10-Q 1 form10q3rdq.txt FORM 10-Q -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ________________ FORM 10-Q (Mark One) [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-26662 PANACO, Inc. (Exact name of registrant as specified in its charter) Delaware 43 - 1593374 (State or other jurisdiction of (I.R.S. Employer Identification incorporation or organization) Number) 1100 Louisiana Street, Suite 5100 Houston, Texas 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 970-3100 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ___X___ No _______. 24,359,695 shares of the registrant's $.01 par value Common Stock were outstanding on September 30, 2001. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- PANACO, Inc. Condensed Balance Sheets ASSETS

The accompanying notes are an integral part of this statement. 2 PANACO, Inc. Condensed Balance Sheets LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

The accompanying notes are an integral part of this statement. 3 PANACO, Inc. Statements of Operations For the Nine Months Ended September 30, (Unaudited)

The accompanying notes are an integral part of this statement. 4 PANACO, Inc. Consolidated Statements of Operations For the Three Months Ended September 30, (Unaudited)

The accompanying notes are an integral part of this statement. 5 PANACO, Inc. Statement of Cash Flows For the Nine Months Ended September 30, (Unaudited)

The accompanying notes are an integral part of this statement. 6 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) Note 1 - BASIS OF PRESENTATION In the opinion of management, the accompanying unaudited condensed financial statements contain all adjustments necessary to present fairly the Company's financial position as of September 30, 2001 and December 31, 2000 and the results of its operations and cash flows for the periods ended September 30, 2001 and 2000. Most adjustments made to the financial statements are of a normal, recurring nature. Although the Company believes that the disclosures are adequate to make the information presented not misleading, certain information and footnote disclosures, including significant accounting policies, normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC"). A more complete description of the accounting policies followed by the Company are set forth in Note 1 to the Company's financial statements in Form 10-K for the year ended December 31, 2000. These financial statements should be read in conjunction with the financial statements and notes included in the Form 10-K. The Company restated its financial results for the first three quarters of 2000. The adjustments reflect an increase in the Company's gas imbalance payable and associated reduction of revenues in the quarters to which the imbalance relates. The changes reflect adjustments to natural gas production and revenues, depletion, income before income taxes and net income. The adjustments to the first nine months of 2000 revenues, depletion, depreciation and amortization and net income were $(1,688,000), $(387,000) and $(808,000), respectively. The adjustments to the third quarter of 2000 revenues, depletion, depreciation and amortization and net income were $(1,007,000), $(293,000) and $(444,000), respectively. Note 2 - OIL AND GAS PROPERTIES AND PIPELINES AND EQUIPMENT The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under the successful efforts method, lease acquisition costs are initially capitalized. Exploratory drilling costs are also capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory costs are expensed. All development costs are capitalized. Non-drilling exploratory costs, including geological and geophysical costs and rentals, are expensed. Unproved leaseholds with significant acquisition costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Unproved leaseholds whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to ultimately prove nonproductive, based on experience, are amortized over an average holding period. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds. Provision for depletion is determined on a depletable unit basis using the unit-of-production method. Estimated future abandonment costs are recorded by charges to depreciation and depletion expense over the lives of the proved reserves of the properties. The Company performs a review for impairment of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review. For each depletable unit determined to be impaired, an impairment loss equal to the difference between the carrying value and the fair value of the depletable unit will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of expected future cash flows computed by applying estimated future oil and gas prices, as determined by management, to estimated future production of oil and gas reserves over the economic lives of the reserves. Future cash flows are based upon the Company's estimate of proved reserves. 7 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) The Company recognized asset impairments during the first nine months of 2001 totaling $6.9 million, relating to both proved and unproved properties. Based on the decision by the Company to discontinue development of proved reserves, discovered in 1998, the Company recorded an impairment of $1.1 million for the capital incurred in initially discovering those reserves. In addition, in connection with the Company's regular review of the recoverability of proved reserves carrying values, an impairment of $5.8 million was recorded based on reserve and price reductions for several properties which the Company considers non-core. Property and equipment are carried at cost. Oil and natural gas pipelines and equipment are depreciated on the straight-line method over their estimated lives, primarily fifteen years. Other property is also depreciated on the straight-line method over their estimated lives, ranging from three to ten years. Fees for processing oil and natural gas for others are treated as a reduction of lease operating expense related to the facilities and infrastructure. During the second quarter of 2001, the Company sold its interest in the High Island 309 and 310 Fields to the operator of the property. The consideration received by the Company included cash, before adjustment, of $3.8 million and the forgiveness of a $1.4 million gas imbalance payable by the Company. The sale closed on June 29, 2001 and the proceeds from the buyer were adjusted to the effective date of the sale, January 1, 2001, and reduced by amounts owed by the Company to the buyer. Both the Company and the buyer also agreed to dismiss lawsuits filed by each party against the other as part of the purchase and sale agreement. The sale resulted in a gain of $4.0 million during the second quarter of 2001. Note 3 - CASH FLOW INFORMATION Cash payments for interest totaled $7.2 million and $9.3 million for the first nine months of 2001 and 2000, respectively. Cash payments for income taxes totaled $26,000 and $50,000 for the first nine months of 2001 and 2000, respectively. Note 4 - EARNINGS PER SHARE CALCULATIONS Basic and diluted earnings per share for the first nine months of each year were based on the year-to-date weighted average share outstanding of 24,346,444 in 2001 and 24,241,116 for 2000. The Company did have potential common shares outstanding during 2001 in the form of stock options, however, the potential common shares are excluded from the diluted earnings per share calculation because the Company had a net loss for both the nine months and quarter ended September 30, 2001 and the potential common shares would have been anti-dilutive. The Company also had stock options outstanding during 2000, however, these stock options were out of the money during the period prior to their expiration in June 2000. Note 5 - RESTRICTED DEPOSITS Pursuant to existing agreements with former property owners and in accordance with requirements of the U.S. Department of Interior's Minerals Management Service ("MMS"), the Company has put in place surety bonds and/or escrow agreements to provide satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain fields are no longer in use. As part of its agreement with the underwriter of the surety bonds, the Company has established bank trust and escrow accounts in favor of either the surety bond underwriter or the former owners of the particular fields. 8 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) In the West Delta Fields and the East Breaks 109 and 110 Fields, the Company established an escrow for both Fields in favor of the surety bond underwriter, who provides a surety bond to the former owners of the West Delta Fields and to the MMS. The balance in this escrow account was $5.2 million at September 30, 2001 and requires quarterly deposits of $375,000 until June 2003, decreasing to $125,000 until the account balance reaches $7.8 million. In the East Breaks 165 and 209 Fields the Company established an escrow account in favor of the surety bond underwriter, who provides surety bonds to both the MMS and the former owner of the Fields. The balance in this escrow account was $4.6 million at September 30, 2001 and requires quarterly deposits of $250,000 until the account balance reaches $6.5 million. The Company has also established an escrow account in favor of BP under which the Company will deposit 10% of the net cash flows from the properties, as defined in the agreement, from the properties acquired from BP. This escrow account balance was $0.7 million at September 30, 2001. Note 6 - COMMITMENTS AND CONTINGENCIES An action was filed against the Company in Louisiana, along with Exxon Pipeline Company ("Exxon"), National Energy Group, Inc. ("NEG"), Mendoza Marine, Inc., Shell Western Exploration & Production, Inc. ("Shell"), and the Louisiana Department of Transportation and Development. The petition was filed in August 1998, and alleges that, in 1997 and perhaps earlier, leaks from a buried crude oil pipeline contaminated the plaintiffs' property. Pursuant to the purchase and sale agreement between PANACO and NEG, NEG is required to indemnify the Company from any damages attributable to NEG's operations on the property after the sale. Pursuant to another purchase and sale agreement, the Company may owe indemnity to Shell and Exxon, from whom the property was acquired prior to selling same to NEG. The Company believes that it has insurance coverage for the claims asserted in the petition, and has notified all insurance carriers that might provide coverage under its policies. In 1999 NEG filed chapter 11 bankruptcy and emerged in late 2000. Some discovery has occurred in the case, but is not yet complete. Therefore, at this point it is not possible to evaluate the likelihood of an unfavorable outcome, or to estimate the amount or range of potential loss. The Company is subject to various other legal proceedings and claims which arise in the ordinary course of business. In the opinion of management, the amount of liability, if any, with the respect to these actions would not materially affect the financial position of the Company or its results of operation. Note 7 - LONG-TERM DEBT The Company maintains a Credit Facility that is a reducing, revolving loan and is collateralized by a first mortgage on the Company's properties. The amount available to the Company under the Credit Facility is determined by a borrowing base typically based on the estimated value of the properties under mortgage to the lender, less any amounts borrowed under the Credit Facility. In October 1999 the Company put in place a new, $60 million Credit Facility with Foothill Capital Corp. ("Foothill") as the Agent for the lenders. The Foothill facility had an initial term of two years with two six-month extension options available at the sole option of the Company. The borrowing base under the Foothill facility at the expiration of the initial term was $60 million. 9 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) In November 2001, the Company amended the Foothill facility to, among other changes, extend the expiration date an additional two years. The new Credit Facility is a $40 million facility with a borrowing base of $40 million. At September 30, 2001, $26.1 million was outstanding under the facility, with availability of $12.7 million, of which $1.3 million was reserved under a letter of credit. The borrowing base is subject to monthly determinations made using internally prepared engineering reports, using a two-year average of NYMEX future commodity prices and are based on our semi-annual third party reserve reports. Indebtedness under this Credit Facility constitutes senior indebtedness with respect to the Senior Notes. The amendment also reduced the interest rates, administrative fees and servicing fees charged the Company. Interest on the loan is computed at Wells Fargo's prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%, depending on the percentage of the facility being used and the pricing option is the choice of the Company. The loan agreement contains certain covenants including an EBITDA (as defined in the agreement) to interest expense ratio of at least 2.0 to 1.0 and a working capital ratio (as defined in the agreement) of at least .25 to 1.0. The loan agreement also contains limitations on additional debt, dividends, mergers and sales of assets. Note 8 - INCOME TAXES During the second quarter of 2000, the Company determined that it was more likely than not that its deferred tax assets would be realized. This valuation was based on several factors, including estimates for future oil and natural gas prices. Projections of future taxable income were sufficient to utilize all of the deferred tax assets due to higher commodity prices and reserve additions, therefore the valuation allowance was removed. The Company performs a review of the deferred tax asset including the associated utilization estimates for the asset. The factors considered in the review include historical utilization, tax planning strategies that may improve the utilization and market conditions at the time of review. The Company has and is continuing to evaluate tax planning strategies for utilizing its deferred tax asset including the sale of assets, when appropriate. Based on its review during the third quarter of 2001, the Company determined that it was more likely than not that its deferred tax asset would not be utilized and reestablished a valuation allowance against the deferred tax asset. This valuation was due to, among other factors, the significant decrease in oil and natural gas prices and reduced reserve estimates from the second quarter of 2000, losses in the prior years, excluding 2000, and current estimates of results for 2001. These projections of future taxable income are management's best estimates, using current reserve estimates, estimates of future commodity prices and other information currently available. While the Company believes that the assumptions used in these projections are reasonable, future events, including changes in commodity prices, could result in a reduction in some or all of the deferred tax asset valuation allowance in future periods. Note 9 - ADOPTION OF SFAS 133 On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge. Currently, the Company 10 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) uses only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income/Loss, a component of Stockholders' Equity (Deficit), to the extent the hedge is effective. The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in Accumulated Other Comprehensive Income/Loss related to cash flow hedges that become ineffective remain unchanged until the related production is delivered. If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Gains and losses on hedging instruments related to Accumulated Other Comprehensive Income/Loss and adjustments to carrying amounts on hedged production are included in natural gas or crude oil production revenues in the period that the related production is delivered. Gains and losses of hedging instruments, which represent hedge ineffectiveness and changes in the time value component of options, are included in Other Income/Loss in the period in which they occur. The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuation on natural gas and crude oil production. At September 30, 2001, the Company had one derivative instrument outstanding, a natural gas swap. For 2001, the Company entered into an option to put 1,000 barrels of oil per day at $25.00 per barrel to a purchaser through September 30, 2001 for a total of 273,000 barrels. In addition, the Company entered into a natural gas price swap covering 6.6 Bcf of production for the entire twelve months of 2001 at an average price of $4.91 per MMBtu. For the period of October 1 through December 31, 2001 the Company's average price for its natural gas swap is $4.56 per MMBtu. The Company recognized a $0.3 million increase in earnings, pre-tax, for the cumulative effect of adopting SFAS 133 on January 1, 2001 and for the nine months ended September 30, 2001 the Company recognized a $0.3 million decrease in earnings, pre-tax, related to the decrease in the value of the put option. For the Company's natural gas swap, on January 1, 2001, in accordance with the transition provisions of SFAS 133, the Company recorded a loss of $9.9 million in Other Comprehensive Income/Loss representing the cumulative effect of an accounting change to recognize the fair value of the natural gas swap. The Company also recorded cash flow hedge derivative liabilities of $9.9 million in accounts payable and accrued liabilities. During the first nine months of 2001, the Company realized pre-tax income of $0.1 million on hedging activity incurred in the first nine months 2001, which were transferred from Other Comprehensive Income/Loss to natural gas revenues for the production months the hedge related. The Company also recognized Other Income of $1.1 million, pre-tax, for the ineffective portion of the natural gas swap. At September 30, 2001 $2.8 million of deferred net gains on derivative instruments recorded in Other Comprehensive Income/Loss are expected to be reclassified to earnings during the next twelve months. All hedge transactions are subject to the Company's risk management policy and are approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and 11 PANACO, Inc. NOTES TO CONDENSED FINANCIAL STATEMENTS (Unaudited) strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Note 10 - COMPREHENSIVE INCOME Comprehensive income includes net income and certain items recorded directly to shareholders' equity and classified as Accumulated Other Comprehensive Loss. The Company recorded Other Comprehensive Income for the first time in the first quarter of 2001. On January 1, 2001, upon adoption of SFAS 133, the Company recorded a charge to Accumulated Other Comprehensive Loss of $9.9 million for the fair value of the Company's cash flow hedges. The following table illustrates the calculation of comprehensive income for the nine months ended September 30, 2001:

12 PART I Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Forward-looking Statements With the exception of historical information, the matters discussed in this Form 10-Q contain forward-looking statements. The forward-looking statements we make, not only in this Form 10-Q, but also in press releases, oral statements and other reports that we file with the Securities and Exchange Commission ("SEC") are intended to be subject to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements relate to future results of operations, the ability to satisfy future capital requirements, the growth of our Company and other matters. You are cautioned that all forward-looking statements involve risks and uncertainties. The words "estimate," "anticipate," "expect," "predict," "believe" and similar expressions are intended to qualify these forward-looking statements. We believe that the forward-looking statements that we make are based on reasonable expectations. However, due to the nature of the business we are in and other factors, we cannot assure you that the actual results will not differ from those expectations. General The oil and natural gas industry has experienced significant volatility in recent years because of the fluctuatory relationship of the supply of most fossil fuels relative to the demand for those products and other uncertainties in the world energy markets. You should consider the volatility of this industry when reading the following. Liquidity and Capital Resources In implementing our business strategy of increasing our reserve base, increasing cash flows from operations and to reduce debt, we reinvest cash flows from operations as capital expenditures or to reduce debt. During the first nine months of 2001, net cash provided by operating activities totaled $34.3 million, which, along with cash on hand, was used to fund capital expenditures, net of property sales, of $32.6 million and for required restricted deposit increases of $1.8 million. Net capital expenditures of $32.6 million for the first nine months of 2001 represents a 48% increase over capital expenditures totaling $22.0 million for the comparable period of 2000. For the year 2001, our Board of Directors has approved a $45 million capital budget. We believe that cash flows from operations and availability under our Credit Facility will fund this level of capital expenditures. In an attempt to reduce interest costs, we keep as little cash on hand as possible and apply available cash to our Credit Facility balance. The timing of receipt of monies due us and the payment of amounts due others also affects our working capital. These two factors cause us to typically have a working capital deficit. On September 30, 2001 this working capital deficit totaled $15.9 million. We believe that cash flows from operations and borrowing availability under our Credit Facility will be sufficient to fund this working capital deficit in addition to ongoing operations and capital expenditures. Credit Facility The primary source of capital beyond discretionary cash flows is our Credit Facility. The Credit Facility is secured by a first mortgage on most of our oil and natural gas properties, and is used primarily as development capital on properties that we own and for acquiring additional oil and natural gas 13 reserves. We may also use the Credit Facility for working capital support, to provide letters of credit and general corporate purposes. In October 1999 we put in place a $60 million Credit Facility with Foothill Capital Corp. ("Foothill") as the Agent for the lenders. The Foothill facility had an initial term of two years with two six-month extension options available at the sole option of the Company. The borrowing base under the Foothill facility at the expiration of the initial term was $60 million. In November 2001, we amended the Foothill facility to, among other changes, extend the expiration date an additional two years. The new Foothill facility is a $40 million facility with a borrowing base of $40 million. The borrowing base is subject to monthly determinations made using internally prepared engineering reports, using a two-year average of NYMEX future commodity prices and are based on our semi-annual third party reserve reports. Indebtedness under this Credit Facility constitutes senior indebtedness with respect to the Senior Notes. At September 30, 2001, $26.1 million was outstanding under the facility, with availability of $12.7 million, of which $1.3 million was reserved under a letter of credit. The reduction in the Credit Facility was part of management's focus on controlling costs and reduces the amount of unused line fees charged by the lender. Management believes that the $40 million provides the liquidity and flexibility needed to continue its capital expenditure program and implement our business strategy. The amendment also reduced the interest rates, administrative fees and servicing fees charged the Company. Interest on the loan is computed at Wells Fargo's prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%, depending on the percentage of the facility being used and the pricing option is the choice of the Company. The loan agreement contains certain covenants including an EBITDA (as defined in the agreement) to interest expense ratio of at least 2.0 to 1.0 and a working capital ratio (as defined in the agreement) of at least .25 to 1.0. The loan agreement also contains limitations on additional debt, dividends, mergers and sales of assets. We were in compliance with the terms of the Foothill facility on September 30, 2001 and anticipate compliance throughout the term of the loan. Senior Note offering On October 9, 1997, we issued $100 million principal amount of 10 5/8% Senior Notes due October 1, 2004. Interest on the Notes is payable semi-annually in arrears on each April 1 and October 1, commencing April 1, 1998. Commodity price hedges We follow a hedging strategy designed to protect against the possibility of severe price declines due to market volatility. We may also make hedging decisions to assure a payout of a specific acquisition or development project. For 2001, we have hedged 18,000 MMBtu per day of natural gas for the entire year. The hedge is a swap, based on the NYMEX closing prices when the swap was put in place in November 2000. The swap prices range from a high of $6.415 per MMBtu in January to a low of $4.485 per MMBtu in October and average $4.914 per MMBtu for the year. The corresponding settlement prices are based on the last three trading days on the NYMEX for the month to which the swap prices relate. If the swap prices are higher than the settlement prices, the counterparty will pay us the price difference for the total MMBtu hedged for that month. If the swap prices are less than the settlement prices, we will pay the counterparty the price difference for the total MMBtu hedged for that month. 14 The Company also purchased an option to put oil to a purchaser at an agreed upon price. The put option was for 1,000 barrels of oil per day from January 1 through September 30 at a NYMEX price of $25.00 per barrel. The cost of the put option was $1.00 per barrel, or $365,000. At September 30, 2001 the fair value of the remaining hedges was a gain of $3.9 million, pre-tax. The fair value of commodity hedging instruments is the estimated amount that we would receive or pay to settle the applicable commodity hedging instrument at the reporting date, taking into account the difference between NYMEX prices or index prices at year-end and the contract price of the commodity hedging instrument. On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under SFAS 133, all derivative instruments are recorded on the balance sheet at fair value. See Note 9 to the Company's Condensed Financial Statements for a discussion of activities involving derivative financial instruments during the first nine months of 2001. We produce and sell natural gas, oil and natural gas liquids. As a result, our financial results are significantly affected by changes in these commodity prices. We use derivative financial instruments to attempt to hedge our exposure to changes in the market price of natural gas and oil. While commodity financial instruments are intended to reduce exposure to declines in these market prices, the commodity financial instruments may also limit gains from increases in the market price of natural gas and oil. Capital expenditures Net capital expenditures totaled $32.6 million for the first nine months of 2001, representing a 48% increase over the $22.0 million of capital expenditures incurred in the comparable period of 2000. The capital expenditures incurred in 2001 were concentrated primarily in four fields in the Gulf of Mexico, as follows. In late June 2000, we began a development program in the East Breaks 109 and 110 Fields, with the aid of 3-D seismic, which we purchased in late 1998. These Fields are in approximately 700 feet of water in the Gulf of Mexico. We own a 100% working interest in these Fields and are the operator. During the first nine months of 2001 we spent $14.1 million in continuing the drilling program in these Fields, $3.8 million of which related to the #A-4 well, an exploratory well that was not completed and accounted for as exploratory dry hole expense. The remaining capital was primarily incurred on the #A-13 well which was completed and began production during the second quarter, in addition to the #A-7 well, which was completed and began production in late January 2001. On April 13, 2001 PANACO acquired 100% of West Delta Block 52 for $4 million, before purchase price adjustments to the effective date of the acquisition, January 1, 2001. The acquisition included approximately 1.1 million barrels of proved reserves and is contiguous to our existing West Delta Fields. During the second quarter we spent $3.2 million in capital expenditures, in addition to the acquisition cost, primarily for the completion of previously shut-in wells to new gas zones. PANACO also incurred capital expenditures totaling $9.1 million in the East Breaks 205 and 161 Fields during the first nine months of 2001. We own a 25% working interest in the first well, the East Breaks 205 #1 well, which was drilled and completed during the second quarter. The #1 well, which is operated by Unocal, was successful and is expected to begin production during the fourth quarter of 2001. The Block 161 #2 well was spudded during the second quarter and completed during the third quarter of 2001. This well was also successful and is expected to begin production during the fourth quarter of 2001. PANACO also owns a 25% working interest in the Block 161 #2 well. 15 During the third quarter of 2001, we spudded a new well in the Umbrella Point Field, the State Tract 76 #3 well in which we own a 40% working interest and are the operator. The State Tract 76 #3 well is an exploratory well which will test the prolific Deep Vicksburg formation at approximately 15,700 feet. Based on current estimates, our net dry hole exposure for this well is approximately $3 million. Through September 30, 2001 we had incurred $2.0 million in net costs in drilling this well. The costs are capitalized pending determination of proved reserves once the well has reached the targeted depths. The remaining capital expenditures were incurred primarily on several properties in which we own smaller interests. Results of Operations For the nine months ended September 30, 2001 and 2000: One of the most significant factors affecting our business is the market price of oil and natural gas that we produce and sell. In late 1997 and continuing through early 1999, both oil and natural gas prices were lower than they had been in the proceeding years. A turnaround was seen in 1999 and through the first quarter of 2001 where we benefited from a steady increase in realized prices for both oil and natural gas. Since March 2001, both oil and natural gas prices have decreased from their highs earlier in 2001. Revenues Oil and natural gas sales totaled $63.1 million during the first nine months of 2001, an increase of $1.2 million, or 2% when compared to the first nine months of 2000. While both oil and natural gas production decreased in 2001, improved natural gas prices have offset lower oil prices and lower production. Production and Prices:

Both oil and natural gas production decreased when comparing the first nine months of 2001 to the comparable period of 2000. The most significant decreases in natural gas production were in the Umbrella Point Field (1,769 MMcf), East Breaks 160 and 161 Fields (898 MMcf ) and the East Breaks 165 Field (651 MMcf), which were due primarily to natural declines in the production from those fields. In addition, naturally declining production and the sale of the High Island 309 and 310 Fields (808 MMcf) during the second quarter of 2001 contributed to the decreased production. Those declines were somewhat offset by increases in the East Breaks 109 and 110 Fields 16 (2,192 MMcf) and the West Delta Fields (923 MMcf), a focal point for part of our 2001 capital expenditure program. Likewise, oil production has decreased from the East Breaks 165 Field (124 Mbbl) and East Breaks 160 and 161 Fields (47 Mbbl) due to lower capital expenditures in those fields and the rapid production declines from the wells in those fields, which are inherent in the areas that we operate. The bulk of the capital expenditures in 2001 are for projects that should produce natural gas, rather than oil. We also recognized a gain of $4.0 million on the sale of an oil and natural gas property during the second quarter of 2001. We sold PANACO's entire interest in High Island Blocks 309 and 310 to the operator of the fields for cash, the assumption of a gas imbalance liability and the dismissal of a lawsuit the operator had filed against us for non-payment of invoices. The property sale was completed on June 29, 2001. Cost and Expenses Lease operating expenses increased $4.1 million, to $20.5 million, during the first nine months of 2001 compared to $16.4 million in 2000. On an Mcf equivalent ("Mcfe") basis, lease operating expenses also increased to $1.60 in 2001 from $1.08 in 2000. During 2001, we have spent a significant amount of capital for repairs and maintenance of PANACO's offshore platforms, which, due to the nature of the work, are expensed as incurred. Some of these expenses are required by the regulatory agencies in the Gulf of Mexico. We expect this program to continue throughout 2001, specifically in the East Breaks area of the Gulf of Mexico, where we own 3 platforms. Total repair and workover expenses for the first nine months of 2001 was $7.6 million, compared to $5.2 million during 2000. These projects include production equipment repairs and workover or cleanout of productive zones in well bores. Excluding these amounts, lease operating expenses per Mcfe were $1.01 and $0.73 for the first nine months of 2001 and 2000, respectively. Depletion, depreciation and amortization ("DD&A") increased 19%, or $3.9 million primarily due to a 42% increase in DD&A per unit of production, which was offset by a 16% decrease in total production. The higher cost per unit relates primarily to an increase in the cost per Mcfe of production from the East Breaks 109 and 110 Fields along with increased production from those Fields. Exploratory dry hole expense increased to $4.6 million primarily due to the unsuccessful #A-4 well drilled during the first quarter of 2001 in the East Breaks 109 and 110 Fields. Geological and geophysical expense decreased $0.4 million primarily due to 3-D Seismic purchases and land rentals incurred during 2000 that were not included in 2001 spending. During the second and third quarters of 2001, PANACO recognized impairments for both proved and unproved oil and natural gas properties. The unproved property impairment was based on our decision to not further develop potential reserves based on the significant capital required to develop the field and the low potential to be realized based on numerous evaluations made by PANACO and other partners in the field. Also, due to reductions in future reserve estimates by our third party engineers, and the resulting lower future net cash flows from certain fields, we were required to impair non-core proved properties. Interest expense decreased $2.0 million due to lower weighted average borrowing levels during 2001 in addition to lower interest rate for our Credit Facility, which is based on the prime rate. Other income increased $0.8 million and is made up of the adoption of SFAS No. 133, including a gain on the ineffective portion of a natural gas swap and the mark-to-market of an option to put oil to a purchaser. 17 Income Tax Expense (Benefit) As oil and natural gas prices increased during 2000, we were able to project future taxable income sufficient to utilize our net operating loss carry-forwards. As such, during the second quarter of 2000 we recorded an income tax benefit of $29 million by reversing a valuation allowance recorded against these assets. From that point forward until the second quarter of 2001, income tax expense has been recognized, at the effective rate, as a percentage of pre-tax income. The analysis of the deferred tax asset utilization made during the second quarter of 2000 determined that it was more likely than not that the deferred tax assets would be realized. This determination was based on several factors, including current projections of future taxable income. This analysis also included current estimates for future oil and natural gas prices in addition to recent reserve additions. Projections of future taxable income were sufficient to utilize all of the deferred tax assets due to higher commodity prices and reserve additions, therefore the valuation allowance was removed. With the decrease in oil and natural gas prices and reserve estimates since the second quarter of 2000, management's estimates of future taxable income had decreased to a point in which it was more likely than not that none of its deferred tax asset would be utilized. Based on this analysis and all other evidence available at the time, the valuation allowance was reestablished against the deferred tax asset. These projections of future taxable income are management's best estimates, using current reserve estimates, estimates of future commodity prices and other information currently available. While we believe that the assumptions used in these projections are reasonable, future events, including changes in commodity prices, could result in a reduction in some or all of the deferred tax asset valuation allowance in future periods. PANACO also evaluates tax planning strategies and utilizes them when available in order to utilize our deferred tax assets and minimize income taxes. During 2001 this evaluation included the potential sales of assets which would have resulted in significant gains which would have been offset by the deferred tax asset. While there is no sale imminent, we are continually evaluating our options. Net Income (Loss) Although total revenues increased 7%, to $67.0 million, a property impairment of $6.9 million, an increase in exploratory dry hole expense of $3.8 million and the increase in the deferred tax valuation allowance of $22.9 million during 2001 along with an income tax net benefit of $26.3 million recognized during 2000, were the primary factors in a decrease of $59.1 million in net income and a $2.43 per share decrease in net income per share. 18 Results of Operations For the three months ended September 30, 2001 and 2000: Revenues Oil and natural gas sales totaled $16.7 million during the third quarter of 2001, a decrease of $8.2 million, or 33%, when compared to the third quarter of 2000. Production and Prices:

Both oil and natural gas production decreased when comparing the third quarter of 2001 to the comparable period of 2000. The most significant decreases in natural gas production were in the Umbrella Point Field (630 MMcf), the Price Lake Field (320 MMcf) East Breaks 160 and 161 Fields (316 MMcf ) and the East Breaks 165 Field (252 MMcf) were due primarily to natural declines in the respective production from those fields. Those declines were somewhat offset by increases in the East Breaks 109 and 110 Fields (849 MMcf) and the West Delta Fields (179 MMcf), both a primary focus of our current capital expenditure program. Likewise, oil production has decreased from the East Breaks 165 Field (31 Mbbl) and East Breaks 160 and 161 Fields (14 Mbbl) due to lower capital expenditures in those fields and the rapid production declines from the wells in those fields, which are inherent in the areas that we operate. Cost and Expenses Lease operating expenses increased $1.2 million, to $7.5 million, during the third quarter of 2001 compared to $6.3 million in 2000. The West Delta Block 52 Field, which was purchased in April 2001, added $0.8 million of additional lease operating expenses, when compared to the third quarter of 2000. On an Mcfe basis, lease operating expenses also increased to $1.85 in 2001, from $1.19 in 2000. Depletion, depreciation and amortization ("DD&A") increased 13%, or $1.0 million primarily due to a 48% increase in DD&A per unit of production and was offset by a 23% decrease in total production. The higher cost per unit relates primarily due to an increase in the cost per Mcfe of production from the East Breaks 109 and 110 Fields along with increased production from those Fields. 19 As part of our regular review of proved property carrying values and estimated recoverability of those values, during the third quarter of 2001, PANACO recognized an impairment of two proved oil and natural gas properties. The impairments were due primarily to reductions in estimated prices for oil and natural gas production. Interest expense decreased $0.6 million due to lower weighted average borrowing levels during 2001 in addition to lower interest rate for our Credit Facility, which is based on the prime rate. Other income increased $0.1 million and is made up of the impact of SFAS No. 133, including a gain on the ineffective portion of a natural gas swap and the mark-to-market of an option to put oil to a purchaser. Income Tax Expense (Benefit) As oil and natural gas prices increased during 2000, we were able to project future net income sufficient to utilize our net operating loss carry-forwards. As such, during the second quarter of 2000 we recorded an income tax benefit of $29 million by reversing a valuation allowance recorded against these assets. From that point forward until the second quarter of 2001, income tax expense has been recognized, at the effective rate, as a percentage of pre-tax income. The analysis of the deferred tax asset utilization made during the second quarter of 2000 determined that it was more likely than not that the deferred tax assets would be realized. This determination was based on several factors, including current projections of future taxable income. This analysis also included current estimates for future oil and natural gas prices in addition to recent reserve additions. Projections of future taxable income were sufficient to utilize all of the deferred tax assets due to higher commodity prices and reserve additions, therefore the valuation allowance was removed. With the decrease in oil and natural gas prices and reserve estimates since the second quarter of 2000, management's estimates of future taxable income had decreased to a point in which it was more likely than not that none of its deferred tax asset would be utilized. Based on this analysis and all other evidence available at the time, the valuation allowance was reestablished against the deferred tax asset. These projections of future taxable income are management's best estimates, using current reserve estimates, estimates of future commodity prices and other information currently available. While we believe that the assumptions used in these projections are reasonable, future events, including changes in commodity prices, could result in a reduction in some or all of the deferred tax asset valuation allowance in future periods. During 2001 this evaluation included the potential sales of assets which would have resulted in significant gains which would have been offset by the deferred tax asset. While there is no sale imminent, we are continually evaluating our options. Net Income (Loss) A decrease in total revenues of $8.2 million, in addition to an increase in income tax expense of $20.7 million, were the primary factors in a $29.1 million decrease in net income and $1.20 decrease in net income per share from the third quarter of 2000 to the third quarter of 2001. Outlook As a relatively small, leveraged oil and natural gas exploration and production company, the success and outcome of our business are highly dependent on oil and natural gas prices. Not only are our revenues, cash flows, results of operations and liquidity impacted by commodity prices, our ability to obtain financing for our business is also influenced by these prices. The nature of our 20 business is capital intensive, typically requiring an investment up front and a resulting return on that investment. The resulting return and success of that investment will vary depending on the prices we receive for the oil and natural gas. Also, due to the geographic area that we operate in, the levels of capital spending are significant and the lives of the reserves that we own are relatively short. Historically, our reserves have a five to seven year life, which tends to amplify oil and natural gas price fluctuations on our Company. For fiscal 2001, the Board of Directors has approved a $45 million capital budget. This budget includes approximately $21.5 million of exploratory projects, the majority of which has been spent at the East Breaks 109 and 110 Fields. While this level of exploratory spending is higher than in previous years, based on current seismic and drilling technology, we feel that these projects are also lower risk than the exploratory projects we have historically participated in. Other Contingencies An action was filed against the Company in Louisiana, along with Exxon Pipeline Company ("Exxon"), National Energy Group, Inc. ("NEG"), Mendoza Marine, Inc., Shell Western Exploration & Production, Inc. ("Shell"), and the Louisiana Department of Transportation and Development. The petition was filed in August 1998, and alleges that, in 1997 and perhaps earlier, leaks from a buried crude oil pipeline contaminated the plaintiffs' property. Pursuant to the purchase and sale agreement between PANACO and NEG, NEG is required to indemnify us from any damages attributable to NEG's operations on the property after the sale. Pursuant to another purchase and sale agreement, we may owe indemnity to Shell and Exxon, from whom we acquired the property prior to selling same to NEG. We believe that we have insurance coverage for the claims asserted in the petition, and have notified all insurance carriers that might provide coverage under our policies. In 1999 NEG filed for chapter 11 bankruptcy and emerged in late 2000. Some discovery has occurred in the case, but discovery is not yet complete. Therefore, at this point it is not possible to evaluate the likelihood of an unfavorable outcome, or to estimate the amount or range of potential loss. PART I Item 3a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Commodity price hedges We follow a hedging strategy designed to protect against the possibility of severe price declines due to market volatility. We may also make hedging decisions to assure a payout of a specific acquisition or development project. For 2001, we have hedged 18,000 MMBtu per day of natural gas for the entire year. The hedge is a swap, based on the NYMEX closing prices when the swap was put in place in November 2000. The swap prices range from a high of $6.415 per MMBtu in January to a low of $4.485 per MMBtu in October and average $4.914 per MMBtu for the year. The average price of this swap for July 1 through December 31, 2001 is $4.54 per MMBtu. The corresponding settlement prices are based on the last three trading days on the NYMEX for the month to which the swap prices relate. If the swap prices are higher than the settlement prices, the counterparty will pay us the price difference for the total MMBtu hedged for that month. If the swap prices are less than the settlement prices, we will pay the counterparty the price difference for the total MMBtu hedged for that month. 21 We have also purchased an option to put oil to a purchaser at an agreed upon price. The put option is for 1,000 barrels of oil per day from January 1 through September 30 at a NYMEX price of $25.00 per barrel. The cost of the put option was $1.00 per barrel, or $365,000. At September 30, 2001 the fair value of these hedges was a gain of $3.9 million, pre-tax. The fair value of our commodity hedging instruments is the estimated amount that we would receive or pay to settle the applicable commodity hedging instrument at the reporting date, taking into account the difference between NYMEX prices or index prices at year-end and the contract price of the commodity hedging instrument. PART II OTHER INFORMATION Item 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits None. (b) Reports on Form 8-K None. SIGNATURES Pursuant to the requirements 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. PANACO, Inc. Date: November 13, 2001 /s/ Todd R. Bart ------------------------ ------------------------------------- Todd R. Bart, Chief Financial Officer

PANACO INC 10-Q