.5%, a 10% change in interest rate would result in an increase or decrease of interest expense of approximately $43,200 on an annual basis.
In the normal course of business we enter into hedging transactions, including commodity price collars, swaps and floors to mitigate our exposure to commodity price movements, but not for trading or speculative purposes. Due to the instability of prices and to achieve a more predictable cash flow, we may put in place a hedge on a portion of our production. While the use of these arrangements may limit the benefit to us of increases in the price of oil and natural gas, it also limits the downside risk of adverse price movements. As of December 31, 2001 no hedges were in place.
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 IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
As noted in the Company's Current Report on Form 8-K filed on October 10, 2001, on October 4, 2001, the Company dismissed its independent accountant, Deloitte & Touche LLP, and engaged Arthur Andersen LLP as its new independent accountant and auditor. The decision to engage Arthur Andersen, LLP and dismiss Deloitte & Touche LLP was recommended by the Audit Committee and approved by the Board of Directors.
None of the reports of Deloitte & Touche LLP on the financial statements of the Company during their engagement contained an adverse opinion or was qualified or modified as to uncertainty, audit scope or accounting principles. Further, during the Company's two fiscal years ended December 31, 1999 and December 31, 2000 and for the period from January 1, 2001 to October 4, 2001, there were no disagreements between the Company and Deloitte & Touche LLP on any matter of accounting principles, or auditing scope or procedure, which disagreement, if not resolved to the satisfaction of Deloitte & Touche LLP, would have caused them to make reference to the subject matter of the disagreements in connection with their report on the financial statements for such years. There were no reportable events (as defined in Regulation S-K, Item 304(a)(1)(v)) during the Company's two fiscal years ended December 31, 1999 and December 31, 2000 and for the period from January 1, 2001 to October 4, 2001. During the Company's two fiscal years ended December 31, 1999 and December 31, 2000 and for the period from January 1, 2001 to October 4, 2001, the Company did not consult with Arthur Andersen LLP regarding any of the matters or events set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.
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 2002 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, 2001. Pursuant to Item 401(b) of Regulation S-K certain of the information required by this item with respect 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.
- ---------------
* Filed herewith.
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K: The Company filed the following reports on Form 8-K during the quarter ended December 31, 2001:
The Company filed with the Securities and Exchange Commission during the quarter ended December 31, 2001, a Current Report on Form 8-K dated October 4, 2001, that reported a change in auditors.
The Company filed with the Securities and Exchange Commission during the quarter ended December 31, 2001, a Current Report on Form 8-K dated November 5, 2001, that reported the status of certain litigation.
The Company filed with the Securities and Exchange Commission during the quarter ended December 31, 2001, a Current Report on Form 8-K dated December 6, 2001, that reported the status of certain litigation.
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
/s/ JOHN W. ELIAS
-------------------------------------- John W. Elias Chief Executive Officer and Chairman of the Board
Date: March 28, 2002
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.
EDGE PETROLEUM CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
None.
All 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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors, Edge Petroleum Corporation:
We have audited the accompanying consolidated balance sheet of Edge Petroleum Corporation (a Delaware corporation) and subsidiaries as of December 31, 2001, and the related consolidated statements of operations, cash flows and stockholders' equity for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States. 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, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2001, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for its derivative instruments and hedging activities.
ARTHUR ANDERSEN LLP
Houston, Texas March 5, 2002
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors, Edge Petroleum Corporation Houston, Texas
We have audited the accompanying consolidated balance sheet of Edge Petroleum Corporation (a Delaware Corporation) (the "Company") as of December 31, 2000, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the two years in the period ended December 31, 2000. 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 auditing standards generally accepted in the United States of America. 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 consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2000, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP Houston, Texas March 19, 2001
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 the 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. ORGANIZATION AND NATURE OF OPERATIONS
General Edge Petroleum Corporation (the "Company") was organized as a Delaware corporation in August 1996 in connection with its initial public offering and the 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 initial public offering of 2,760,000 shares of its common stock (the "Offering") generating proceeds of approximately $40 million, net of expenses.
Nature of Operations The Company is an independent energy company engaged in the exploration, development, acquisition 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. During 2001, the Company added a new focus area in the northern Rocky Mountains that it expects to become a core area in 2002. The Company currently controls interests in almost 250,000 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.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation The consolidated financial statements 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.
Other Charge On December 31, 1999, but effective January 3, 2000, James D. Calaway resigned as President, Chief Operating Officer and Director of the Company. As a result of his resignation the Company recorded a one-time charge of approximately $1.5 million to satisfy corporate obligations under his employment contract. Included in the $1.5 million is a $1.1 million non-cash amount relating to vesting of the remaining balance of Mr. James Calaway's restricted common stock award granted concurrent with the Company's Offering (see Note 9). The balance of the 1999 other charge primarily represents an accrual for workforce reduction and cash payments to be paid to Mr. Calaway from the date of his resignation to December 31, 2000.
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 Properties Investments in oil and natural gas properties are accounted for using the full cost method of accounting. All costs associated with the exploration, development and acquisition of oil and natural gas properties, including salaries, benefits and other internal costs directly attributable to these activities, are capitalized. The Company capitalized $1.6 million, $1.3 million and $2.0 million of these internal costs in 2001, 2000 and 1999, respectively.
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 indicate 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.
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The depletion rates per Mcfe for the years ended December 31, 2001, 2000 and 1999 were $1.22, $1.11 and $1.15, respectively.
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. No adjustment related to the ceiling test was required during December 31, 2001, 2000 or 1999.
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 (see Note 7).
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, collars and floors) for a portion of its oil and 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 may limit the benefit to the Company of increases in the price of oil and natural gas, it may also limit the downside risk of adverse price movements. The Company's hedging arrangements, to the extent it enters into any, apply to only a portion of its production and provide only partial price protection against declines in oil and 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 revenue during the period the hedged transactions occur (see Note 5).
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") that were convertible into common stock. The Company paid $3.6 million for these shares. Frontera develops and operates oil and gas projects in emerging market areas around the world.
Pursuant to a rights offering conducted by Frontera in November 1998, the Company agreed to purchase 44,027 shares of Frontera common stock (the "Frontera Common Stock") plus such additional shares, if necessary, to maintain its then current 8.73% interest of the partially diluted outstanding Frontera Common Stock (assuming conversion of all preferred stock). As a result, the Company paid Frontera $116,671 in December 1998 for 44,027 shares of Frontera Common Stock, $5,626 in January 1999 for 2,123 shares of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Frontera Common Stock and $116,672 in April 1999 for 44,027 shares of Frontera Common Stock bringing its total investment in Frontera to $3.9 million.
The Company sold its investment in Frontera in June 2000 for proceeds of $3.6 million and paid related fees of $87,500 resulting in a loss on the sale of investment of $354,733.
Stock-Based Compensation The Company accounts for stock options under Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. As allowed by SFAS No. 123, "Accounting for Stock Based Compensation," ("SFAS No. 123") the Company has continued to apply APB Opinion No. 25 for purposes of determining net income and to present the pro forma disclosure required by SFAS No. 123.
The Company is subject to reporting requirements of Financial Accounting Standards Board ("FASB") Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation that requires a non-cash charge to deferred compensation expense if the price of the Company's common stock on the last trading day of each reporting period is greater that the exercise price of certain stock options. After the first such adjustment is made, each subsequent period is adjusted upward or downward to the extent that the trading price exceeds the exercise price of the options. The charge is related to non-qualified stock options granted to employees and directors in prior years and re-priced in May 1999, as well as certain options newly issued in conjunction with the repricing (see Note 9).
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 and warrants having exercise prices less than the average market price of the common stock using the treasury stock method. During the year ended December 31, 1999, the Company reported a net loss, thus the effects of stock options were antidilutive (See Note 9).
Financial Instruments The Company's financial instruments consist of cash, receivables, payables, long-term debt and oil 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, 2001 and 2000 approximates fair value because the interest rates are variable and reflective of market rates. No hedges were outstanding at December 31, 2001. The fair value, gain (loss), of outstanding hedges was approximately $(1.1) million at December 31, 2000.
Derivatives The Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended, requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, a liability or firm commitment, then the changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows then the changes in the fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the period in which earnings are impacted by the hedged item.
When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in earnings prospectively.
The Company accounts for its natural gas and crude oil hedge derivative instruments as cash flow hedges, as defined. Although the fair value of the Company's derivative instruments fluctuates daily, as of January 1, 2001, the fair value of our natural gas hedge derivative instrument was approximately ($1.1) million, which was recorded as a liability on the balance sheet in January 2001 as part of the transition adjustment related to the Company's adoption of SFAS 133. The offset to this balance sheet adjustment was a decrease to "Accumulated other comprehensive income", a component of stockholders' equity. The entire amount related to 2001 anticipated transactions and was reclassified to earnings during 2001. At December 31, 2001, all hedging gains and losses had been recognized in earnings. The Company believes the adoption of SFAS 133 will result in more volatility in its financial statements than in the past.
Comprehensive Income As of December 31, 2001, 2000 and 1999, there were no adjustments ("Other Comprehensive Income") to net income (loss) in deriving comprehensive income.
Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 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 significant credit losses on such receivables; however, in 2001, the Company reserved $525,248 related to non-payments from purchasers of the Company's oil and natural gas. No bad debt expense was recorded in 2000 or 1999. The Company cannot ensure that similar such losses may not be realized in the future.
Accounting Pronouncements On June 29, 2001, the FASB approved its proposed SFAS No. 141, ("SFAS 141") "Business Combinations," and SFAS No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets." Under FAS 141, all business combinations should be accounted for using the purchase method of accounting; use of the pooling-of-interests method is prohibited. The provisions of the statement will apply to all business combinations initiated after June 30, 2001.
SFAS 142 will apply to all acquired intangible assets whether acquired singly, as part of a group, or in a business combination. The statement will supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible Assets," and will carry forward provisions in APB Opinion No. 17 related to internally developed intangible assets. Under this statement, goodwill will no longer be amortized but will be subject to annual impairment analysis. All of the provisions of the statement should be applied in fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company does not have any goodwill or intangible assets recorded as of December 31, 2001.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement of obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The standard is effective for fiscal years beginning after June 15, 2002, with
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
earlier application encouraged. We are currently evaluating the effect of adopting Statement No. 143 on our financial statements and have not determined the timing of adoption.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the accounting and reporting for the impairment or disposal of long-lived assets and supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of" and APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS No. 144 establishes one accounting model for long-lived assets to be disposed of by sale as well as resolves implementation issues related to SFAS No. 121. The standard also expands the scope of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The Company adopted SFAS No. 144 effective January 1, 2002. The adoption did not have a material impact on the consolidated financial statements.
The Company does not expect the adoption of any of the above-mentioned standards to have a material effect on our consolidated financial statements.
Reclassifications Certain prior year balances have been reclassified to conform to the current year presentation.
3. PROPERTY AND EQUIPMENT
At December 31, 2001 and 2000, property and equipment consisted of the following:
The Company uses the full-cost method of accounting for its oil and natural gas properties. Unevaluated oil and natural gas properties are not subject to amortization and consist of the cost of unevaluated 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 any costs impaired added to 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. Interest cost capitalized in 2001, 2000 and 1999, respectively, relating to unproved properties was $24,400, $399,300, and $531,700.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes the cost of the properties not subject to amortization for the year the cost was incurred:
Under the full-cost method, a sale of oil and natural gas properties, whether or not being amortized currently, is accounted for as an adjustment of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves.
4. LONG-TERM DEBT
In October 2000, the Company entered into a new credit facility (the "Credit Facility") with a bank. Borrowings under the Credit Facility bear interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December 31, 2001, $10.0 million in borrowings were outstanding under the Credit Facility. The Credit Facility matures October 6, 2003 and is secured by substantially all of the Company's assets.
Originally the borrowing base under the Credit Facility was $5 million and was subject to automatic reductions at a rate of $300,000 per month beginning October 31, 2000. In March 2001, the Credit Facility was amended to increase the borrowing base to $14 million, and to eliminate the $300,000 per month automatic reduction. In January 2002, the borrowing base was increased to $18 million. The borrowing base will be re-determined again during the second quarter of 2002.
The Credit Facility provides for certain restrictions, including but not limited to, limitations on additional borrowings and issues of capital stock, sales of oil and natural gas properties or other collateral, engaging in merger or consolidation transactions. The Credit Facility also prohibits dividends and certain distributions of cash or properties and certain liens. The Credit Facility also contains certain financial covenants. The EBITDA to Interest Expense Ratio requires that (a) consolidated EBITDA, as defined in the agreement, of the Company for the four fiscal quarters then ended to (b) the consolidated interest expense of the Company for the four fiscal quarters then ended, to not be less than 3.5 to 1.0. The Working Capital ratio requires that the amount of the Company's consolidated current assets less its consolidated current liabilities, as defined in the agreement, be at least $1.0 million. The Allowable Expenses ratio requires that (a) the aggregate amount of the Company's year to date consolidated general and administrative expenses for the period from January 1 of such year through the fiscal quarter then ended to (b) the Company's year to date consolidated oil and gas revenues, net of hedging activity, for the period from January 1 of such year through the fiscal quarter then ended, to be less than 0.40 to 1.0. At December 31, 2001, the Company was in compliance with the above-mentioned covenants.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 2001 and 2000, debt and long-term debt consisted of the following:
5. HEDGING ACTIVITIES
The impact on oil and natural gas revenue from hedging activities for the three years ended December 31, 2001, 2000 and 1999 was as follows:
The Company's natural gas hedging activities are entered into on a 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 revenue for the three years ended December 31, 2001 was approximately $(0.9) million, $(1.5) million and $(1.1) million, respectively, representing net losses from hedging activity. Included within oil and condensate revenue for the year ended December 31, 2000 was $(223,454) representing net (losses) from hedging activity. During December 2000, the Company entered into a natural gas collar covering 4,000 MMbtu per day for the period January 1, 2001 to December 31, 2001 with a floor of $4.50 per MMBtu and a ceiling of $6.70 per MMbtu. On January 3, 2001, the Company closed out the hedge for the period February 1, 2001 to December 31, 2001 at a cost of $547,760. No hedges were outstanding at December 31, 2001. At December 31, 2000 and 1999, the fair value of outstanding hedges was approximately $(1.1) million and $15,000, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. COMMITMENTS AND CONTINGENCIES
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, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a potential material adverse effect on the Company's financial condition, results of operations or cash flows, except for the litigation described below. The Company does not believe that the ultimate outcome of this litigation will have a material adverse effect on the Company.
In October 2001, the Company was sued by certain mineral owners in its Mew lease, upon which the Company and its partners drilled and completed the Mew No. 1 well in the Brandon Area, Duval County, Texas. The suit names the Company, Santos USA and Mark Smith, an independent landman, as Defendants, and is filed in the 229th Judicial District Court of Duval County, Texas. The suit seeks a declaratory judgment to set aside certain quitclaim deeds between the Mew lessors that were intended to result in a partition of the mineral estate between the various members of the Mew family in the land where the well is located and other lands. The pleadings allege failure of consideration, fraud, failure to consummate the partition, bad faith trespass and conversion. As part of the leasing effort for the prospect, some members of the Mew family had sought to partition their minerals under the tracts where they owned the surface in full. The Mew heirs, from whom the Company acquired leases, could lose a portion of their mineral interest if the quitclaim deeds are set aside. Were this to happen, it could have the effect of voiding the Company's leases as to an undivided one-third of the unit acreage for the Mew well and the Mew lease. Plaintiffs seek unspecified actual and exemplary damages against the Company and Santos arising out of the alleged fraud committed by the Company and Mark Smith. They also seek damages from Santos for the value of the oil and natural gas produced and saved from the Mew well, or alternatively, for the value of the oil and natural gas produced less the cost of drilling, completing and operating the well. The Company has a 12.5% working interest in the well. To date, the Mew well has produced $5.7 million in net revenue and has cost $3.6 million to drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and 4.6 Bcf. The Company has filed an answer in the case. Santos has filed a plea of abatement asking that the case be dismissed for failure to join necessary and indispensable parties. At this point, it is not possible to determine the ultimate outcome of this litigation or the exposure, if any, the Company may have.
In July 2001, the Company was notified of a prior lease in favor of a predecessor of ExxonMobil purporting to be valid and covering the same property as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part of a unit in the N. LaCopita Prospect in which the Company owns a non-operating interest. The operator of the lease, GMT, filed a petition for, and was granted, a temporary restraining order against ExxonMobil in the 229th Judicial Court in Starr County, Texas, enjoining ExxonMobil from taking possession of the Neblett wells. Pending resolution of the underlying title issue, the temporary restraining order was extended voluntarily by agreement of the parties, conditioned on GMT paying the revenues into escrow and agreeing to provide ExxonMobil with certain discovery materials in this action. ExxonMobil has filed a counterclaim against GMT and all the non-operators, including the Company, to establish the validity of their lease, remove cloud on title, quiet title to the property, and for conversion, trespass and punitive damages. ExxonMobil seeks unspecified damages for the lost profits on the sale of the hydrocarbons from this property, and for a determination of whether the Company and the other working interest owners were in good faith or bad faith in trespassing on this lease. If a determination of bad faith is made, the parties will not be able to recover their costs of developing this property from the revenues therefrom. While there is always a risk in the outcome of the litigation, the Company believes there is no question that it acted in good faith and intends to vigorously defend its position. The Company, along with GMT and the other partners, are attempting to negotiate a settlement with ExxonMobil that would allow GMT et al (including the Company) to participate for their respective shares of a 23% working interest in the Neblett unit, and would allow for the recovery of well costs. If the case cannot be settled and the title issue is decided unfavorably, the Company believes that it will ultimately be able to recover its costs as a good faith trespasser. Due to the uncertainty of
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the final outcome, the Company has ceased to record revenue from the properties as of August 1, 2001, which net to the Company averaged approximately 1.4 MMcfe/d of production at the time the well was shut-in. In addition, the Company removed associated reserves of 1.4 Bcfe from its total proved reserves. The Company believes this potential loss is not material to its financial condition or results of operations.
The Company, as one of three original plaintiffs, filed a lawsuit against BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial District Court of Duval County, Texas, for fraud and breach of contract in connection with an agreement whereby BNP was obligated to drill a test well in an area known as the Slick Prospect in Duval County, Texas. The allegations of the Company in this litigation were, in general, that BNP gave the Company inaccurate and incomplete information on which the Company relied in entering into the transaction and in making its decision not to participate in the test well and the prospect, resulting in the loss of the Company's interest in the lease, the test well and four subsequent wells drilled in the prospect. The Company sought to enforce its interest in the prospect and sought damages or rescission, as well as costs and attorneys' fees. The case was originally filed in Duval County, Texas on February 25, 2000. The Company filed a lis pendens to protect its interest in the real property at issue.
In mid-March, 2000, the defendants filed an original answer and certain counterclaims against plaintiffs, seeking unspecified damages for slander of title, tortious interference with business relations and exemplary damages. The case proceeded to trial before the court (without a jury) on June 19, 2000, after the plaintiffs were found by the court to have failed to comply with procedural requirements regarding the request for a jury. After several days of trial, the case was recessed and later resumed on September 5, 2000. The court at that time denied the plaintiffs' motion for mistrial based on the court's denial of a jury trial. The court also ordered that the defendants' counterclaims would be the subject of a separate trial that would commence on December 11, 2000. The parties proceeded to try issues related to the plaintiffs' claims on September 5-13, 2000. Defendants filed a second amended answer and counterclaim and certain supplemental responses to a request for disclosure in which they stated that they were seeking damages in the amount of $33.5 million by virtue of an alleged lost sale of the subject properties, $17 million in alleged lost profits from other prospective contracts, and unspecified incidental and consequential damages from the alleged wrongful suspension of funds under their gas sales contract with the gas purchaser on the properties, alleged damage to relationships with trade creditors and financial institutions, including the inability to leverage the Slick Prospect, and attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in defending against plaintiffs' claims and for 40% of any aggregate recovery in prosecuting their counterclaims. In subsequent deposition testimony, the defendants verbally alleged $26 million of damages by virtue of the alleged lost sale of the properties (as opposed to the $33.5 million previously sought), $7.5 million of damages by virtue of loss of a lease development opportunity and $100 million of damages by virtue of the loss of a business opportunity related to BNP's alleged inability to participate in a 3-D seismic project.
The Company also alleged that BNP, Seiskin Interests, LTD and Pagenergy Company, LLC breached a confidentiality agreement with the plaintiffs by obtaining oil and gas leases within an area restricted by that contract. This breach of contract allegation is the subject of an additional lawsuit by plaintiffs in the 165th District Court in Harris County, Texas. In this separate action, the Company is seeking damages as a result of defendants' actions as well as costs and attorneys' fees.
During the week of December 11-15, 2000, in Duval County BNP tried its counterclaims against Edge, and Edge presented its defenses to the counterclaims. BNP presented evidence that its damages were in the amounts of $19.6 million for the alleged lost sale of the properties, $35 million for the alleged loss of the lease development opportunity, and $308 million for the alleged loss of the opportunity related to participation in the 3-D seismic project. During the course of the trial, Edge presented its motion for summary judgment on the counterclaims based on the doctrine of absolute judicial proceeding privilege. The judge partially granted Edge's motion for summary judgment as it related to the filing of the lis pendens, but denied it with regard to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the other allegations of BNP. The judge also granted Edge's plea in abatement relating to the breach of the confidentiality agreement, ruling that the District Court in Harris County has dominant jurisdiction of that issue.
On November 5, 2001, the court filed with the clerk and provided to the Company a final judgment that had been signed by the court, but not provided to the Company, on October 26, 2001. Pursuant to the terms of the judgment, the Company takes nothing on its claims against BNP and is denied any recovery of its interest in the lease, the prospect, or the wells of the Slick Prospect. Instead, the court confirmed title in the lease, prospect, and wells in BNP's affiliate. In addition, the Company was found to have tortiously and maliciously interfered with two different BNP contracts or prospective contracts, and BNP was awarded actual damages against the Company in the amount of $10 million and punitive damages in the amount of $5.1 million. The judgment does not reflect a credit in the amount of $1,945,000 to which the Company believes that it is entitled by reason of certain settlements by its two co-plaintiffs and co-counterdefendants.
On December 6, 2001, the Company agreed to settle this litigation. Pursuant to the settlement, the Company agreed to pay $2.5 million and to release its claims to interest in an area known as the Slick Prospect in Duval County, Texas. The parties to the settlement agreed to the dismissal of all claims, both in the 229(th) Judicial District Court of Duval County, Texas and in the 165(th) District Court in Harris County, Texas. The parties also agreed to set aside the judgment of the 229(th) Judicial District Court of Duval County, Texas against the Company and to a mutual release of all claims.
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 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, 2001, the Company was obligated under noncancelable operating leases. Following is a schedule of the remaining future minimum lease payments under these leases:
Rent expense for the years ended December 31, 2001, 2000 and 1999 was $578,952, $499,033 and $511,270, respectively.
7. 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Significant components of the Company's deferred tax liabilities and assets as of December 31, 2001 and 2000 are as follows:
The Company's provision (benefit) for income taxes consists of the following:
During 2001, the Company determined that it was more likely than not that future taxable income would be sufficient to realize its recorded tax assets, accordingly the remaining valuation allowance was reversed.
The differences between the statutory federal income taxes calculated using a federal tax rate of 35% and the Company's effective tax rate is summarized as follows:
At December 31, 2001, the Company had cumulative net operating loss carryforwards ("NOLs") for federal income tax purposes of approximately $18.2 million that will begin to expire in 2012. The Company anticipates that all of these NOLs will be utilized in connection with federal income taxes payable in the future. NOLs assume that certain items, primarily intangible drilling costs have been written off for tax purposes 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 in the future.
8. 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
matching contributions to the Plan are discretionary. For the years ended December 31, 2001, 2000 and 1999, the Company contributed $60,516, $53,926, and $81,990, respectively, to the Plan.
9. EQUITY AND STOCK PLANS
Equity Offerings On March 3, 1997, the Combination was 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 approximately $40.0 million, net of offering costs of approximately $5.4 million.
Private Offering On May 6, 1999, the Company completed a private offering of 1,400,000 shares of common stock at a price of $5.40 per share. The Company also issued warrants, which were purchased for $0.125 per warrant, to acquire an additional 420,000 shares of common stock at $5.35 per share and are exercisable through May 6, 2004. At the election of the Company, the warrants may be called at a redemption price of $0.01 per warrant at any time after any date at which the average daily per share closing bid price for the immediately preceding 20 consecutive trading days exceeds $10.70. No warrants have been exercised as of December 31, 2001. Total proceeds, net of offering costs, were approximately $7.4 million of which $4.9 million was used to repay debt under the previous revolving credit facility with the remainder being utilized to satisfy working capital requirements and to fund a portion of the Company's exploration program.
Stock Plan 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 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 2-10 years. An aggregate of 1,200,000 shares of common stock have been reserved for grants under the Incentive Plan, of which 364,652 shares were available for future grants at December 31, 2001. Shares of common stock awarded as restricted stock are subject to vesting requirements and subject to risk of forfeiture until earned by continued employment or service. During 2001, awards for 100,800 shares of restricted stock were made having a value in the range of $4.58 to $8.88 based on the market value on each award date. During 2000, awards for 161,300 shares of restricted stock were made having a market value of $3.00 per share as of the award date. Shares of common stock associated with these awards will be issued, subject to continued employment, ratably over three years in accordance with the award's vesting schedule, beginning on the first anniversary of the date of grant. Compensation expense is amortized over the vesting period and offset to additional paid in capital. Amortization of deferred compensation related to restricted stock awards totaled $353,371 and $105,250, respectively, for the years ended December 31, 2001 and 2000.
Effective May 21, 1999, the Company amended and restated the Incentive Plan. In conjunction with those and other amendments of the Incentive Plan, the Company exchanged, on a voluntary basis, 556,488 outstanding nonqualified stock options of certain employees and Directors of the Company for 326,700 new common stock options in replacement of those options. The exercise price of the replacement options was $7.06, which represents the fair market value on the date of grant. The replaced options have a ten-year term with 50% of the options vesting immediately on the date of grant with the remaining 50% vesting on May 21, 2000. On May 21, 1999, in conjunction with the repricing, the Company also issued 99,800 new ten-year common stock options to employees, which vest 100% on May 21, 2001. The exercise price of the new options was $7.06, which represents the fair market value on the date of grant. On June 1, 1999, the Company issued 21,000 ten-year common stock options to non-employee directors with an exercise price of $7.28 per share, which represents fair market value at the date of grant, vesting 100% on June 1, 2001.
Deferred compensation cost reported in accordance with FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation was a credit of $(850,281), or $(0.09) per share, for
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the year ended December 31, 2001 compared to a charge of $899,548, or $0.10 per share in the comparable prior year period. FIN 44 requires, among other things, a non-cash charge to compensation expense if the price of Edge's common stock on the last trading day of a reporting period is greater than the exercise price of certain options. FIN 44 could also result in a credit to compensation expense to the extent that the trading price declines from the trading price as of the end of the prior period, but not below the exercise price of the options. The Company will adjust deferred compensation expense upward or downward on a monthly basis, based on the trading price at the end of each such period as necessary to comply with FIN 44. We are required to report under this rule as a result of non-qualified stock options granted to employees and directors in prior years and re-priced in May of 1999, as well as certain options newly issued in conjunction with the repricing as discussed above.
Effective January 8, 1999, as a component of his employment agreement with the Company, John Elias, CEO and Chairman of the Board, was granted options outside of the Incentive Plan for the purchase of 200,000 shares of common stock. These options vest and become exercisable one-third upon issue, and one- third upon each of January 1, 2000 and January 1, 2001. These amounts are included within options granted for 1999. In January 2000, Mr. Elias was granted additional options outside of the Incentive Plan for the purchase of 50,000 shares of common stock. These options vest and become exercisable 100% in January 2002. In January 2001, Mr. Elias was granted additional options outside the Incentive Plan for the purchase of another 50,000 shares of common stock. These options vest and become exercisable 100% in January 2003. In April 2001, Mr. Elias was granted 14,000 shares of restricted stock under the Incentive Plan valued at $7.75 per share, the market value on the award date. These shares are issued ratable over three years in accordance with the award's vesting schedule, beginning on the first anniversary of the date of grant. Compensation expense is amortized over the vesting period and offset to additional paid in capital. The amortization of compensation expense related to this award was included in the amounts discussed above. Below is a summary of option and restricted stock grants to Mr. Elias:
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(1) Exercise price equals the fair market value on the date of grant.
(2) Value was $7.75 per share, the market value on the date of grant.
In addition, as of the date of the Combination, Old Edge had in place a stock incentive plan that 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, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjustment for the conversion, the option price per share of common stock for each of the two 48,922 grants was approximately $4.09 and $2.04, respectively. Options for the purchase of 48,922 shares of common stock were exercised during 1997. The remaining 48,922 shares of common stock were exercised during 2001.
Unearned Compensation Expense Unearned compensation expense is amortized to operations over the corresponding vesting period. No unearned compensation expense was reported in 2001. Unearned compensation expense for the years ended December 31, 2000 and 1999 totaled $22,696 and $349,623, respectively, and relates to restricted stock granted to executives at the completion of the Offering.
Effective December 31, 1999, Mr. James D. Calaway resigned as President and Chief Operating Officer and a Director of the Company. In connection with his resignation his remaining restricted stock, 93,552 shares, became fully vested. Included in "Other charge" for 1999 is the amortization of approximately $1.1 million of unearned compensation expense resulting from the vesting of those restricted shares.
A summary of the status of the Company's stock options and changes as of and for each of the three years ended December 31, 2001 is presented below:
The Company purchased 133,645 options from a former employee at a cost of $100,000 included in general and administrative costs for the year ended December 31, 2001.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the Company's stock options categorized by class of grant at December 31, 2001 is 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, with the exception of amounts recognized in relation to the FIN 44 effect of the repricing, restricted stock awards and options repurchased. Had compensation expense for the Company's stock options granted during the years ended December 31, 2001, 2000 and 1999 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 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 years ended December 31, 2001, 2000 and 1999: expected volatility based on historical volatility of daily Common Stock Prices (80%, 83% and 70%, 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 expected option exercise period of 8 years for all periods (with the exercise occurring at the end of such period) and a forfeiture rate of 0-10% over the vesting period of such options.
Following is the pro forma effect of SFAS No. 123 and its impact on net income (loss) and earnings (loss) per basic and diluted share for the three years ended December 31, 2001, 2000 and 1999.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Computation of Earnings per Share 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.
For the year ended December 31, 1999, the Company reported a net loss, thus the effects of stock options and warrants were antidilutive.
10. RELATED PARTY TRANSACTIONS
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 historically received a monthly management fee for managing the Essex Joint Ventures, the general partner of each of which is a related party. No management fees were recorded for the year ended December 31, 2001 or 2000. For the year ended December 31, 1999, the Company recorded management fees totaling $52,560 and recorded this amount as a reduction of general and administrative expenses. In addition, these agreements stipulated that the Company was entitled to be reimbursed for certain direct general and administrative expenses and other reimbursable costs. No such amounts were due or invoiced by the Company to the Essex Joint Ventures for the year ended December 31, 2001. The Company is no longer the manager for these ventures. At December 31, 2001, there were no receivables from the Essex Joint Ventures owed to the Company. At December 31, 2000 and 1999, the Company had a receivable from the Essex Joint Ventures of $21,110 and $58,651, respectively, relating to these management fees, direct expenses, and costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pursuant to a Purchase and Sale Agreement dated as of November 9, 1999, the Company sold 18,872 shares of Common Stock to Mr. James C. Calaway. In exchange for such stock, the Company received from Mr. Calaway his working interests in all the Company's prospects, leases and areas of mutual interest.
11. SUBSEQUENT EVENTS (UNAUDITED)
In March 2002, the Company purchased a floor on 18,000 MMbtus per day at $2.65 per MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of $163,800. The floor structure provides a minimum realized price for the protected volume, yet preserves any upside in gas prices.
12. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. A summary of non-cash investing and financing activities for the years ended December 31, 2001, 2000 and 1999 is presented below:
In March 2001, 42,103 shares of common stock were issued representing one-third of a restricted stock award granted March 2, 2000. The value of the restricted stock on the date of grant was $3.00 per share.
In December 2001, 1,033 shares of restricted stock were issued valued at $4,834 based on the quoted market price on the date of issuance.
In May 2000, a portion of the annual retainer due our directors was paid by the issuance of 9,648 shares of common stock valued at $30,000, based on quoted market prices on the date of issuance.
For the year ended December 31, 2000, forfeitures of restricted stock were recorded with respect to 5,600 shares valued at $11,528.
In June 1999, a portion of the annual retainer due our directors was paid by the issuance of 4,809 shares of restricted common stock valued at $29,479, based on the quoted market prices on the date of issuance.
In November 1999, we issued 18,872 shares of common stock in exchange for working interests in certain prospects, leases and areas of mutual interest valued at $92,500.
For the year ended December 31, 1999, forfeitures of restricted stock were recorded with respect to 325 shares valued at $4,024.
Supplemental Disclosure of Cash Flow Information
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. 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 for the three months ended December 31, 2001 is $3.5 million for the settlement of litigation with BNP.
Included in operating expenses for the three months ended March 31, 2001, is a non-cash credit of $(755,372), to compensation expense as required by FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation. In the second quarter of 2001, an additional credit of $(95,353) was included in operating expenses related to FIN 44.
Included in operating expenses for the three months ended December 31, 2000, is a non-cash charge of $899,548, to compensation expense as required by FIN 44.
14. 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."
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (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:
Results of Operations Results of operations for the Company's oil and natural gas producing activities are summarized below:
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 Company's 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 2001 is shown below:
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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
EXHIBIT INDEX
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* Filed herewith.
+ Incorporated by reference as indicated.