Item 1. Business.
With the exception of historical information, the matters discussed in this Form 10-K contain forward-looking statements. The forward-looking statements we make, not only in this Form 10-K, 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. For information concerning some of the most significant risks which may affect PANACO's operations, see "Risk Factors." 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.
Unless otherwise specified, all references we make to "PANACO" or the "Company" include PANACO, Inc. and the predecessor company, PAN Petroleum, MLP and two former subsidiaries, Goldking Acquisition Corp. and PANACO Production Company. On December 31, 1999 we merged these into PANACO, Inc. and our references to PANACO may include these former subsidiaries. Capitalized terms in this Form 10-K are defined in a glossary, which begins on Page 39. Our corporate headquarters are located at 1100 Louisiana Street, Suite 5100, Houston, Texas 77002. Our telephone number is (713) 970-3100 and our fax number is (713) 970-3151. You can also visit our website, which can be found at www.panaco.com.
The predecessor of PANACO was formed in 1984 as a consolidator of oil and gas partnerships. From 1984 through 1988 a total of 114 partnerships were acquired and merged into our predecessor, which became PAN Petroleum, MLP in 1987. In 1991, we formed PANACO, Inc. as a Delaware Corporation and acquired PAN Petroleum, MLP in 1992. At that time, we began focusing our resources on the Gulf of Mexico and the states surrounding the Gulf, which we collectively refer to as the Gulf Coast Region. We are in the business of selling oil and natural gas, produced on properties we lease, to third party purchasers. We obtain reserves of crude oil and natural gas by either buying them from others or drilling developmental and exploratory wells on acquired properties. We acquired our first property in the Gulf of Mexico in 1991, and have acquired other properties in the Gulf Coast Region and Gulf of Mexico in every year, except for 1999, from 1994 through 2000. We have grown not only through acquisitions in each of those years but also by further developing the properties we have acquired. We have acquired properties from companies such as Conoco, Texaco, Arco, Oxy and BP Exploration & Oil, Inc. (now BP Amoco). We also acquired the common stock and the oil and gas properties of the Goldking Companies in 1997.
Business Strategy
Our strategy is to systematically grow reserves, production, cash flow and earnings through a program focused on the Gulf Coast Region. Some of the ways we do this are: (i) strategic acquisitions and mergers, (ii) exploiting and developing acquired properties, (iii) marketing of existing infrastructure and (iv) a selective exploration program. As a result of property acquisitions which are described below, we have an inventory of development and exploration projects that provide additional reserve potential. The key elements of our objectives are outlined as follows.
Strategic Acquisitions and Mergers
In implementing our strategy, we focus our acquisition efforts on Gulf Coast Region properties that have an inventory of development and exploitation projects, operating control, infrastructure value and opportunities for cost reduction. The properties we seek to acquire are generally geologically complex with multiple reservoirs, have an established production history and are candidates for exploitation and further exploration. Geologically complex fields with multiple reservoirs are fields in which there are multiple reservoirs at different depths and wells, which penetrate more than one reservoir and have the potential for recompletion in more than one reservoir. In pursuing this strategy, we identify properties that may be acquired, preferably through negotiated transactions or, where appropriate, sealed bid transactions. Once we acquire these properties we focus on reducing operating costs and implementing production enhancements through the application of technologically advanced production and recompletion techniques.
In the future, we may acquire more oil and natural gas assets or ownership in other assets that we believe will provide value to our investors. In doing so, there are inherent risks associated with the oil and natural gas industry. The success of our acquisitions will depend on our ability to estimate the quantity of oil and natural gas reserves using all of the data available to us at the time. The success of these acquisitions will also depend on how the actual results of the properties compare to the results that we projected when the acquisition was evaluated.
While we tend to focus on acquisitions of properties from large integrated oil companies, we evaluate a broad range of acquisition and merger opportunities. PANACO is comprised of a staff with technical experience in evaluating, identifying, exploiting and exploration on Gulf Coast Region properties. Also, we believe that we are regarded in the industry as a competent buyer with the proven ability to close transactions in a timely manner. Below are highlights of some of our more significant acquisitions.
Price Lake Field
We acquired the Price Lake Field in April 1998 for $750,000 as a potential development field in addition to its exploration prospects, that had been identified using new 3-D Seismic data. The Field had previously produced 26.7 Bcf of natural gas and 913,000 barrels of oil from shallower reservoirs. As operator, we evaluated the 3-D Seismic data, identified potential drilling locations and brought partners into the prospect.
We spud the first well in January 1999 and reached a depth of 16,467 in May 1999. This well, the Sturlese Estate #1, was successful in the exploratory zones of the prospect and encountered 144' of producing formation in the MA-22 and MA-24 sands. The Sturlese Estate #1 began production in September 1999 once production facilities were completed. We drilled and completed a second exploratory well in the Price Lake Field, the Sturlese Estate #3, in March 2000. The Sturlese Estate #3 also encountered producing formation in the MA-24 sand in addition to the MA-23 sand. We own 51.2% of both of these wells and are the operator of the Field. We are currently reviewing seismic and other data for other potential wells to be drilled. We currently have a new well in the Price Lake Field in our 2001 budget.
BP Acquisition
In May 1998 we acquired 100% of East Breaks Blocks 165 and 209 and 75% of High Island Block 587 from BP Exploration and Oil, Inc., now BP Amoco ("BP"). We entered into a purchase and sale agreement with BP on May 14 and closed the acquisition on May 26. We paid $19.6 million in cash and accounted for the
acquisition as a purchase. In addition to the leases acquired, we also received 3-D Seismic data, which covers 20 offshore blocks. We became the operator effective June 1, 1998.
The central production platform for all three blocks is located in East Breaks 165. This platform is nicknamed "Snapper" and is located in 863 feet of water. Also included in the acquisition was 31.72 miles of 12" oil pipeline, with capacity of over 20,000 barrels of oil per day. This oil pipeline ties our production platform to the High Island Pipeline System, which is the major oil transportation system in that area. We also acquired a 9.3 mile, 12 3/4" gas pipeline, which connects to the High Island Offshore System, the major gas transportation system in the area. We currently receive payments from other lease operators in the area for their use of our platform and processing facilities, which reduces our operating expenses in this Field. We have completed some development on the Field since it was acquired, and continue to evaluate the 3-D Seismic data for further development.
Goldking Acquisition
On July 31, 1997, we acquired the Goldking Companies, Inc. ("Goldking") by purchasing all of the common stock of its parent Company, a privately held oil and natural gas company. The Goldking acquisition included not only oil and gas reserves, but also a portfolio of exploration prospects, an extensive development program and a technical staff experienced in Gulf Coast oil and natural gas operations. Goldking was held as a subsidiary of PANACO, Inc., which was named PANACO Production Company. On December 31, 1999 we merged the subsidiary into PANACO, Inc. Since 1997, we have developed several of the properties acquired from Goldking, the largest of which was the Umbrella Point Field. We drilled and completed two wells in the Field, the State Lease #74-10 well and the State Tract #87-12 well. The first was the State Lease #74-10 well, which was completed in February 1998 and produced as much as 27 MMcf of natural gas and 260 barrels of condensate per day. We completed a workover on this well in December 1999 and increased production back to over 19 MMcf of natural gas and 176 barrels of condensate per day. The second development well, the State Tract #87-12 well was completed in January 2000 and has produced as high as 6 MMcf per day of natural gas. We own an 80% working interest in these two wells and a 100% working interest in the rest of the Field. Current production from the Umbrella Point Field is 6,500 Mcf and 320 barrels of oil per day.
Amoco Acquisition
In October 1996 we acquired interests in six offshore fields from Amoco Production Company, now BP Amoco ("BP"). We paid BP $32 million in cash and issued them 2 million shares of common stock in consideration for the properties. All of the properties we acquired from BP are operated by third parties, which are Unocal, Texaco, Coastal Oil and Gas and Newfield Exploration.
Zapata Acquisition
In July 1995, we acquired all of Zapata Corp.'s remaining offshore properties. The net purchase price was $2.8 million in cash and was effective October 1, 1994. The purchase price also included a production payment to Zapata and a platform revenue sharing agreement, both of which related to the East Breaks 109 Field. In January 2000, we acquired the production payment and revenue sharing agreement for $1.4 million in cash and a 1% overriding royalty on East Breaks 109 and 110.
In late 1998 we acquired new 3-D Seismic covering several blocks in the East Breaks area, including blocks 109 and 110. Based on a review of this new seismic data, we identified several developmental and exploratory drilling locations on blocks 109 and 110. During 2000 we drilled three new exploratory wells on Block 110, two of which were completed and continue to produce, the A-11 and A-12 wells. The initial production from the A-11 well was 6.1 MMcf of natural gas and 73 barrels of condensate per day and began producing in mid October. The A-12 well began producing in early December at a rate of 3.0 MMcf of natural gas and 10 barrels of condensate per day. The third well reached the
targeted zone in late December and appeared to contain hydrocarbons. However, upon preparation and completion the well was determined to be unproductive and was abandoned.
In January 2001 the fourth exploratory well was drilled and completed. The A-7 well began producing at 5.8 MMcf of natural gas per day. We have five additional projects scheduled for 2001 in East Breaks 109 and 110, which account for over one-half of our capital budget for the year. We own a 100% working interest in both blocks and we are the operator. Current production from the entire Field is 11,000 Mcf and 70 barrels of condensate per day. Production before the drilling program began was 2,000 Mcf and 10 barrels of condensate per day.
Exploitation and Development of Acquired Properties
Primarily through these acquisitions, we have developed an inventory of exploitation projects including development drilling, workovers, sidetrack drilling, recompletions and artificial lift enhancements. As of December 31, 2000, 33% of our total Pretax PV-10 relates to Proved Undeveloped Reserves. We use advanced technologies where appropriate in development activities to convert Proved Behind Pipe and Proved Undeveloped Reserves to Proved Developed Producing Reserves. These technologies include horizontal drilling and through tubing completion techniques, new lower cost coiled tubing workover procedures and reprocessed 2-D and 3-D Seismic interpretation. A majority of the identified capital projects can be completed utilizing our existing platform and pipeline infrastructure, which improve project economics.
Marketing of Existing Infrastructure
A key element of each acquisition we have made has been production infrastructure. While we focus primarily on oil and natural gas reserves, we view platforms, pipelines and related facilities as an often-overlooked source of additional revenues. We own interests in 20 offshore platforms and 109 miles of offshore oil and natural gas pipelines with diameters of 10" or greater. We market the use of this infrastructure to other lease operators as a source of additional revenue to us and as a way for other lease operators to produce their hydrocarbons in a more economical fashion. We currently have facility use or processing agreements in the West Delta Fields, the Umbrella Point Field, the East Cameron 359 Field, the East Breaks 109 Fields, the East Breaks 160 Fields and the East Breaks 165 Fields. Our major focus of marketing these facilities has been in the East Breaks area. We own 100% of the platforms and related pipelines in the East Breaks 109 and East Breaks 165 Fields and 33% of the platforms and pipelines in the East Breaks 160 Fields. These existing platforms are three of the furthest from the coastline in the Gulf of Mexico and are in 700' to 900' of water and replacement costs for these facilities are in excess of $100 million. These existing platforms can significantly improve the economics of operating an adjacent oil and gas lease and in return lower our costs of operating this infrastructure.
Selective Exploration Program
During 1996 we began to increase our exposure to exploration projects by allocating more resources to and reviewing more of these projects. This process continued with the Goldking acquisition in 1997. Goldking increased our inventory of exploratory projects and the technical staff of PANACO. Historically we have allocated 10% to 20% of our capital budget on exploratory projects. We believe a balanced capital budget includes the higher reward and higher risk exploratory projects along with the lower risk developmental projects.
The increased technical staff has helped us by increasing exposure to third-party projects and, more importantly, by generating more projects on the properties we already own. New 3-D Seismic data and our technical staff have generated several exploration prospects, most recently the successful East Breaks 109 and 110 wells. Our exploratory inventory is unique in that many of
the exploration prospects can be reached in conjunction with developmental wells, which reduces the risk by providing "bail outs" in lower risk developmental reserves.
Geographic Focus
Our reserve base is focused primarily in the Gulf Coast Region, which includes the Gulf of Mexico. The Gulf of Mexico has historically been the most prolific basin in North America and currently accounts for a large percentage of the natural gas produced in the United States and continues to be the most active region in terms of capital expenditures and new reserve additions. Because of upside potential, high production rates, technological advances and acquisition opportunities, we have focused our efforts in this region. We believe we have the technical expertise and infrastructure in place to take advantage of the inherent benefits of the Gulf Coast Region. Also, as the integrated oil companies move to deeper water, we believe we will continue to be well positioned to use our expertise to acquire and exploit Gulf Coast Region properties.
Inventory of Exploitation and Development Projects
We have identified development drilling locations and recompletion and workover opportunities. We believe that the majority of these opportunities have a moderate risk profile and could add incremental reserves and production. In addition to these identified opportunities, with the use of 3-D Seismic technology, additional opportunities continue to be found in the known reservoirs as well as deeper undrilled horizons. For example, new 3-D Seismic on the West Delta Fields, which were acquired in 1991, has identified further development potential and led to several new wells completed in 2000.
Significant Operating Control
We operate 82% of our properties as measured by Pretax PV-10 value. The operator of an oil and natural gas property supervises production, maintains production records, employs field personnel, and performs other functions required in the production and administration of such property. This level of operating control benefits us in numerous ways by enabling us to (i) control the timing and nature of capital expenditures, (ii) identify and implement cost control programs, (iii) respond quickly to operating problems and (iv) receive overhead reimbursements from other working interest owners. In addition to significant operating control, our geographic focus allows us to operate a large value asset base with relatively few employees, thereby decreasing overhead relative to other offshore lease operators.
Well Operations
We operate 50 productive offshore wells and own all of the working interests in a majority of those wells. Third party operators, including Unocal Corporation, Coastal Oil & Gas Corp., Newfield Exploration, Texaco, Anadarko Petroleum Corporation and Burlington, operate our 48 remaining productive offshore wells. We also operate 51 productive onshore wells in which we own a majority or all of the working interest. In addition, we own working interests in two productive onshore wells operated by others. Where properties are operated by others, operations are conducted pursuant to joint operating agreements that were in effect at the time we acquired our interest in these properties. We consider these joint operating agreements to be on terms customary within the industry. The compensation paid to the operator for such services customarily varies from property to property, depending on the nature, depth, and location of the property being operated.
Acquisition, Development, and Other Activities
We utilize our capital budget for (a) the acquisition of interests in other producing properties, (b) recompletions of our existing wells, and (c) the drilling of development and exploratory wells.
In recent years, major oil companies have been selling properties to independent oil companies because they feel these properties do not have the remaining reserve potential needed by a major oil company. Several independent oil companies have acquired these properties and achieved significant success in further exploitation. Even though a property does not meet the criteria for further development by a major oil company that does not mean it is lacking further exploitation potential. The majors are simply moving further offshore into deeper water and to other countries where they can find and produce the larger fields that fit their criteria. Present day technology permits drilling and completing wells in water in excess of 10,000 feet.
We believe that our primary activities will continue to be concentrated offshore in the Gulf of Mexico and onshore in the Gulf Coast region. The number and type of wells we drill will vary from period to period depending upon the amount of the capital budget available for drilling, the cost of each well, our commitment to participate in the wells drilled on properties operated by third parties, the size of the fractional working interest acquired and the estimated recoverable reserves attributable to each well. Drilling on and production from offshore properties often involves higher costs than does drilling on and production from onshore properties, but the production achieved on successful wells is generally greater.
Use of 3-D Seismic Technology
The use of 3-D Seismic and computer-aided exploration ("CAEX") technology is an integral component of our acquisition, exploitation, drilling and business strategy. In general, 3-D Seismic is the process of obtaining continuous seismic data within a large geographic area, rather than as individual, widely spaced lines. 3-D Seismic differs from 2-D Seismic in that it provides information as a seamless volume, or "cube" of data instead of information along a single vertical line or numerous separate vertical lines across the geological formations of interest.
By integrating well log and production data from existing wells with the structural and stratigraphic details of a continuous 3-D Seismic volume, our Geosciences team obtains a greater understanding and clearer image of the formations of interest. While it is impossible to predict with certainty the exact structural configuration or lithological composition of any underground geological formation, 3-D Seismic provides a mechanism by which more accurate and detailed images of complex geological formations can be obtained prior to drilling for hydrocarbons therein. In particular, 3-D Seismic delineates smaller reservoirs with greater precision than can be obtained with 2-D Seismic. We own our own seismic interpretation workstations and data processing equipment and utilize the services of outside firms to process and interpret seismic data.
Marketing of Production
We sell the Production from our properties in accordance with industry practices, which include the sale of oil and natural gas at the wellhead to third parties. We sell both at prices based on factors normally considered in the industry, such as index price for natural gas or the posted price for oil, price premiums or bonuses with adjustments for transportation and the quality of the oil and natural gas.
We market all of our offshore oil production to Plains Resources, Amoco, Oxy, Conoco, Texaco, Unocal and BP. BP has a call on all of the oil production from our properties acquired from BP at their posted prices. If we have a bona fide offer from a crude oil purchaser at a higher price than BP's posted price, then BP must match that price or release the call. Oil from the Zapata Properties is currently being sold to Unocal and BP, but can be sold to any crude oil purchaser of our choice. Plains Resources purchases the oil production from the Umbrella Point Fields, the East Breaks 165 Fields, the Price Lake Field and on some of our smaller fields that produce oil. Plains Resources accounted for 23% of our total oil and natural gas revenues in 2000. Natural gas is generally sold on the spot market or under short-term contracts of one year or less. There are numerous potential purchasers for natural gas. Notwithstanding
this, natural gas purchased by Enron North America Corp. accounted for 39% of our total oil and natural gas revenues in 2000. There are numerous natural gas purchasers doing business in the areas that we operate in as well as natural gas brokers and clearinghouses. Furthermore, we can contract to sell the natural gas directly to end-users. We do not believe that we are dependent upon any one customer or group of customers for the purchase of natural gas.
Plugging and Abandonment
All of our reserve values include the estimated future liability to plug and abandon ("P&A") all of the wells, platforms and pipelines in accordance with guidelines established by regulatory authorities. These costs vary according to the location of the lease, depth of water, number of wells, etc. The total estimated future abandonment costs for all of our properties is over $20 million. The Minerals Management Service of the U.S. Department of the Interior ("MMS") requires operators of offshore platforms to provide evidence of the ability to satisfy these future obligations. The companies that we acquire properties from may also require evidence of our ability to satisfy these future obligations. Our preferred method of providing evidence to these parties is a combination of escrow accounts and surety bonds. Following is a description of the methods by which we have accomplished these objectives.
West Delta and East Breaks 109 and 110 Fields
In both the West Delta Fields and the East Breaks 109 and 110 Fields, we have established an escrow 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 $3.5 million at December 31, 2000 and requires quarterly deposits of $250,000 until the account balance reaches $6.3 million.
East Breaks 165 Fields
In the East Breaks 165 and 209 Fields we have 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 $4.4 million at December 31, 2000 and requires quarterly deposits of $250,000 until the account balance reaches $6.5 million.
BP Properties
We have also established an escrow account in favor of BP under which we 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 December 31, 2000.
We provide much smaller bonds on various locations for similar purposes, the amounts of which are not significant. All of these agreements provide for us to receive the escrow monies back upon satisfaction of our performance of these obligations.
Insurance
We maintain insurance coverage that is customary for companies our size and engaged in the same line of business. Our coverage includes general liability insurance in the amount of $100 million for personal injury and property damage. We carry cost of control and operators extra expense insurance of $5 million to $20 million, depending on the estimated cost to drill the well for wells onshore or in state waters, and up to $100 million for wells in federal offshore waters. The amounts are proportionately reduced if we own less than 100% of the well. We also maintain $147 million in property insurance on our offshore properties. We also carry business interruption insurance on our significant properties, which covers the estimated cash flows from each property after it has been non-producing for 21 days and reimburses us for those amounts for up to six months. Finally, our officers and directors are indemnified by PANACO and we
maintain insurance of $3 million, which is designed to reimburse us for legal fees incurred in defense costs. We believe that our insurance coverage is adequate and the underwriters of our insurance will be able to satisfy any claims made. However, we can not assure you that this insurance or that the underwriters will adequately cover all of the costs or that we will be able to continue to purchase insurance at reasonable prices. Even one significant event, if not adequately insured, could significantly impair our financial condition and results of operations.
Funding of Business Activities
Credit Facility
Our primary source of capital beyond discretionary cash flows is our Credit Facility. Our 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. We may also use the Credit Facility for working capital support, to provide letters of credit and general corporate purposes.
In September 1999 we put in place a new Credit Facility, with Foothill Capital Corp. as the Agent, along with Foothill Partners, L.P. and Ableco Finance, a subsidiary of Cerberus Capital Management, L.P. This Credit Facility is a $60 million line, with a term of two years to October 1, 2001, and extendable for two additional six month periods, at our sole option. We are reviewing alternatives to extending this agreement, including replacing this Credit Facility with a bank facility. Management believes that if we do not choose to renew the existing facility, that we would be able to replace it with one that provides acceptable terms.
Borrowings under this Facility bear interest at rates ranging from prime plus .5% up to prime plus 3.0% depending on the amounts borrowed. We had $19.4 million outstanding at December 31, 2000. We will continue to use this Facility in 2001 to fund part of our $37.1 million capital budget.
The Credit Facility is a revolving credit agreement subject to monthly borrowing base determinations. These determinations are made from 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.
Under the terms of this Credit Facility, we must maintain a ratio of trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0 through December 31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term of the Facility. We must also maintain a working capital ratio, as defined in the agreement, of not less than .25 to 1.0. Also, the Credit Facility contains certain limitations on mergers, additional indebtedness and pledging or selling assets. We were in compliance at December 31, 2000 with the covenants contained in the Credit Facility.
Senior Notes
In October 1997 we issued $100 million of Senior Notes, which bear interest at 10 5/8% and are due October 1, 2004. These Senior Notes are general unsecured obligations and rank pari passu with any unsubordinated indebtedness and rank senior to any subordinated indebtedness. In effect, the Senior Notes are subordinated to all secured indebtedness, such as the Credit Facility, but only up to the value of the assets that are secured.
We can redeem all or part of the Senior Notes, at our option, after October 1, 2001, at certain prices, which are specified in the indenture plus accrued interest to date. We can also redeem up to 35% of the Senior Notes any time after October 1, 2000 at a price of 110.625% of the principal, plus accrued interest to date, with the proceeds of an equity offering.
If a Change in Control occurs, as it is defined in the Indenture, the holders of the Senior Notes can require PANACO to repurchase those notes at 101% of the principal amounts plus accrued interest to date. We must maintain a total Adjusted Consolidated Net Tangible Asset Value, as defined in the Indenture, ("ACNTA") equal to 125% of our indebtedness at the end of each quarter. If our ACNTA falls below this percentage of indebtedness for two succeeding quarters, we must redeem an amount of the Senior Notes sufficient to maintain this ratio.
In August of 2000, we were informed that High River Limited Partnership, a Delaware limited partnership ("High River"), had purchased a sufficient number of additional shares of common stock to be a Change of Control under the Indenture, thus requiring the Company to make a Change of Control Offer for Senior Notes. High River is an affiliate of Carl C. Icahn, whose aggregate ownership of Company common stock with his affiliates after the acquisition was 6,545,400 shares or 26.9% of the outstanding common stock. Pursuant to an agreement with the Company, in October of 2000 High River purchased all the Senior Notes tendered, increasing High River's ownership in the Notes to approximately 99% of the $100 million principal amount of Senior Notes outstanding.
The Indenture contains certain restrictive covenants that limit us to, among other things, incurring additional indebtedness, paying dividends or making certain other restricted payments, consummating certain asset sales, entering into certain transactions with affiliates and incurring liens. The Indenture also restricts us from merging or consolidating with any other person or selling, assigning, transferring, leasing, conveying or otherwise disposing of all or substantially all of our assets. In addition, under certain circumstances, we will be required to offer to purchase the Senior Notes, in whole or in part, at a purchase price equal to 100% of the principal amount thereof plus accrued interest to the date of repurchase, with the proceeds of certain Asset Sales. We were in compliance at December 31, 2000 with the covenants contained in the Indenture.
Common and Preferred Stock
On December 31, 2000 we had issued and outstanding 24,323,521 shares of $.01 par value common stock. You will find a more detailed description of our common stock and the rights of ownership in Part II, Item 5 of this Form 10-K. We are authorized to issue 100 million shares of common stock for a variety of purposes with board of director approval. In the past, we have issued new common stock for property acquisitions, raising additional capital and for compensation to our directors and employees. We have an Employee Stock Ownership Plan ("ESOP") that we contribute shares to for the account of employees. The ESOP plan was established in 1994 and is funded annually at the discretion of the board of directors.
We are authorized to issue up to 5 million shares of preferred stock the details of which you can also find in Part II, Item 5 of this Form 10-K. We have not issued any shares of preferred stock.
Competition, Markets, Seasonality and Environmental and Other Regulation
COMPETITION. There are a large number of companies and individuals engaged in the exploration for and development of oil and natural gas properties. Competition is particularly intense with respect to the acquisition of oil and natural gas producing properties and securing experienced personnel. We encounter competition from various independent oil companies in raising capital and in acquiring producing properties. Many of our competitors have financial resources and staffs considerably larger than ours.
MARKETS. Our ability to produce and market oil and natural gas profitably is dependent upon numerous factors beyond our control. The effect of these factors cannot be accurately predicted or anticipated. These factors include the availability of other domestic and foreign production, the marketing of
competitive fuels, the proximity and capacity of pipelines, fluctuations in supply and demand, the availability of a ready market, the effect of federal and state regulation of production, refining, transportation, and sales of oil and natural gas, political instability or armed conflict in oil-producing regions, and general national and worldwide economic conditions.
Certain members of the Organization of Petroleum Exporting Countries ("OPEC") have, at various times, dramatically increased their production of oil, causing a significant decline in the price of oil in the world market. We cannot predict future levels of production by the OPEC nations, the prospects for war or peace in the Middle East, or the degree to which oil and natural gas prices will be affected, and it is possible that prices for any oil, natural gas liquids, or natural gas that we produce will be lower than those currently available.
The demand for natural gas in the United States has fluctuated in recent years due to economic factors, a deliverability surplus, conservation and other factors. This lack of demand has resulted in increased competitive pressure on producers. However, environmental legislation is requiring certain markets to shift consumption from fuel oils to natural gas, thereby increasing demand for this cleaner burning fuel.
In view of the many uncertainties affecting the supply and demand for oil, natural gas, and refined petroleum products, we are unable to predict future oil and natural gas prices. In order to minimize these uncertainties we have from time to time hedged prices on a portion of our production.
SEASONALITY. Historically the nature of the demand for natural gas caused prices and demand to vary on a seasonal basis. Prices and production volumes were generally higher during the first and fourth quarters of each calendar year. The substantial amount of natural gas storage becoming available in the U.S. is altering this seasonality. We sell our natural gas on the spot market based upon published index prices. Historically the net price received for our natural gas has averaged about $.10 per MMbtu below the NYMEX Henry Hub index price, due to transportation differentials. Fields that are located further offshore, such as the BP Properties, will generally sell their natural gas for as much as $.12 below the index price.
ENVIRONMENTAL AND OTHER REGULATION. Governmental laws and regulations, including price control, energy, environmental, conservation, tax and other laws and regulations relating to the petroleum industry, affect our business. For example, state and federal agencies have issued rules and regulations that require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil reserves, and regulate environmental and safety matters. These rules and regulations include restrictions on the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limits or prohibitions on drilling activities on certain lands lying within wetlands and other protected areas, and remedial measures to prevent pollution from current and former operations. Changes in any of these laws, rules and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current law and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on future operations.
We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence of such laws and regulations has no more restrictive effect on our method of operations than on other similar companies in the industry. The following discussion contains summaries only of certain laws and regulations.
Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the federal government for operations of federal leases. The Federal Energy Regulatory Commission (the
"FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA").
Sales of crude oil, condensate and natural gas liquids by us are not regulated and are made at market prices. The price we receive from the sale of these products is affected by the cost of transporting the products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which would generally index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting crude oil, liquids and condensates by pipeline. These regulations are subject to pending petitions for judicial review. We are not able to predict with certainty the effect, if any, these regulations will have on our business.
Additional proposals and proceedings that might affect the oil and natural gas industry are pending before Congress, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry historically has been very heavily regulated. There is no assurance that the current regulatory approach pursued by the FERC will continue indefinitely into the future. Notwithstanding the foregoing, it is not anticipated that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position.
Extensive federal, state and local laws and regulations govern oil and natural gas operations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which change frequently, are often difficult and costly to comply with and which carry substantial civil and/or criminal penalties for failure to comply. Some laws, rules and regulations to which we are subject, relating to protection of the environment, may in certain circumstances, impose "strict liability" for environmental contamination, rendering a person liable for environmental damages and response costs without regard to negligence or fault on the part of such person. For example, the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, also known as the "Superfund" law, imposes strict, joint and several liability on an owner and operator of a facility or site where a release of hazardous substances into the environment has occurred and on companies that disposed or arranged for the disposal of the hazardous substances released at the facility or site. Similarly, the Oil Pollution Act of 1990 ("OPA") imposes strict liability for remediation and natural resource damages in the event of an oil spill. In addition to other requirements, the OPA requires operators of oil and natural gas leases on or near navigable waterways to provide $35 million in "financial responsibility" as defined in the Act. At present we are satisfying the financial responsibility requirement with insurance coverage. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations and costs. Furthermore, we cannot guarantee that such laws as they apply to oil and natural gas operations will not change in the future in such a manner as to impose substantial costs on us. While compliance with environmental requirements generally could have a material adverse effect on our capital expenditures, earnings or competitive position; we believe that other independent energy companies in the oil and natural gas industry likely would be similarly affected. We also believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.
Offshore operations are conducted on both federal and state lease blocks of the Gulf of Mexico. In all offshore areas the more stringent regulation of the federal system, as implemented by the Minerals Management Service of the Department of the Interior, will ultimately be applicable to state as well as federal leases, which could impose additional compliance costs on the Company. While there can be no guarantee, we do not expect these costs to be material. See "Risk Factors - Environmental and Other Regulations."
Employees
We have 37 full time employees, five of whom are officers. Additionally, we utilize approximately 40 contract personnel in the operation of our properties, and use numerous outside geologists, production engineers, reservoir engineers, geophysicists and other professionals on a consulting basis.
Risk Factors
The Company's business and the results of operations are affected by numerous factors and uncertainties, many of which are beyond our control. Following is a description of some of the factors that could cause actual results of operations in the future to differ materially from those currently experienced or expected.
Finding and Acquiring Additional Reserves; Depletion
Our future success and growth depends upon the ability to find or acquire additional oil and natural gas reserves that are economically recoverable. Except to the extent that we conduct successful exploration or development activities or acquire properties containing Proved Reserves, our Proved Reserves will generally decline as they are produced. The decline rate varies depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore, cash flow and income are highly dependent upon the level of success in exploiting our current reserves and acquiring or finding additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain or expand this asset base of oil and natural gas reserves could be impaired. There can be no assurance that our planned development projects and acquisition activities will result in additional reserves or that we will have success drilling productive wells at economic returns sufficient to replace our current and future production.
Substantial Leverage; Ability to Service Debt
We incurred significant losses in 1999 and 1998 and are significantly leveraged. Our long-term debt balance at December 31, 2000 was $121.7 million and our stockholders' equity was $12.4 million. A large part of our losses in prior years was due to depletion and impairment of property costs based primarily on low commodity prices. This level of indebtedness has several important effects on our operations, including (i) a substantial portion of our cash flow from operations is dedicated to interest on our long-term debt and is not available for other purposes, (ii) the covenants in our Credit Facility and our Senior Notes can be very restrictive as to how we conduct business, (iii) our ability to obtain additional financing may be restricted, (iv) the market price for our common stock may be lower than companies in our peer group. We cannot give you assurance that we will continue to find financing on acceptable terms, or at all. If sufficient capital is not available, we may not be able to continue to implement our business strategy.
The Credit Facility lenders have the ultimate decision, at their sole discretion, as to the amounts available to borrow under the line. If oil or natural gas prices decline significantly, the availability under this line could be severely reduced. The Credit Facility requires us to satisfy certain financial ratios in the future. The failure to satisfy these covenants or any of the other covenants in the Credit Facility would constitute an event of default thereunder and may permit the lenders to accelerate the indebtedness outstanding under the Credit Facility and demand immediate repayment. See "Credit Facility."
Volatility of Oil and Natural Gas Prices
Our revenues, profitability and the carrying value of oil and natural gas properties are substantially dependent upon prevailing prices of, and demand for, oil and natural gas and the costs of acquiring, finding, developing and producing reserves. Our ability to maintain or increase borrowing capacity, to repay the Senior Notes and outstanding indebtedness under any current or future credit facility, and to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and natural gas; (ii) market uncertainty; and (iii) a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions, the price and availability of domestic and imported oil and natural gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Our production is weighted toward natural gas, making earnings and cash flow more sensitive to natural gas price fluctuations. Historically, we have attempted to mitigate these risks by oil and natural gas hedging transactions. See "Business - - Marketing of Production."
Uncertainty of Estimates of Reserves and Future Net Cash Flows
The basis for the success and long-term continuation of our Company is the price that we receive for our oil and natural gas. These prices are the primary factors for all aspects of our business including reserve values, future net cash flows, borrowing availability and results of operations. The reserve valuations are prepared semi-annually by independent petroleum consultants, including the Pretax PV-10 values included in this Form 10-K. However, there are many uncertainties inherent in preparing these reports and the third party consultants rely on information we provide them. The Pretax PV-10 calculations assume constant oil and natural gas prices, operating expenses and capital expenditures over the lives of the reserves. They also assume certain timing for completion of projects and that we will have the financial ability to conduct operations and capital expenditures without regard to factors independent of the reserve report. The actual results we realize from these properties have historically varied from these reports and may do so in the future. The volumes estimated in these reports may also vary due to a variety of reasons including incorrect assumptions, unsuccessful drilling and the actual oil and natural gas prices that we receive.
You should not assume that the Pretax PV-10 values of our reserves that are included in this Form 10-K represent the market value for those reserves. These values are prepared in accordance with strict guidelines imposed by the SEC. These valuations are the estimated discounted future net cash flows from our Proved Reserves. These estimates use prices that we received or would have received on December 31, 2000 and use costs for operating and capital expenditures in effect at that same time. These assumptions are then used to calculate a future cash flow stream that is discounted at a rate of 10%.
The base prices used for the Pretax PV-10 calculation were public spot prices on December 31 adjusted by differentials to those spot market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. The average prices in the Pretax PV-10 value at December 31, 2000 were $9.65 per Mcf of natural gas and $26.60 per barrel of oil. Currently, we are selling our oil production for slightly higher than the prices at December 31, 2000 and our natural gas production for much less. Based on current market conditions, we are projecting that our 2001 average realized prices for oil and natural gas average approximately $26.96 and $5.62, respectively.
Acquisition Risks
As our business strategy is to grow primarily through acquisitions and subsequent development of those acquired properties, you should know that there are risks involved in acquiring oil and gas reserves. We perform extensive reviews of properties that we intend to acquire based on the information available to us. With a limited staff, we may use consultants to assist us in our review and we may rely on third party information available to us. Again, these are inherent uncertainties in the review process. Consistent with other companies in our peer group, we focus our review on the properties with the most significant values and spend less time on less significant properties. This could leave undetected a problem or issue that did not initially appear to be significant to us.
We have typically focused our acquisition efforts on larger assets being sold such as our BP Acquisitions. By doing so, we are at risk for unforeseen problems to become significant both operationally and financially. Variations of actual results from results we estimate in the review process could also be more significant to us.
Exploration and Development Risks
With the inventory of projects on our existing properties, we have done or plan to do more development, and to a lesser extent, exploration than we have since the inception of our Company. While we feel that this is the best approach to implement our business strategy, it also involves inherent risks. The costs of drilling all types of wells are uncertain, as are the quantity of reserves to be found, the prices that we will receive for the oil or natural gas and the costs to operate the well. While we have successfully drilled many wells, you should know that there are inherent risks in doing so, and those difficulties could materially affect our financial condition and results of operations. Also, just because we complete a well and begin producing oil or natural gas, we can not assure you that we will recover our investment or make a profit.
Operating Hazards and Uninsured Risks
Our oil and natural gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels we believe are reasonable, we are not fully insured against all risks. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.
Marketing Risks
Substantially all of our natural gas production is currently sold to gas marketing firms or end users either on the spot market on a month-to-month basis at prevailing spot market prices. For the year ended December 31, 2000, one natural gas purchaser accounted for approximately 39% of our oil and natural gas revenues. Also, in 1999 we consolidated a majority of our oil production to one oil purchaser, who accounted for 23% of our oil and natural gas revenues in 2000. We do not believe that discontinuation of a sales arrangement with either of these purchasers would be in any way disruptive to our marketing operations. During 1999 our largest oil purchaser and our largest natural gas purchaser accounted for 37% and 39%, respectively, of total oil and natural gas sales. During 1998 our largest natural gas producer accounted for 42% of total oil and natural gas sales.
Hedging Risks
Historically, we have attempted to reduce our exposure to the volatility of crude oil and natural gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the counterparty to the hedge the excess of the fixed price specified in the hedge over a floating price. If the floating price exceeds the fixed price, we are required to pay the counterparty all or a portion of this difference multiplied by the quantity hedged.
In the past, we have hedged up to 80% of oil and natural gas production on an annualized basis. Hedging may also prevent us from receiving the full advantage of increases in crude oil or natural gas prices above the fixed amount specified in the hedge. For the year 2001, our hedges are composed of options to put oil to a purchaser at a fixed price and swaps on natural gas. See Item 7a, "Qualitative and Quantitative Disclosure About Market Risks."
Abandonment Costs
Government regulations and lease terms require all oil and natural gas producers to plug and abandon platforms and production facilities at the end of the properties' lives. Our reserve valuations include the estimated costs of plugging the wells and abandoning the platforms and equipment on our properties. These costs are usually higher on offshore properties, as are most expenditures on offshore properties. As of December 31, 2000, our total estimated abandonment costs, net of $8.6 million already in escrow, were approximately $11.7 million. We account for those future liabilities by accruing for them in our depreciation, depletion and amortization expense over the lives of each property's total Proved Reserves.
Environmental and Other Regulations
Our operations are affected by extensive regulation through various federal, state and local laws and regulations relating to the exploration for and development, production, gathering and marketing of oil and natural gas. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds or other financial responsibility requirements, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas.
Our operations are also subject to numerous environmental laws, including but not limited to, those governing management of waste, protection of water, air quality, the discharge of materials into the environment, and preservation of natural resources. Non-compliance with environmental laws and the discharge of oil, natural gas, or other materials into the air, soil or water may give rise to liabilities to the government and third parties, including civil and criminal penalties, and may require us to incur costs to remedy the discharge. Oil and gas may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks, and sudden discharges from oil and gas wells or explosion at processing plants. Hydrocarbons tend to degrade slowly in soil and water, which makes remediation costly, and discharged hydrocarbons may migrate through soil and water supplies or adjoining property, giving rise to additional liabilities. Laws and regulations protecting the environment have become more stringent in recent years, and may in certain circumstances impose retroactive, strict, and joint and several liabilities rendering entities liable for environmental damage without regard to negligence or fault. In the past, we have agreed to indemnify sellers of producing properties against certain liabilities for environmental claims associated with those properties. We can not assure you that new laws or regulations, or modifications of or new interpretations of existing laws and regulations, will not substantially increase the cost of compliance or otherwise adversely affect our oil and natural gas operations and financial condition or that material
indemnity claims will not arise with respect to properties that we acquire. While we do not anticipate incurring material costs in connection with environmental compliance and remediation, we cannot guarantee that material costs will not be incurred.
Dependence Upon Key Personnel
Our success will depend almost entirely upon the ability of a small group of key executives and technical staff to manage our business. Should one or more of these employees leave or become unable to perform their duties, we cannot assure you that we will be able to attract competent new management.
Competition
There are many companies and individuals engaged in the exploration for and development of oil and natural gas properties. Competition is particularly intense with respect to the acquisition of oil and natural gas producing properties and securing experienced personnel. We encounter competition from various independent oil companies in raising capital and in acquiring producing properties. Many of our competitors have financial resources and staffs considerably larger than ours.
Item 2.
Item 2. Properties.
At December 31, 2000 our Proved Reserves totaled 131 Bcfe and had a Pretax PV-10 value of $532.9 million. Approximately 67% of these reserves are classified as Proved Developed Reserves and approximately 63% are natural gas. Our primary producing properties are located along the Gulf Coast in Texas and Louisiana and offshore in the federal and state waters of the Gulf of Mexico. We own interests in a total of 78 producing oil wells and 76 producing natural gas wells. We also own interests in 20 federal blocks in the Gulf of Mexico and 9 state water blocks and we operate 78% of the 98 producing offshore wells, based upon the Pretax PV-10 value as of December 31, 2000. Large independents and major oil companies, including Unocal, Newfield, Texaco, Coastal, Anadarko and Burlington, operate our non-operated offshore properties. Our 61 producing onshore wells account for 18% of our total Pretax PV-10 value as of December 31, 2000. We operate 97% of our onshore wells, based upon such Pretax PV-10 value. We also own interests in 20 offshore production platforms and 109 miles of offshore oil and natural gas pipelines with diameters of 10" or larger. In 2000, our properties yielded net production to PANACO of 1,070,000 Bbls of oil and condensate and 13,547,000 Mcf of natural gas.
While we review many acquisition opportunities each year, and have made several acquisitions under $5 million, we usually focus on larger acquisitions, relative to the size of our company. Gulf Coast Region, and more specifically, Gulf of Mexico property acquisitions tend to have larger reserves and larger purchase prices. We feel they usually also provide more exploitation and development potential. Since 1991, we have made six acquisitions of producing properties that had Proved Reserves of 159 Bcfe at the time of their respective acquisitions. We paid a total of $106.4 million for the Proved Reserve component of those acquisitions. By focusing on larger acquisitions, our reserve base is concentrated in a small number of properties.
The following is a summary of our significant properties as of December 31, 2000. These properties represent 82% of the aggregate Pretax PV-10 value of our Proved Reserves.
West Delta
PANACO acquired the West Delta Fields in May 1991 from Conoco, Atlantic Richfield Company (now BP), Oxy USA, Inc. and Texaco Exploration and Production Company. These Fields consist of 13,565 acres in Blocks 52 through 56 and Block 58 in the West Delta area offshore Louisiana. The Field was originally discovered in the mid 1950s and has continued to produce hydrocarbons since then. West Delta continues to have drilling and other activity in the area. These are currently approximately 40 total wells in the Field which produce from depths ranging from 1,200' to 17,000'. We operate the Field and generally own 100% of most wells. The production facility is a four-platform complex located in Block 54 in water that ranges in depth from six to fifteen feet. During 1996 we rebuilt a significant portion of the production facilities after damage caused by a third party. We spent a total of $8.5 million on rebuilding, and we received $3.9 in reimbursement under our insurance policies. The unreimbursed portion of the rebuilding related to upgrading the facilities to allow for increased production and more efficient operations. During 2000 we also settled a claim for $1 million with that third party's insurance carriers for the time value of the production lost during the rebuilding.
The geology is characterized by multiple reservoirs, which we believe provides more opportunities for successful drilling activities. Proved Producing Reserves are based on establishing consistent producing history. The Behind Pipe Reserves are generally uphole recompletion with reserves based on volumetric estimates. Fiscal 2000 continued to be an active year at West Delta, with three completed development wells by PANACO and four exploratory wells being drilled under a farmout agreement with Basin Exploration, three of which were completed. The three new wells that we completed were typical for the Field in that the wells were all set up to produce in several zones during the lives of the wells. The wells were all drilled in Block 54 and they continue to produce.
We have also allowed third party operators to drill on our Block 58 acreage in West Delta under farmout agreements. Typically these agreements provide for PANACO to receive an overriding royalty interest, with an optional back-in after payout in addition to processing fees for the production and handling.
During 2000 Basin Exploration drilled four wells in Block 58, three of which were completed. Generally, we have overriding royalty interests ranging from 10% to 12.5%. Under the Basin agreement we received a prepayment of processing fees for the five-year term of the processing agreement. In addition to the $1.8 million prepayment we receive some incremental fees and reimbursement of expenses as the wells produce. During 1997 and 1994 we farmed out other acreage in Block 58 to El Paso Energy and Samedan, respectively. We also received interest in these wells in addition to fees for processing and handling production from their wells.
East Breaks 109
We acquired the East Breaks 109 and 110 Fields in July 1995 as part of the Zapata Acquisition, for information regarding the East Breaks 109 field, see "Business Strategy - Zapata Acquisition."
East Breaks 165
In May 1998 we acquired the East Breaks 165 Field, for information regarding the East Breaks 165 Field, see "Business Strategy - BP Acquisition."
Umbrella Point
Since its discovery in 1957 by Sun Oil, the Umbrella Point Field has produced over 17 MMbbls of oil and 100 Bcf of natural gas from 35 wells. We own 100% of the working interest in Texas State Leases 73, 74, 87 and 88 in Trinity Bay, Chambers County, Texas, that encompass the Field. Field production is gathered on a small platform complex in approximately 10' of water and transported via a five-mile oil pipeline we own to our onshore production facility at Cedar Point. Gas production is transported through a Midcon Pipeline Co. pipeline.
We acquired this field in July 1997 as a part of the Goldking Acquisition. The Umbrella Point Field consists of multiple stacked reservoirs. Production is from 13 main reservoirs from 7,700' to 9,000'. Prior to Goldking's control of the Field, it was developed and produced by two different operators each controlling two state leases, which created a competitive drainage situation. This situation resulted in several reservoirs that were abandoned prematurely as the former operators tried to accelerate production in uphole reservoirs. Consequently, significant development work remains to sufficiently drain the abandoned reservoirs. On January 21, 1998 we announced the successful completion of our first new well in the Umbrella Point Field. The well flowed 11.5 MMcf and 220 barrels of condensate per day through a 20/64ths choke with flowing tubing pressure of 5,600 PSIG. The production from this well peaked at 27,000 Mcf per day of natural gas and 260 barrels of oil per day in July 1998. It declined to 600 Mcf of natural gas and 5 barrels of oil per day in December 1999. In that month, we completed a workover on the well and brought the production back up to 19,000 Mcf of natural gas and 176 barrels of oil per day. We own an 80% working interest in the well. Peoples Energy Production owns the remaining 20%. Current production from the Umbrella Point Field is 6,500 Mcf and 320 barrels of oil per day.
In late 2000, we entered into an agreement with the owner of an adjacent block in which both parties have agreed to farmout acreage to the other party in order to develop a reservoir that extends under both blocks. The farmout agreement also provides us with a partner in order to reduce our costs of drilling the well, which is exploratory. We have budgeted a new well to be drilled under this agreement in mid-2001. This new well will be a test of the Vicksburg sand and will be drilled on from the block on our acreage. We will own a 40% working interest in this well and will be the operator.
East Breaks 160
We acquired a 33.3% interest in this Field as part of the Amoco Acquisition in October 1996. The Field consists of two federal offshore blocks, East Breaks 160 and 161, with a production platform set in 925' of water placing this production facility on the edge of deep water. Unocal operates the Field and production is from 12 separate reservoirs. Unocal acquired proprietary 3-D Seismic over the Field in 1990 and has identified some undeveloped locations. The Proved Developed Producing Reserve value is proportionately dispersed among eleven producing wells decreasing the risk to some degree. The undeveloped locations included are based on seismic interpretation of attic reserves.
We also receive processing fees from BP from a subsea well drilled in Block 117. Because of the strategic location of the platform on the edge of deepwater, the facility has potential for additional processing and handling fees as more nearby discoveries are made and tied into the platform. In addition to the property interests acquired, we purchased a 33.3% interest in a 12.67 mile 12" natural gas pipeline connecting the East Breaks Block 160 platform to the High Island Offshore System ("HIOS") a natural gas pipeline system in the Gulf of Mexico and a 33.3% interest in a 17.47 mile 10" oil pipeline connecting the platform to the High Island Pipeline System ("HIPS"), a crude oil pipeline system in the Gulf of Mexico. Currently such firms as Exxon, Kerr-McGee and Devon are actively exploring in the East Breaks Area and we believe that, due to the ongoing deepwater exploration in the Area, our platform and pipelines can become long-term strategic revenue generating assets after the field reserves are depleted.
Price Lake
We acquired the Price Lake Field in April 1998, for more information regarding the Price Lake Field, see "Business Strategy-Price Lake Field."
Oil and Gas Information
Third party engineering firms use information we provide them to prepare our reserve estimates. The firms we use to prepare these estimates are Ryder Scott Company, Netherland, Sewell and Associates, Inc., W.D. Von Gonten and Co. and McCune Engineering. Ryder Scott Company and Netherland, Sewell and Associates, Inc. prepare estimates for most of our larger properties and account for 85% of the Pretax PV-10 of our reserve estimates. Our proved oil reserves totaled 8.1 million barrels at December 31, 2000 compared to 8.7 million barrels at December 31, 1999. Our proved natural gas reserves totaled 82.2 Bcf at December 31, 2000 as compared to 82.8 Bcf at December 31, 1999. The Pretax PV-10 value of these reserves totaled $533 million at December 31, 2000 compared to $181 million at December 31, 1999. For more information related to our oil and natural gas reserves, see "Supplemental Information Related to Oil and Gas Producing Activities (Unaudited)," which is in Part IV, Item 14(a) in this Form 10-K.
Producing Wells(a)
The following table presents the number of producing oil and natural gas wells attributable to our properties, as of December 31, 2000.
__________ (a) One or more completions in the same borehole are counted as one well. (b) A "gross well" is a well in which we own a working interest. (c) A "net well" is deemed to exist when the sum of the fractional working interests in gross wells equals one.
Leasehold Acreage
The following table presents the estimated developed acreage attributable to our properties, as of December 31, 2000.
__________ (a) Developed acreage is acreage assignable to producing wells. (b) A "gross acre" is one in which we own a working interest. (c) A "net acre" is deemed to exist when the sum of the fractional working interests in gross acres equals one. (d) In addition to these acres, our undeveloped offshore potential exists at greater depths beneath existing producing reservoirs.
Drilling Activities
The following table presents the number of gross productive and dry wells in which we had an interest that were drilled and completed during the five years ended December 31, 2000. You should not consider this to be indicative of our future performance, nor should you assume that there is any correlation between the number of productive wells drilled and the oil and natural gas reserves generated from those wells or the costs of productive wells compared to the costs of dry wells.
Title to Oil and Gas Properties
When we acquire properties we obtain title opinions for our more significant properties. Prior to the commencement of drilling operations we conduct a thorough drill site title examination and perform any curative work with respect to significant defects.
Item 3.
Item 3. Legal Proceedings.
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.
In August 2000, an action was filed against the Company by Coastal Oil and Gas Corporation (now El Paso Corporation) for nonpayment of joint interest billing invoices. The suit seeks to recover unpaid costs from a well drilled on a property operated by El Paso. PANACO counter sued alleging, among other things, gross misconduct and negligence in drilling the well. The case is still in discovery and it is not possible to evaluate the likelihood of an unfavorable outcome or to estimate the amount or range of potential loss in addition to what we have already accrued.
We are presently a party to several other legal proceedings, which we consider to be routine and in the ordinary course of business. We have no knowledge of any other pending or threatened claims that could give rise to any litigation, which would be material to the Company.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5. Market for Common Stock and Related Shareholder Matters.
Our authorized capital shares consists of 100,000,000 Common Shares, par value $.01 per share, and 5,000,000 preferred shares, par value $.01 per share. The following description of the capital shares does not purport to be complete or to give full effect to the provisions of statutory or common law and is subject in all respects to the applicable provisions of our Certificate of Incorporation.
Common Shares
We are authorized by our Certificate of Incorporation, as amended, to issue 100,000,000 Common Shares, of which 24,323,521 shares are issued and outstanding as of March 20, 2001 and are held by over 6,700 shareholders, based upon information available on individual security position listings.
The holders of Common Shares are entitled to one vote for each share held on all matters submitted to a vote of common holders. The Common Shares have no cumulative voting rights, which means that the holders of a majority of the Common Shares outstanding can elect all the directors if they choose to do so. In that event, the holders of the remaining shares will not be able to elect any directors.
Each Common Share is entitled to participate equally in dividends, as and when declared by the Board of Directors, and in the distribution of assets in the event of liquidation, subject in all cases to any prior rights of secured creditors and outstanding preferred shares. The Common Shares have no preemptive or conversion rights, redemption rights, or sinking fund provisions. The outstanding Common Shares are duly authorized, validly issued, fully paid, and non-assessable.
Warrants and Options
We also have outstanding options to acquire 500,000 Common Shares at a price of $1.92 per share and expire August 17, 2006. These options are all held by current employees and contain limited provisions for adjustment of the number of shares in the event of a subdivision, combination or reclassification of Common Shares. They do not have any rights to demand registration or "piggy back" rights in the event of a registration of Common Shares.
Preferred Shares
Pursuant to our Certificate of Incorporation, we are authorized to issue 5,000,000 preferred shares, and the Board of Directors, by resolution, may establish one or more classes or series of preferred shares having the number of shares, designations, relative voting rights, dividend rates, liquidation and other rights preferences, and limitations that the Board of Directors fixes without any shareholder approval.
Transfer Agent
The transfer agent, registrar and dividend disbursing agent for our Common Shares is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn, New York 11204.
Price Range of Common Shares
Since September 2000, our Common Shares have been traded on The American Stock Exchange under the symbol "PNO." Prior to that, our Common Shares were traded on the OTC Bulletin Board and on NASDAQ under the symbol "PANA." They commenced trading September 21, 1989. The following table sets forth, for the periods indicated, the high and low closing prices for the Common Shares.
On March 19, 2001, the last sale price of the Common Shares was $2.62 per share.
Dividend Policy
We have not paid any cash dividends on our Common Shares. The Delaware General Corporation Law, to which we are subject, permits us to pay dividends only out of our capital surplus (the excess of net assets over the aggregate par value of all outstanding capital shares) or out of net profits for the fiscal year in which the dividend is declared or the preceding fiscal year. The Credit Facility requires the consent of the lenders and the Senior Notes contain limitations on any dividends or distributions and on any purchases of our Common Shares. We retain our cash flow to finance the expansion and development of our business and currently do not intend to pay dividends on the Common Shares. Any future payments of dividends will depend on, among other factors, earnings, cash flow, financial condition, and capital requirements.
Certain Anti-takeover Provisions
In September 1998, the Board elected to redeem the Preferred Share Purchase Right at its stated value of $0.005 per Common Share.
The provisions of the Certificate of Incorporation and By-laws summarized in the following paragraphs may be deemed to have an anti-takeover effect and may delay, defer, or prevent a tender offer or takeover attempt that a shareholder might consider to be in their best interests, including attempts that might result in a premium over the market price for the shares held by our shareholders. In addition, certain provisions of Delaware law and our Long-Term Incentive Plan may be deemed to have a similar effect.
CERTIFICATE OF INCORPORATION AND BY-LAWS. Our Board of Directors is divided into three classes. The term of office of one class of directors expires at each annual meeting of shareholders, when their successors are elected and qualified. Directors are elected for three-year terms. Shareholders may remove a director only for cause. In general, the Board of Directors, not our shareholders, has the right to appoint persons to fill vacancies on the Board of Directors.
Pursuant to our Certificate of Incorporation, the Board of Directors, by resolution, may establish one or more classes or series of preferred shares having the number of shares, designation, relative voting rights, dividend rates, liquidation and other rights, preferences, and limitations that the Board of Directors fixes without any shareholder approval. Any rights, preferences, privileges, and limitations that are established could have the effect of impeding or discouraging the acquisition of the Company.
Our Certificate of Incorporation also contains a "fair price" provision that requires the affirmative vote of the holders of at least 80% of the voting shares and the affirmative vote of at least two-thirds of our voting shares that are not owned, directly or indirectly, by the Related Person to approve any merger, consolidation, sale or lease of all or substantially all of our assets or certain other transactions involving any Related Person. For purposes of the fair price provision, a "Related Person" is any person beneficially owning 10% or more of our voting shares who is a party to the Transaction at issue, a director who is also an officer and is a party to the Transaction at issue, an affiliate of either such person, and certain transferees of those persons. The voting requirements are not applicable to certain transactions, including those that are approved by the Continuing Directors (as defined in the Certificate of Incorporation) or that meet certain "fair price" criteria contained in the Certificate of Incorporation.
Our Certificate of Incorporation further provides that shareholders may act only at an annual or special meeting of shareholders and not by written consent, that only the Board of Directors may call special meetings of shareholders, and that only business proposed by the Board of Directors may be considered at special meetings of shareholders.
Our Certificate of Incorporation also provides that the only business (including election of directors) that may be considered at an annual meeting of shareholders, in addition to business proposed (or persons nominated to be directors) by the directors, is business proposed (or persons nominated to be directors) by shareholders who comply with the notice and disclosure requirements of the Certificate of Incorporation. In general, the Certificate of Incorporation requires that a shareholder give us notice of proposed business or nominations no later than 60 days before the annual meeting of shareholders (meaning the date on which the meeting is first scheduled and not postponements or adjournments thereof) or (if later) 10 days after the first public notice of the annual meeting is sent to common shareholders. In general, the notice must also contain certain information about the shareholder proposing the business or nomination, his interest in the business, and (with respect to nominations for director) information about the nominee of the nature ordinarily required to be disclosed in public proxy solicitations. The shareholder must also submit a notarized letter from each of his nominees stating the nominee's acceptance of the nomination and indicating the nominee's intention to serve as director if elected.
The Certificate of Incorporation also restricts the ability of shareholders to interfere with the powers of the Board of Directors in certain specified ways, including the constitution and composition of committees and the election and removal of officers.
The Certificate of Incorporation provides that approval by the holders of at least two-thirds of the outstanding voting shares is required to amend the provisions of the Certificate of Incorporation discussed in the preceding paragraphs and certain other provisions, except that approval by the holders of at least 80% of the outstanding voting shares, together with approval by the holders of at least two-thirds of the outstanding voting shares not owned, directly or indirectly, by the Related Person, is required to amend the fair price provisions and except that approval of the holders of at least 80% of the outstanding voting shares is required to amend the provisions prohibiting shareholders from acting by written consent.
DELAWARE ANTI-TAKEOVER STATUTE. We are a Delaware corporation and are subject to Section 203 of the Delaware General Corporation Law. In general, Section 203 prevents an "interested shareholder" (defined generally as a person owning 15% or more of outstanding voting shares) from engaging in a "business combination" (as defined in Section 203) with us for three years following the date that person became an interested shareholder unless (a) before that person became an interested shareholder, the Board of Directors approved the transaction in which the interested shareholder became an interested shareholder or approved the business combination, (b) upon consummation of the transaction that resulted in the interested shareholder's becoming an interested shareholder, the interested shareholder owns at least 85% of our voting shares outstanding at the time the transaction commenced (excluding shares held by directors who are also officers and by employee stock plans that do not provide employees with the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer), or (c) following the transaction in which that person became an interested shareholder, the business combination is approved by the Board of Directors and authorized at a meeting of shareholders by the affirmative vote of the holders of at least two-thirds of the outstanding voting shares of the Company not owned by the interested shareholder. In connection with a private sale of Common Shares in 1999, the Board elected to waive the Delaware anti-takeover statute.
Under Section 203, these restrictions also do not apply to certain business combinations proposed by an interested shareholder following the announcement or notification of one of certain extraordinary transactions involving us and a person who was not an interested shareholder during the previous three years or who became an interested shareholder with the approval of a majority of our directors, if that extraordinary transaction is approved or not opposed by a majority of the directors who were directors before any person became an interested shareholder in the previous three years or who were recommended for election or elected to succeed such directors by a majority of such directors then in office.
LONG-TERM INCENTIVE PLAN. Awards granted pursuant to the Long-Term Incentive Plan may provide that, upon a change in control (a) each holder of an option will be granted a corresponding stock appreciation right, (b) all outstanding stock appreciation rights and stock options become immediately and fully vested and exercisable in full, and (c) the restriction period on any restricted stock award shall be accelerated and the restrictions shall expire.
DEBT. Certain provisions in the Credit Facility and Senior Notes may also impede a change in control, in that they provide that the Credit Facility and Senior Notes become due if there is a change in the management or a merger with another company. The Senior Notes would become due upon an increase in ownership of Common Shares outstanding to over 20% of the then outstanding Common Shares. Our Credit Facility would become due upon an increase in ownership of Common Shares outstanding to over 30% of the then outstanding Common Shares. See "Business - Senior Notes."
Item 6.
Item 6. Selected Financial Data.
The following historical data is derived from the Financial Statements and the notes thereto. When reading this data, you should refer to our audited consolidated financial statements and the related notes, both of which are included in this Form 10-K, Item 8.
(1) Results for the years ended December 31, 1999 and 1998 include impairments of oil and gas properties of $13.2 million and $20.4 million, respectively. (2) During 2000 the deferred tax valuation allowance was reversed, resulting in an income tax benefit of $29 million, see "Management's Discussion and Analysis of Financial Condition and Results of Operations." (3) No Common Share dividends have been paid in the five-year period ending December 31, 2000. Results for each year presented may not necessarily be comparative due to numerous acquisitions, see "Business strategy - Strategic Acquisitions and Mergers" for further discussion of acquisitions.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
When reading the following discussion, you should also read our Consolidated Financial statements and their notes, both of which are included in this Form 10-K. The following discussion is our best assessment of our Company and current operations. You should not assume that these results will continue.
General
With the exception of historical information, the matters discussed in this Form 10-K contain forward-looking statements. The forward-looking statements we make, not only in this Form 10-K, 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, we cannot assure you that the actual results of our Company will not differ from those expectations.
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
During 2000 we focused our efforts on increasing our cash flows from operations and reducing debt. Due to the short lived nature of our reserve base and in order to implement our strategy, we invest a significant amount of our cash flows into capital expenditures. In addition to reducing outstanding debt by $17.2 million in 2000, we spent $37.2 million drilling developmental and exploratory wells and acquiring proved reserves. We also deposited $2.4 million into escrow accounts, which are held as restricted deposits and are for the eventual plugging and abandonment of certain offshore properties that we own. After the reduction of $17.2 million, the amount outstanding under our credit facility at December 31, 2000 was $19.4 million. We had in place letters of credit in the amount of $7.5 million, leaving $31.8 million available for capital expenditures and general corporate purposes.
At December 31, 2000, 68% of our total assets were represented by oil and natural gas properties, pipelines and equipment, net of depreciation, depletion and amortization.
Working Capital
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, the payment of amounts due others and timing of capital expenditures also affect our working capital. These factors caused us to have a working capital deficit on December 31, 2000, of $16.6 million. We believe that our cash flow from operations and borrowing availability under our Credit Facility will be sufficient to fund this working capital deficit in addition to our ongoing operations, capital expenditures and additional reduction of debt.
For the year 2001, our Board of Directors has approved a $37.1 million capital budget. This budget is based primarily on those resources available to us at this time. We believe that our cash flows from operations and borrowings under our Credit Facility will fund this level of capital expenditures and that we will have sufficient availability under our Credit Facility to do so.
Financing Activities
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. Of the $96.2 million net proceeds, $54.7 million was used to repay substantially all of our outstanding indebtedness with the remaining $41.5 million used for capital expenditures including the BP Acquisition.
Credit Facility
Our primary source of capital beyond discretionary cash flows is our Credit Facility. Our 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. We may also use the Credit Facility for working capital support, to provide letters of credit and general corporate purposes.
In September 1999 we put in place a new Credit Facility, with Foothill Capital Corp. as the Agent, along with Foothill Partners, L.P. and Ableco Finance, a subsidiary of Cerberus Capital Management, L.P. This Credit Facility is a $60 million line, with a term of two years to October 1, 2001, and extendable for two additional six month periods, at our sole option. We are reviewing alternatives to extending this agreement, including replacing this Credit Facility with a bank facility. Management believes that if we do not choose to renew the existing facility, that we will be able to replace it with one that provides acceptable terms. Borrowings under this Facility bear interest at rates ranging from prime plus .5% up to prime plus 3.0% depending on the amounts borrowed. We had $19.4 million outstanding at December 31, 2000.
The Credit Facility is a revolving credit agreement subject to monthly borrowing base determinations. These determinations are made based on internally prepared engineering reports, using a two year average of NYMEX future commodity process 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.
Under the terms of this Credit Facility, we must maintain a ratio of trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0 through December 31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term of the Facility. We must also maintain a working capital ratio, as defined in the agreement, of not less than .25 to 1.0. Also, the Credit Facility contains certain limitations on mergers, additional indebtedness and pledging or selling assets. We were in compliance with those covenants on December 31, 2000 and anticipate compliance throughout the term of the loan.
Production, Price, and Cost Data
The following table presents certain production, price, and cost data with respect to our properties for the three years ended December 31, 2000.
______________
(a) Production information is net of all royalty interests. Beginning in 1999, the MMS began taking its royalties in-kind rather than being paid in cash. (b) Oil production is converted to Mcfe at the rate of 6 Mcf per Bbl, which represents the estimated relative energy content of natural gas to oil.
Results of Operations
Revenues
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 2000 where we benefited from a steady increase in realized prices. The average realized price, net of hedges, has increased 105% for oil and 103% for natural gas from 1998 to 2000.
Our oil and natural gas revenues reached an all-time high of $88.6 million in 2000, a 108% increase over 1999. Oil production decreased 9%, to 1,070 MBbls, from 1,170 MBbls in 1999. This decrease was more than offset by higher average realized oil prices. Including hedges, we realized a 71% increase in our average price per barrel. Natural gas prices also increased dramatically in 2000, from $2.02 per Mcf in 1999 to $4.20 per Mcf in 2000. Coupled with a 22% increase in natural gas production, natural gas revenues increased to $56.9 million in 2000, a 154% increase over 1999. For the first three quarters of 1999, our capital spending decreased from the same periods in 1998. Once commodity prices began to improve, we increased spending in late 1999 and through 2000, which resulted in increased production.
Oil and natural gas revenues were 15% lower in 1999 when compared to 1998. While average oil prices and production improved 20% and 31%, respectively, natural gas production decreased 38% in 1999, while natural gas prices remained relatively flat. As our capital spending decreased in 1999 from 1998, our natural gas production also decreased.
During the fourth quarter of 2000 we sold two offshore properties resulting in a gain of $1.9 million.
Two lawsuits were settled during 2000 for which we received a total of $2.6 million.
Cost and Expenses
Lease operating expenses ("LOE") totaled $20.9 million in 2000 versus $17.7 in 1999, and $18.1 million in 1998. During 2000 we performed many workovers and property repairs in conjunction with our increased capital spending. LOE for 2000 includes $5.7 million of these repair, maintenance and workover expenditures, as compared to $1.0 million for these same types of costs in 1999. During 1999, LOE remained relatively flat versus 1998.
Depletion, depreciation and amortization ("DD&A") increased 2% in 2000 to $27.0 million, compared to $26.4 million in 1999. The increase is due to a 10% increase in total production, upon which our depletion is calculated. However, this increased production was offset by a lower depletion rate per unit of production, from $1.46 per Mcf equivalent ("Mcfe") in 1999 to $1.35 per Mcfe in 2000. The decrease in depletion per Mcfe is primarily due to property impairments in 1999 totaling $13.2 million. This impairment reduced the remaining capitalized costs to be depleted in 2000. Likewise, in 1999, while total production decreased 23% when compared to 1998, DD&A decreased 30%, from $37.5 million to $26.4 million. This decrease is also due to a lower depletion rate per Mcfe of production in 1999, of $1.46 as compared to $1.60 in 1998. A property impairment of $20.4 million in 1998 reduced the capitalized costs that were depleted in 1999.
General and administrative expenses totaled $5.2 million, $4.1 million and $4.6 million in 2000, 1999 and 1998, respectively. The increase in 2000 of $1.1 million relates primarily to $0.6 million of employee bonuses paid in 2000, as there were no bonuses paid in 1999 and an increase in bad debt expense of $0.2 million. When comparing 1999 to 1998, the decrease is primarily due to a decrease in bad debt expense of $1.0 million from 1998.
Production and ad valorem taxes totaled $2.1 million, $1.2 million and $1.4 million in 2000, 1999 and 1998, respectively. These taxes vary from year to year primarily based on our production mix. Production from offshore properties is not subject to production taxes, while onshore properties and those in state waters are. These taxes are based on the value of the sales from the production or the number of units produced, depending on the location of the properties.
Exploration expenses, including geological and geophysical expenses ("G&G") increased $3.2 million in 2000, from $2.5 million in 1999 to $5.7 million. As our capital spending increased in 2000, we also increased our exposure to exploration projects. We believe that a balanced capital budget includes a mix of higher risk, higher reward exploratory projects as well as development projects. The increase of $3.2 million relates to exploratory dry hole expense recorded in three wells that were drilled in 2000, the largest of which was the A-10 well in the East Breaks 110 Field, which totaled $2.3 million. The decrease of $5.1 million in 1999 is due to lower capital spending in that year.
During 1999 we recorded an oil and gas property impairment of $13.2 million, which related to two property groups. Part of the impairment provision related to our unproved property costs, for which we did not have planned development activity. The other part of the impairment provision was recorded in
connection with a reserve reduction on a proved property. During 1998 we recorded a provision for impairment of our oil and gas properties primarily due to historically low market prices used in estimating the future recoverability of those properties' costs. During 2000 we did not record an asset impairment.
During 2000 a former officer and director resigned in accordance with the terms of his employment agreement. Under the terms of this agreement, the former employee received two years of his salary in addition to other benefits. We recorded a $0.7 million charge in connection with the resignation. During 1998 we recorded a $1.0 million charge in connection with the consolidation of our Kansas City office into our Houston office in addition to severance expense for several employees that did not move to Houston.
During 2000 net interest expense increased primarily due to higher borrowing levels under our Credit Facility. Our weighted average interest rates also increased due to two factors (1) a new Credit Facility put in place in late 1999 and (2) increases in the prime rate, which is the base for our Credit Facility charges. Net interest expense increased in 1999 due to higher borrowing levels under our Credit Facility.
Income Tax 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 2000 we recorded an income tax benefit of $29 million by reversing a valuation allowance recorded against these assets. We also recorded an income tax expense provision of $6.3 million during 2000 based on pre-tax income for the year of $16.5 million, resulting in a net income tax benefit of $22.7 million in 2000. No income tax expense or benefit was recorded in 1999.
Extraordinary Item
During 1999 we recorded an extraordinary item for the early retirement of long-term debt. This charge was recorded in connection with the prepayment of our Credit Facility. We put in place a new Credit Facility in September 1999.
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 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, our Board of Directors has approved a $37.1 million capital budget. This budget includes approximately $21.5 million of exploratory projects, the majority of which will be spent at our East Breaks 109 and 110 Fields. To date in 2001, we have completed the first of these exploratory wells, the A-7 well as a producing natural gas well. 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.
In late 2000, in conjunction with the preparation of our 2001 capital budget, natural gas prices were at much higher levels than had been in previous years. Based on a recommendation from management, the Board approved the
execution of a swap agreement on approximately 40% of our estimated 2001 natural gas production. The swap was put in place in late November 2000 and is in effect from January 1 through December 31, 2001. We agreed to swap 18,000 MMbtu per day at an average price for the year of $4.91. The purpose of the swap is to ensure a minimum level of revenues that would allow for debt service and the completion of the entire $37.1 capital budget. To date in 2001, the market prices for our natural gas have exceeded the fixed prices in the swap agreement. However, by having approximately 60% of our natural gas production "unhedged", we have benefited from the higher prices. We also have in place an option to put oil to a purchaser for $25 per barrel on 1,000 barrels per day from January 1 through September 30, 2001. This represents approximately 39% of 2001 estimated oil production.
The estimates of the future net cash flows from our oil and natural gas reserves were made by third party petroleum engineers in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." The prices used in preparing these estimates were based on spot market prices on December 31, 2000, which averaged $26.60 per barrel of oil and $9.65 per Mcf of natural gas. These average prices are based upon spot market prices on December 31 for each property's location and differential to those market prices. You should not assume that these estimates represent the market value for those reserves, nor should you assume that we will achieve those results from our reserves.
Currently, we are selling our oil production for slightly higher than the prices at December 31, 2000 and our natural gas production for much less. Based on current market conditions, we project that our 2001 average realized prices for oil and natural gas will average approximately $26.96 and $5.62, respectively.
During the first quarter of 2001 we will recognize approximately $3.5 million of dry hole expense for the East Breaks 110 A-4 well. The well was spud on January 30, 2001 and reached total depth in early March. The well reached the targeted objective, however, the sand contained an uncommercial quantity of hydrocarbons.
Change in Accounting Method
In accordance with our hedging policy, we expect to continue using derivative financial instruments as a means of hedging prices we receive for our oil and natural gas production. We have generally used swaps, collars or options with counter parties that are major financial institutions or commodities trading institutions. Through December 31, 2000 gains and losses from these financial instruments have been recognized in revenues for the periods to which the production covered by the derivative financial instruments relate.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statement of operations. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. All of our derivative financial instruments subject to SFAS 133 have been designated as cash flow hedges.
Adoption of SFAS 133 at January 1, 2001 will result in the recognition of $10 million of derivative liabilities included in accrued liabilities in the Consolidated Balance Sheets and $6 million, net of taxes, of deferred hedging losses, included in accumulated other comprehensive income. We will also recognize an increase in assets of $261,000 and net income of $162,000 for the fair value of an option to put oil to a purchaser as the effects of the change in accounting principle. Amounts were determined as of January 1, 2001 based on quoted market values, our portfolio of derivative instruments, and the measurement of hedge effectiveness.
Item 7a.
Item 7a. Qualitative and Quantitative Disclosure About Market Risks.
We follow a hedging strategy designed to protect against the possibility of severe price declines due to unusual market conditions. We usually make hedging decisions to assure a payout of a specific acquisition or development project, to ensure sufficient revenues for debt service and capital expenditures or to take advantage of unusual strength in the market. The type of hedge agreement we enter into varies, based on among other factors, the market conditions at the time.
During 1998, 1999 and 2000 we hedged the following percentages of our oil and natural gas production in accordance with our hedging policy and/or as a requirement with our Credit Facility. During 1998 and 1999 we entered into a combination of options to put produced volumes to a purchaser at a predetermined price, or swaps based on a single predetermined price or a range of high and low predetermined prices. During 2000 we entered into agreements to put oil and natural gas to a purchaser at predetermined prices. Following is a summary of the results of those years' hedging activities.
For 2001, the 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.
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. We paid $365,000 for the put option, of which $273,000 remained unamortized at December 31, 2000. At December 31, 2000 and 1999 the fair value of these hedges was losses of $10.6 million and $1.8 million, respectively.
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. Certain of our commodity hedging instruments, primarily swaps and options, are off balance sheet transactions and, accordingly, no respective carrying amounts for these instruments were included in the accompanying consolidated balance sheets as of December 31, 2000 and 1999. A 10% increase in oil and natural gas prices would increase the anticipated hedge losses by $4.3 million on December 31, 2000. These hedges are accounted for as gains and losses in oil and natural gas revenue in the month of hedged production.
At December 31, 2000 we had $100 million in Senior Notes outstanding with a fixed interest rate of 10 5/8%. The fair value of the Notes, based on quoted market prices at December 31, 2000, was approximately $80 million. We also had $19.4 million outstanding under our Credit Facility at December 31, 2000. The Credit Facility is a floating rate facility, with a fair value of $19.4 million. We do not have any interest rate hedge agreements at December 31, 2000.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements are included beginning at.
The following unaudited summarized quarterly financial data should be read in conjunction with the Financial Statements, beginning on and Item 7. - "Managements Discussion and Analysis of Financial Condition and Results of Operations." Amounts are in thousands, except per share data.
Quarterly periods ending December 31, 2000 - ------------------------------------------
During the second and fourth quarters we received lawsuit settlements totaling $1.0 million and $1.6 million, respectively. During the third quarter of 2000 we recorded a $0.7 million severance charge in connection with the resignation of a former employee and director.
During the second quarter we also recorded an income tax benefit of $29.0 million due to the reversal of a deferred tax asset valuation allowance. In the second quarter and the subsequent two quarters of 2000 we also began recording income tax expense which totaled $1.1 million, $1.5 million and $3.7 million for the second, third and fourth quarters, respectively.
Financial results for the first three quarters of 2000 were restated. The adjustments reflect an increase in a 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 revenues were $63,000, $(744,000) and $(1,007,000) for the first, second and third quarters, respectively. The adjustments to depletion, depreciation and amortization were $(35,000), $(60,000) and $(293,000) for the first, second and third quarters, respectively. The adjustments to income before income taxes were $98,000, $(684,000) and $(714,000) for the first, second and third quarters, respectively. The adjustments to net income were $98,000, $(425,000) and $(444,000) for the first, second and third quarters, respectively.
Quarterly periods ending December 31, 1999 - ------------------------------------------
During 1999 we recorded impairments of our oil and gas properties in the third and fourth quarters totaling $5.7 million and $7.5 million, respectively. We also recorded an extraordinary item, a loss on early retirement of debt, during the third quarter in the amount of $0.1 million.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation.
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference.
Part IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) See Index to Financial Statements, Page.
(b) Reports on Form 8-K. Form 8-K filed October 26, 2000 with respect to the Change of Control Offer for the Company's Senior Notes.
(c) Exhibits and Financial Statement Schedules.
Exhibit Number Description ------ -----------
3.1* Certificate of Incorporation of the Company.
3.2* Amendment to Certificate of Incorporation dated November 19, 1991.
3.3* By-laws of the Company.
3.4 Amendment to Certificate of Incorporation of the Company dated September 24, 1996 filed as an exhibit to the Amended Current Report on Form 8-K/A, filed with the Commission on November 18, 1996, and incorporated herein by this reference.
4.1* Article Fifth of the Certificate of Incorporation of the Company in Exhibit 3.1.
4.2* Form of Certificate of Common Shares par value $.01 per share, of the Company.
4.3 Rights Agreement, dated as of August 3, 1995, between PANACO, Inc., and American Stock Transfer and Trust Company, which includes as Exhibit A the Form of Certificate of Designation of Series A Preferred Stock, Exhibit B the Form of Rights Certificate and Exhibit C the Summary of Rights to Purchase Preferred Stock was filed as Exhibit 1 to the Registration Statement on Form 8-A, filed with the Commission on August 21, 1995, and incorporated herein by this reference.
4.4*** Indenture dated October 9, 1997, among the Company and UMB Bank, N.A., as trustee.
4.6*** Form of 10 5/8 % Series B Senior Note due 2004.
10.1* PANACO, Inc. Long-Term Incentive Plan.
10.13** PANACO, Inc. Employee Stock Ownership Plan & Trust.
10.13.1 Amendment to PANACO, Inc. Employee Stock Ownership Plan.
10.17 Form of Executive Officer and Director Indemnification Agreement, filed with the Commission as an exhibit to the Company's Form 10-Q on August 15, 1997, and incorporated herein by this reference.
10.25 New credit agreement dated September 30, 1999 filed as an exhibit on the Company's Form 10-Q on November 15, 1999, and incorporated herein by reference.
10.25.1 Second amendment to the Company's credit agreement filed as an exhibit on the Form 10-Q on November 10, 2000, and incorporated herein by reference.
10.25.2**** Third amendment to the Company's credit agreement.
10.27 Employment agreement between the Company and Robert G. Wonish filed as an exhibit on the Form 10-Q on November 10, 2000, and incorporated herein by reference.
10.28**** Form of stock option agreement between the Company and key employees.
*Filed with the Registration Statement on Form S-4, Commission File No. 33-44486, initially filed December 13, 1991, and incorporated herein by this reference.
**Filed with the Registration Statement on Form S-1, Commission file No. 333-18233, initially filed December 19, 1996, and incorporated herein by this reference.
***Filed with the Registration Statement on Form S-4, Commission File No. 333-39919, initially filed November 10, 1997, and incorporated herein by this reference.
****Filed herewith.
(d) Financial Statement Schedules. See Index to Financial Statements, Page.
GLOSSARY OF SELECTED OIL AND GAS TERMS
2-D Seismic. Seismic data and the related technology used to acquire and process such data to yield a two-dimensional view of a "slice" of the subsurface.
3-D Seismic. Seismic data and the related technology used to acquire and process such data to yield a three-dimensional picture of the subsurface. 3-D Seismic is created by the propagation of sound waves through sedimentary rock layers, which are then detected and recorded as they are reflected and refracted back to the surface. By measuring the time taken for the sound to return and applying computer technology to process the resulting data in volume, imagery of significantly greater accuracy and usefulness than older-style 2-D Seismic can be created.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalents converting one Bbl of oil to six Mcf of natural gas.
Block. One offshore unit of lease acreage, generally 5,000 acres.
Btu. British Thermal Unit, the quantity of heat required to raise one pound of water by one degree Fahrenheit.
Condensate. A hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Estimated Future Net Revenues. Revenues from production of oil and natural gas, net of all production-related taxes, lease operating expenses and capital costs.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Farmout. An agreement whereby the lease owner agrees to allow another to drill a well or wells and thereby earn the right to an assignment of a portion or all of the lease, with the original lease owner typically retaining an overriding royalty interest and other rights to participate in the lease.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Group 3-D Seismic. Seismic procured by a group of parties or shot on a speculative basis by a seismic company.
MBbl. One thousand Bbls of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalents converting one Bbl of oil to six Mcf of natural gas.
Mcfe/d. Mcfe per day.
MMbbl. One million Bbls of oil or other liquid hydrocarbons.
MMbtu. One million Btu.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalents converting one Bbl of oil to six Mcf of natural gas.
Natural Gas Equivalent. The amount of natural gas having the same Btu content as a given quantity of oil, with one Bbl of oil being converted to six Mcf of natural gas.
Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.
Net Oil and Gas Sales. Oil and natural gas sales less oil and natural gas production expenses.
Net Pay. The thickness of a productive reservoir capable of containing hydrocarbons.
Net Production. Production that is owned by the Company after royalties and production due others.
Net Revenue Interest. A share of the Working Interest that does not bear any portion of the expense of drilling and completing a well and that represents the holder's share of production after satisfaction of all royalty, overriding royalty, oil payments and other non-operating interests.
Overriding Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of exploration and production.
Payout. That point in time when a party has recovered monies out of the production from a well equal to the cost of drilling and completing the well and the cost of operating the well through that date.
Pretax PV-10. The present value of proved reserves is an estimate of the discounted future net cash flows from oil and natural gas reserves at December 31, 2000, or as otherwise indicated. Net cash flow is defined as net revenues less production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. These future net cash flows have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. In accordance with Commission rules, estimates have been made using constant oil and natural gas prices and operating costs, at December 31, 2000, or as otherwise indicated.
Productive Well. A well that is producing oil or natural gas or that is capable of production in paying quantities.
Proprietary 3-D Seismic. Seismic privately procured and owned by the procurer.
Proved Developed Non-Producing Reserves. Reserves that consist of (i) Proved Reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) Proved Reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved Developed Producing Reserves. Reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of oil, natural gas and natural gas liquids 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 Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in a different formation or producing horizon from that in which the well was previously completed.
Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.
Shut-In. To close down a producing well or field temporarily for repair, cleaning out, building up reservoir pressure, lack of a market or similar conditions.
Sidetrack. A drilling operation involving the use of a portion of an existing well to drill a second hole, in which a milling tool is used to grind out a "window" through the side of a drill casing at some selected depth. The drilling bit is then directed out of the window at a desired angle into previously undrilled strata. From this directional start a new hole is drilled to the desired formation depth and casing is set in the new hole and tied back into the older casing, generally at a lower cost because of the utilization of a portion of the original casing.
Tcf. One trillion cubic feet of natural gas.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
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.
PANACO, Inc.
By: \s\ Robert G. Wonish March 20, 2001 ----------------------- -------------- Robert G. Wonish, President and Chief Operating Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
By: \s\ Robert G. Wonish March 20, 2001 ----------------------- -------------- Robert G. Wonish, President and Chief Operating Officer and Director
By: \s\ Todd R. Bart March 20, 2001 ------------------------ -------------- Todd R. Bart Chief Financial Officer and Principal Accounting Officer
By: \s\ Harold First March 20, 2001 ------------------------ -------------- Harold First, Director
By: \s\ A. Theodore Stautberg, Jr. March 20, 2001 ----------------------------- -------------- A. Theodore Stautberg, Jr., Director
By: \s\ James B. Kreamer March 20, 2001 ------------------------ -------------- James B. Kreamer, Director
By: \s\ Felix A. Pardo March 20, 2001 ------------------------ -------------- Felix A. Pardo, Director
By: ------------------------ Stanley Nortman, Director
By: ------------------------ George W. Hebard III, Director
PANACO, Inc.
Beginning on PANACO, Inc. - AUDITED FINANCIAL STATEMENTS Page Number - ------------------------------------------- ------------
Independent Auditors' Report
Consolidated Balance Sheets, December 31, 2000 and 1999
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998
Consolidated Statements of Changes in Stockholders' Equity (Deficit)
for the Years Ended December 31, 2000, 1999 and 1998
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998
Notes to Consolidated Financial Statements for the Years Ended
December 31, 2000, 1999 and 1998
Independent Auditors' Report
The Board of Directors and Shareholders of PANACO, Inc.:
We have audited the accompanying consolidated balance sheets of PANACO, Inc. as of December 31, 2000 and 1999, and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of PANACO, Inc. as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP Houston, Texas March 7, 2001
PANACO, Inc. CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
See accompanying notes to consolidated financial statements.
PANACO, Inc. CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
PANACO, Inc. CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT) FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998
See accompanying notes to consolidated financial statements.
PANACO, Inc. CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
For the year ended December 31, 2000: - ------------------------------------
The Company issued 337,000 common shares valued at $128,000 to the ESOP. The change in accounts payable from December 31, 1999 to December 31, 2000 excludes this non-cash reduction of the liability.
For the year ended December 31, 1999: - ------------------------------------
The Company issued 281,566 common shares valued at $250,000 to the ESOP. The change in accounts payable from December 31, 1998 to December 31, 1999 excludes this non-cash reduction of the liability.
For the year ended December 31, 1998: - ------------------------------------
The Company issued 43,281 common shares valued at $165,000 to the ESOP. The Company also issued 52,793 common shares valued at $110,000 as director compensation which were expensed in 1998.
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year ended December 31:
PANACO, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------
Nature of Business - ------------------ PANACO, Inc. (the "Company") is an independent oil and natural gas exploration and production company with operations focused in the Gulf of Mexico and onshore in the Gulf Coast region. The Company operates a majority of its assets in order to control the operations and the timing of expenditures. The majority of the Company's properties are located in state or federal waters of the Gulf of Mexico, where the costs of operations, productions rates and reserve potential are generally greater than properties located onshore. The Company's assets and operations are primarily concentrated on a small group of properties. The Company has grown primarily by acquiring properties that have additional development potential and improving the economics of those properties by exploiting the oil and natural reserves and reducing operating costs and making them more efficient.
Revenue Recognition - ------------------- The Company recognizes its ownership interest in oil and gas production as revenue. Gas balancing arrangements with partners in natural gas wells are accounted for by the entitlements method. At December 31, 2000 the Company's imbalance position was an over-produced, or payable balance of 610,000 Mcf valued at $2.9 million. At December 31, 1999 the Company's quantity and dollar amount of such arrangements were immaterial.
Hedging Transactions - -------------------- The Company hedges the prices of its oil and gas production through the use of oil and natural gas swap contracts and put options within the normal course of its business. The Company uses swap contracts and put options to reduce the effects of fluctuations in oil and natural gas prices (see Note 9). To qualify as hedging instruments, swaps or put options must be highly correlated to anticipated future sales such that the Company's exposure to the risk of commodity price changes is reduced. Realized gains and losses are recognized monthly as adjustments to revenues in the same production period as the hedged production. Contracts are placed with entities that the Company believes have minimal credit risk. Contracts that do not or cease to qualify as a hedge are recorded at fair value, with changes in fair value recognized in income.
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair market value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statement of operations. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in earnings. All of the Company's derivative financial instruments subject to SFAS 133 have been designated as cash flow hedges.
Adoption of SFAS 133 at January 1, 2001 will result in the recognition of $10 million of derivative liabilities included in accrued liabilities in the Consolidated Balance Sheets and $6 million, net of taxes, of deferred hedging losses, included in accumulated other comprehensive income, as an effect of the change in accounting principle. In addition, the Company will also recognize a $261,000 increase in assets and a $162,000 increase in net income based on the market value of an option to put oil to a purchaser as an effect of the change in accounting principle. Amounts were determined as of January 1, 2001 based on quoted market values, our portfolio of derivative instruments, and the measurement of hedge effectiveness.
Income Taxes - ------------ Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes that enactment date.
Oil and Gas Producing Activities and Depreciation, Depletion and Amortization - -------------------------------------------------------------------------------- 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. During 2000 the Company recorded a net gain of $1.9 million from the sale of three 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. The Company recorded an asset impairment in 1999 of $13.2 million for unproved properties that the Company did not have current plans to develop and for a reserve reduction in the High Island 309 Fields. The Company also recorded an asset impairment in 1998 of $20.4 million, primarily due to lower oil and natural gas prices.
Environment Liabilities - ----------------------- The Company accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the time of the completion of the remedial feasibility study. These accruals are adjusted as further information
develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Capitalized Interest - -------------------- The Company capitalizes interest costs associated with unproved properties under development. Interest capitalized in 2000, 1999 and 1998 was $208,000, $544,000 and $936,000, respectively.
Property, Plant & Equipment - --------------------------- 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.
Amortization of Deferred Debt Costs - ----------------------------------- Costs incurred in debt financing transactions are amortized over the term of the debt.
Per Share Amounts - ----------------- The Company's basic earnings per share amounts have been computed based on the average number of common shares outstanding. Diluted weighted average shares outstanding amounts include the effect of the Company's outstanding stock options and warrants using the treasury stock method when dilutive. In part of 2000 and all of 1999 and 1998 the Company had options outstanding that were exercisable at prices above the market and are not included in per share calculations.
Stock Based Compensation - ------------------------ The Company accounts for stock-based compensation under the intrinsic value method. Under this method, the Company records no compensation expense for stock options granted when the exercise price of options granted is equal to or higher than the fair market value of the Company's common shares on the date of grant, see Note 10.
Consolidated Statements of Cash Flows - ------------------------------------- For purposes of reporting cash flows, the Company considers all cash investments with original maturities of three months or less to be cash equivalents.
Use of Estimates - ---------------- The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities in the financial statements, including the use of estimates for oil and gas reserve information and the valuation allowance for deferred income taxes. Actual results could differ from those estimates. Estimates related to oil and gas reserve information and the standardized measure are based on estimates provided by independent engineering firms. Changes in prices could significantly affect these estimates from year to year.
Reclassification - ---------------- Certain financial statement items have been reclassified to conform to the current year's presentation.
Accounts Receivable - Related Party - ----------------------------------- During 1998, the Company made a loan of $300,000 to an executive officer of the Company evidenced by a note and secured by a second mortgage on certain assets of the officer. On October 1, 2000 the officer resigned from all of his
positions with the Company. As part of the severance agreement, $300,000 of the amount due the employee was withheld by the Company and interest on the note stopped accruing. The $300,000 due the employee was used to repay this note in January 2001.
Quarterly Financial Data - ------------------------ The Company has 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 revenues were $63,000, $(744,000) and $(1,007,000) for the first, second and third quarters, respectively. The adjustments to depletion, depreciation and amortization were $(35,000), $(60,000) and $(293,000) for the first, second and third quarters, respectively. The adjustments to income before income taxes were $98,000, $(684,000) and $(714,000) for the first, second and third quarters, respectively. The adjustments to net income were $98,000, $(425,000) and $(444,000) for the first, second and third quarters, respectively.
Note 2 - ACQUISITIONS ------------
During 2000 the Company acquired an additional 33% working interest in the North Coward's Gully Field onshore in Louisiana from a non-operating owner for $1.1 million. The Company operates the Field and the acquisition gave the Company essentially 100% ownership of the Field. During 2000 the Company also purchased an additional 6.2% working interest in the Price Lake Field from several small non-operating partners for $0.9 million.
On May 26, 1998 the Company purchased a 100% working interest in East Breaks Blocks 165 and 209 and 75% working interest in High Island Block 587 from BP Exploration and Oil, Inc. ("BP"). The acquisition was accounted for using the purchase method. PANACO became the operator of all three blocks effective June 1, 1998. The Company acquired the properties for $19.6 million in cash. Included in the acquisition was the production platform, located in 863 feet of water in East Breaks Block 165. The Company also acquired 31.72 miles of 12" pipeline, with capacity of over 20,000 barrels of oil per day, which ties the production platform to the High Island Pipeline System, the major oil transportation system in the area. It also acquired 9.3 miles of 12 3/4" pipeline, which ties the production platform to the High Island Offshore System, the major gas transportation system in the area.
The following unaudited pro forma financial information assumes the BP acquisition had been consummated January 1, 1998. The pro forma financial information does not purport to be indicative of the results of the Company had this transaction occurred on the data assumed, nor is it necessarily indicative of the future results of the Company.
Note 3 - EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) ------------------------------------
In August 1994 the Company established an ESOP and Trust that covers substantially all employees. The Board of Directors can approve contributions, up to a maximum of 15% of eligible employees' gross wages. The Company incurred $330,000, $337,000 and $275,000 in costs for the years ended December 31, 2000, 1999 and 1998, respectively.
Note 4 - 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.
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 $3.5 million at December 31, 2000 and requires quarterly deposits of $250,000 until the account balance reaches $6.3 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 $4.4 million at December 31, 2000 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 December 31, 2000.
Note 5 - LAWSUIT RECOVERIES ------------------
During 2000 the Company settled two lawsuits it had filed, for which it received a total of $2.6 million. The first suit was settled with the insurance carrier of a third party that caused a fire at the West Delta Fields in 1996. The proceeds of $1.0 million were for the lost revenues during the period which the Company was not able to produce and sell its oil and natural gas. The second suit was the recovery of net revenues from a well based on an incorrect payout calculation by the operator, resulting in a settlement received by the Company totaling $1.6 million.
Note 6 - LONG-TERM DEBT --------------
(a) In October 1997 the Company issued $100 million of 10.625% Senior Notes due 2004. Interest is payable semi-annually April 1 and October 1 of each year. The net proceeds of the transaction were used to repay or prepay substantially all of the Company's outstanding indebtedness and for capital expenditures. The estimated fair value of these notes at December 31, 2000 was approximately $80 million based on quoted market prices. The notes are the general unsecured obligations of the Company and rank senior in right of payment to any subordinated obligations. The Senior Note indenture contains certain restrictive covenants that limit the ability of the Company and its subsidiaries to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, impose restrictions on the ability of a restricted subsidiary to pay dividends or make certain payments to the Company and its Restrictive Subsidiaries, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of the Company. In addition, under certain circumstances, the Company will be required to offer to purchase the Senior Notes, in whole or in part, at a purchase price equal to 100% of the
principal amount thereof plus accrued interest to the date of repurchase, with the proceeds of certain asset sales. The holders of the Senior Notes have acceleration rights, subject to certain grace periods, if the Company is in default under the credit facility.
(b) In October 1999 the Company put in place a new credit facility. The loan is a reducing revolver which will provide the Company with up to $60 million, depending on the borrowing base. The Company's borrowing base at December 31, 2000 was $60 million, with availability of $39.3 million, of which, $7.5 million was reserved by a letter of credit. The principal amount of the loan is due October 1, 2001, and may be extended for two additional six month periods, at the sole option of the Company. The Company is reviewing alternatives to extending this agreement, including replacing this Credit Facility with a bank facility. Interest on the loan is computed at Wells Fargo's prime rate plus .5% to 3.0%, depending on the percentage of the facility being used. The Credit Facility is collateralized by a first mortgage on the Company's properties. The loan agreement contains certain covenants including an EBITDA (as defined in the agreement) to interest expense ratio of at least 1.5 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.
(c) Represents a production payment obligation to a former lender which is paid with a portion of the revenues from certain wells. The production payment is a non-recourse loan related to the development of certain wells acquired upon acquisition. The agreement requires repayment of principal plus an amount sufficient to provide an internal rate of return of 18%.
Note 7 - EXTRAORDINARY ITEM-LOSS ON EARLY RETIREMENT OF DEBT ---------------------------------------------------
In 1999 the Company replaced its Credit Facility, see Note 6. In connection with the prepayment of the previous Credit Facility, the Company wrote off the remaining deferred financing costs associated with the previous facility.
Note 8 - SEVERANCE EXPENSE -----------------
Effective October 1, 2000 the Company's President and Chief Executive Officer resigned his position as an employee and director of the Company. Pursuant to an employment contract between the Company and the employee, the employee was entitled to receive two years of salary and benefits. The Company had the right to offset the amounts due the employee with principal and interest on a promissory note due the Company. The severance charge incurred in the third quarter of 2000 relates to the settlement of all amounts due the employee under the agreement, including the remaining salary and coverage under the Company's
various insurance policies. The employee was paid a portion of this amount due in October 2000 and the remaining amount due the employee will be offset against the principal amount of the promissory note in January 2001. Effective October 15, 2000, the Company's Chief Operating Officer took over as President of the Company.
Note 9 - COMMODITY HEDGE AGREEMENTS --------------------------
During 2000, 1999 and 1998, the Company hedged a portion of its oil and natural gas production in accordance with its hedging policy and as a requirement of its credit facilities. During these periods, the hedges entered into by the Company were either swaps or cost free collars. The swaps were agreements to sell a
certain quantity of oil or natural gas in the future at a predetermined price. Cost free collars ensured that the Company would receive a predetermined range of prices for its products. The following is a summary of those years' hedging activities.
For 2001, the Company has 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 averages $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 the Company the price difference for the total MMbtu hedged for that month. If the swap prices are less than the settlement prices, the Company will pay the counterparty the price difference for the total MMbtu hedged for that month.
The Company has 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 Company paid $365,000 for the put option, of which $273,000 remained unamortized at December 31, 2000. The cost of the put option is being amortized over the period the hedged item is produced. At December 31, 2000 and 1999 the fair value of the Company's hedges was losses of $10.6 million and $1.8 million, respectively.
The fair value of the Company's commodity hedging instruments is the estimated amount the Company 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. Certain of the Company's commodity hedging
instruments, primarily swaps and options, are off balance sheet transactions and, accordingly, other than an unamortized premium of $273,000 on put options, no respective carrying amounts for these instruments were included in the accompanying consolidated balance sheets as of December 31, 2000 and 1999. The Company accounts for the gains and losses in oil and natural gas revenue in the month of hedged production.
Note 10 - STOCK OPTIONS -------------
During 1992, the shareholders approved a long-term incentive plan allowing the Company to grant incentive and non-statutory stock options, performance units, restricted stock awards and stock appreciation rights to key employees, directors, and certain consultants and advisors of the Company up to a maximum of 20% of the total number of shares outstanding.
SFAS No. 123, "Accounting for Stock-based Compensation" defines a fair value method of accounting for an employee stock option or similar equity instrument. The Company has elected to account for its stock options under the intrinsic value method, whereby, no compensation expense is recognized for stock options granted when the exercise price is equal to or greater than the market value of the Company's common stock on the date of an option's grant.
On June 18, 1997, 1.2 million options at $4.45 per share were issued to certain employees under the provisions of the Company's long-term incentive plan, which expired June 20, 2000.
During 2000 the Company issued 500,000 options at $1.92 per share, the market closing price on the grant date of August 16, 2000, to officers of the Company. The options vest ratably over five years and expire six years from the grant date.
The fair value of each option granted in 2000 was estimated at the date of grant using the Black-Scholes Modified American Option Pricing Model with the following assumptions:
If compensation expense for the Company's stock option plans had been recorded using the Black-Scholes fair value method and the assumptions described above, the Companys unaudited net income (loss) and earnings (loss) per share for 2000, 1999 and 1998 would have been as shown below:
Note 11 - MAJOR CUSTOMERS ---------------
During 2000, the purchaser of a majority of the Company's oil production accounted for 23% of total oil and natural gas sales and the purchaser of a majority of the Company's natural gas production accounted for 39% of total oil and natural gas sales. In 1999, the purchaser of a majority of the Company's oil production accounted for 37% of total oil and natural gas sales, while the purchaser for a majority of the Company's gas production accounted for 39% of total oil and natural gas sales. A purchaser of natural gas production in 1998 accounted for 42% of total oil and natural gas sales.
Note 12 - INCOME TAXES ------------
At December 31, 2000, the Company had net operating loss carry forwards for federal income tax purposes of approximately $100.4 million which are available to offset future federal taxable income through 2020. The Company's timing of its utilization of a portion of its net operating loss carry forwards may be limited on an annual basis in the future due to its issuance of common shares, the purchase of common stock of an entity acquired in 1997 and other changes in stock ownership.
Significant components of the Company's deferred tax assets (liabilities) as of December 31 are as follows:
At December 31, 2000 the Company determined that it is more likely than not the deferred tax assets will be realized and the valuation allowance was decreased by $29 million. This determination was based on the Company's estimates of future net income sufficient to utilize the entire net operating loss carryforwards.
Total income taxes were different than the amounts computed by applying the statutory income tax rate to income before income taxes. The sources of these differences are as follows:
Note 13 - 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 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.
In August 2000, an action was filed against the Company by Coastal Oil and Gas Corporation (now El Paso Corporation) for nonpayment of joint interest billing invoices. The suit seeks to recover unpaid costs from a well drilled on a property operated by El Paso. PANACO counter sued alleging, among other things, gross misconduct and negligence in drilling the well. The case is still in discovery and it is not possible to evaluate the likelihood of an unfavorable outcome or to estimate the amount or range of potential loss in addition to what has already been accrued.
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.
The Company has commitments under an operating lease agreement for office space through November 30, 2004. At December 31, 2000, the future minimum rental payments due under the lease are as follows:
2001 $ 432,000 2002 459,000 2003 459,000 2004 421,000 ----------- Total $ 1,771,000 ===========
Note 14-SUBSEQUENT EVENTS -----------------
During the first quarter of 2001 the Company will recognize approximately $3.5 million of exploratory dry hole expense for the East Breaks 110 A-4 well. The well was spud on January 30, 2001 and reached total depth in early March 2001 The well encountered the objective sand, however, it did not contain a commercial amount of hydrocarbons.
Note 15 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES -------------------------------------------------------------------- (UNAUDITED) -----------
The following table reflects the costs incurred in oil and gas property activities for each of the three years ended December 31:
Quantities of Oil and Gas Reserves - ---------------------------------- The estimates of proved reserve quantities at December 31, 2000, are based upon reports of third party petroleum engineers (Ryder Scott Company, Netherland, Sewell & Associates, Inc., W.D. Von Gonten & Co. and McCune Engineering, P.E.) and do not purport to reflect realizable values or fair market values of reserves. It should be emphasized that reserve estimates are inherently imprecise and accordingly, these estimates are expected to change as future information becomes available. These are estimates only and should not be construed as exact amounts. All reserves are located in the United States.
Proved reserves are estimated reserves of natural gas and crude oil and condensate that 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 those expected to be recovered through existing wells, equipment and operating methods.
Standardized Measure of Discounted Future Net Cash Flows - -------------------------------------------------------- Future cash inflows are computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the year-end estimated future production of proved oil and gas reserves. The base prices used for the Pretax PV-10 calculation were public market prices on December 31 and adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for
the quality of the oil and natural gas and for transportation to the appropriate location. The average prices in the Pretax PV-10 value at December 31, 2000 were $9.65 per Mcf of natural gas and $26.60 per barrel of oil. For production in February 2001, the Company estimates that its realized oil and natural gas prices, including the impact of hedges, will average $30.59 per Bbl and $6.87 per Mcf, respectively. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.
The accompanying table reflects the standardized measure of discounted future cash flows relating to proved oil and gas reserves as of the three years ended December 31: