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. 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 can not assure you that the actual results of our Company 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. Through December 31, 1999 we had two 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 33. 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 surroundings the Gulf, which we collectively refer to as the Gulf Coast Region. We acquired our first property in the Gulf of Mexico in 1991, and since that time, have acquired other properties in the Gulf Coast Region and Gulf of Mexico in every year since 1994. We have grown not only through acquisitions in each of those years but also by further developing the properties we have acquired. We acquired those 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 from the Goldking Companies in 1997. We are in the business of selling oil and natural gas produced on properties we lease to third party purchasers. We obtain the reserves of crude oil and natural gas by a combination of buying them from others, drilling developmental wells on acquired properties and drilling exploratory wells in new locations.
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 previous property acquisitions from BP, Amoco, Goldking and others, which are described below, we have an inventory of development and exploration projects that provide additional reserve potential. The key elements of the Company's 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, significant 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 ownerships 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. Based on these factors, we are usually asked to bid on significant producing property sales in the Gulf Coast Region. Below are highlights of some of our more significant acquisitions.
Price Lake Field
We acquired the Price Lake Field in April 1998 as a potential development field in addition to exploration prospects which 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 spudded 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. This well began production in September 1999 once we completed production facilities. We own 56.25% of this well until it reaches payout, after which we will own 51.2% and we will own 51.2% of the subsequent wells in this Field. The second well in the Field, the Sturlese #3 was spudded in November 1999, and was completed as a successful developmental well in March 2000. The Sturlese #3 was drilled to a total depth of 17,000' and encountered an estimated 98' of productive sand in two zones.
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. The largest oil and gas lease we acquired from Goldking was the Umbrella Point Field, which we have successfully developed since the acquisition. In January 1998 we completed a developmental well that began production in February 1998, the State Lease #74-10 well. This well produced as much as 27 MMcf of natural gas and 260 barrels of condensate per day. In December 1999, we completed a workover on this well and brought its production back up to 19 MMcf of natural gas and 176 barrels of condensate per day. We recently completed another successful development well in this Field in January 2000. The State tract #87-12 was spud on December 25, 1999 and drilled to a total depth of 12,000'. The well reached total depth in January 2000 and encountered 85' of net productive intervals in four different zones. The well flowed 10,100 Mcf and 337 barrels of condensate during a 24 hour test and has a calculated open flow rate of 38,100 Mcf per day.
Amoco Acquisition
In October 1996 we acquired interests in six offshore fields from Amoco Production Company, now BP Amoco. We paid Amoco $32 million in cash and issued them 2 million shares of common stock in consideration for the properties. Following is a summary of the interests acquired:
All of the properties we acquired from Amoco are operated by third parties, which are Unocal, Texaco, Coastal Oil and Gas and Newfield Exploration. We acquired an additional 25% interest in West Cameron 144 in 1998.
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 109/110. 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 have identified several developmental and exploratory drilling locations on blocks 109 and 110 and we have allocated a relatively significant part of our 2000 capital budget to developmental work on these blocks.
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, 1999, 40% 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 23 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 coast line 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. We currently receive approximately $175,000 per month from other lease operators in the East Breaks area alone, which we account for as a reduction of lease operating expense.
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. In 1998 and 1999 we 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 Price Lake wells and Umbrella Point 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 over 35% 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, which led to a new well completed in January 2000.
Significant Operating Control
We operate 78% 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 64 productive offshore wells and own all of the working interests in a majority of those wells. Our 50 remaining productive offshore wells are operated by third party operators, including Unocal Corporation, Coastal Oil & Gas Corp., Newfield Exploration, Texaco, Anadarko Petroleum Corporation and Burlington. We also operate 25 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 Geoscience 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.
3-D Seismic and CAEX technology have been in existence since the mid 1970s; however, it was not until the late 1980s, with the development of improved data acquisition equipment and techniques capable of gathering significant amounts of data through a large number of channels and the availability of improved computer technology at reasonable costs, that the method became economically available to smaller companies such as ours. Prior to that, it was the exclusive province of large multinational oil companies. We own our own seismic interpretation workstations and data processing equipment and utilize the services of outside firms to process and interpret seismic data.
With the BP Acquisition, we acquired 129 square miles of 3-D Seismic. We have used the seismic for workover and recompletion activity to date, and we plan further development on the fields acquired with this 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 Vastar. Oxy, Conoco, Texaco and Vastar each have a 25% call (exclusive right to purchase) on the oil production from the West Delta Fields at their average posted price for each month. Amoco has a call on all of the oil production from our properties acquired from Amoco at their posted prices. If we have a bona fide offer from a crude oil purchaser at a higher price than Amoco's posted price, then Amoco must match that price or release the call. Oil from the Zapata Properties is currently being sold to Unocal and Amoco, 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 37% of our total revenues in 1999. 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 Columbia Energy Services Corporation (now Enron North America Corp.) accounted for 39% of our total revenues in 1999. 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 $21 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 Fields
The former owner of these Fields requires a $4.1 million surety bond, based on their estimate of the P&A Liability of the Fields. As security for the $4.1 million bond, we have provided a cash escrow account to the underwriter of the bond. The balance of this escrow account was $1.1 million at December 31, 1999, and was fully funded in November 1997 in accordance with the terms of the escrow agreement. We also provide the MMS a $50,000 surety bond for the plugging of two wells in federal blocks of these Fields.
East Breaks 165 Fields
We provide the MMS with a $10.9 million surety bond based on their estimated P&A Liability for these Fields. As security for the underwriter of this bond we have established a cash escrow account. The balance in this escrow
account totaled $2.3 million at December 31, 1999 and requires quarterly deposits of $250,000 until the balance in the escrow account reaches $6.5 million. The underwriter also provides the former owner of these Fields with a $6.5 million security bond based on the same escrow account used for the bond provided to the MMS.
East Breaks 109 Fields
We provide the MMS with a $5.8 million surety bond for these Fields. As security for the underwriter of these bonds, we have established an escrow account, the balance of which was $1.8 million at December 31, 1999. The escrow agreement requires quarterly deposits of $250,000 until the balance of the account reaches $5.4 million.
Amoco Properties
The properties we acquired from Amoco in 1996 are all operated by third parties and as such, the MMS does not require non-operators to provide evidence of the ability to P&A the properties. However, Amoco Production Company requires us to fund an escrow account to provide them with this evidence. The escrow agreement requires that we deposit 10% of the cash flows from the Fields, net of capital expenditures for their lives. At December 31, 1999 the balance in this escrow account was $315,000.
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 $50 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 $50 million for wells in federal offshore waters. The amounts are proportionately reduced if we own less than 100% of the well. We also maintain $112 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 Cereberus 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 an additional year at our option. 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 $36.7 million outstanding at December 31, 1999. We will continue to use this Facility in 2000 to fund part of our $30 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, 1999 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.
The Indenture contains certain restrictive covenants that limit us 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 and incur liens. The Indenture also restricts us from merging or consolidating with any other person or sell, assign, transfer, lease, convey or otherwise dispose 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, 1999 with the covenants contained in the Indenture.
Common and Preferred Stock
On December 31, 1999 we had issued and outstanding 23,986,521 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 on 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. At various times during recent years, worldwide oil production capacity and natural gas production capacity in the United States exceeded demand and resulted in a substantial decline in the price of oil and natural gas in the United States during those periods.
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 our 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 Amoco Properties, will generally sell their natural gas for as much as $.12 below the index price.
Environmental and Other Regulation. Our business is affected by governmental laws and regulations, including price control, energy, environmental, conservation, tax and other laws and regulations relating to the petroleum industry. 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 have 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 Mineral 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 34 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
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 acquires 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 have incurred significant losses in 1999 and 1998 and are significantly leveraged. Our long-term debt balance at December 31, 1999 was $138.9 million and our stockholders' deficit was ($26.9 million). A large part of our losses in each year 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 can not 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 prices 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, 1999 and use costs for operating and capital expenditures in effect at that same time. The average prices used in calculating the Pretax PV-10 value at December 31, 1999 were $2.43 per Mcf of natural gas and $24.99 per barrel of oil. These prices are adjusted on a property by property basis for the quality of the oil and natural gas and for transportation to the appropriate location. These assumptions are then used to calculate a future cash flow stream, that is discounted at a rate of 10%.
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 Acquisition and Amoco Acquisition. 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 our 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, 1999, one natural gas purchaser accounted for approximately 39% of our revenues. Also, in 1999 we consolidated a majority of our oil production to one oil purchaser, who accounted for 37% of our total revenues in 1999. 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.
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 counter party all or a portion of this difference multiplied by the quantity hedged, regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. 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 2000, our hedges are composed primarily of floors for both oil and natural gas. These floors set a minimum price that we will receive on a certain amount of our daily production, and allow us to receive all of the benefit of prices in excess of these minimums. You can find more information regarding our hedging activity beginning on Page 29.
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, 1999, our total estimated abandonment costs, net of $5.6 million already in escrow, were approximately $15.7 million. We account for those future liabilities by accruing for them in our depreciation, depletion and amortization expense over the lines 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 can not 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 us. See "Business - Competition, Markets Seasonality and Environmental and Other Regulation."
Item 2.
Item 2. Properties.
At December 31, 1999 our Proved Reserves totaled 135 Bcfe and had a Pretax PV-10 value of $181.3 million. Approximately 60% of these reserves are classified as Proved Developed Reserves and approximately 61% 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 43 producing oil wells and 98 producing natural gas wells. We also own interests in 23 federal blocks in the Gulf of Mexico and 9 state water blocks and we operate 66% of the 114 producing offshore wells, based upon the Pretax PV-10 value as of December 31, 1999. Our non-operated offshore properties are operated by large independents and major oil companies, including Unocal, Newfield, Texaco, Coastal, Anadarko and Burlington. Our 27 producing onshore wells account for 18% of our total Pretax PV-10 value as of December 31, 1999. We operate 52% of our onshore wells, based upon such Pretax PV-10 value. We also own interests in 23 offshore production platforms and 109 miles of offshore oil and natural gas pipelines with diameters of 10" or larger.
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, 1999. These properties represent 80% of the aggregate Pretax PV-10 value of our Proved Reserves.
East Breaks 165
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 5 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 18,600 Mcf of natural gas and 176 barrels of oil per day. We own an 80% working interest in the well. The remaining 20% is owned by Peoples Energy Production.
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. The field is operated by Unocal 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. The facility also receives processing fees from Vastar Corp. from to 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, Reading and Bates and Santa Fe Energy 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.
West Delta
These properties consist of 13,565 acres in Blocks 52 through 56 and Block 58 in the West Delta Area, offshore Louisiana. The West Delta Fields were acquired from Conoco, Inc., Atlantic Richfield Company (now Vastar Resources, Inc.), OXY USA, Inc. and Texaco Exploration and Production, Inc. in May 1991. These Fields were shut in from December 6, 1998 through May 1999 due to a third party pipeline being shut in. We are the operator and generally own 100% of the working interest in these wells. Presently, the properties have 36 wells, which produce from depths ranging from 1,200' to 16,800'. Because of the existing surface structures and production equipment, additional wells can be added on the properties with lower completion costs.
The field is characterized by multiple reservoirs with significant workover and recompletion potential. Proved producing reserves are based on an established consistent production history. The behind pipe reserves are generally uphole recompletions with reserves based on volumetric estimates. In February 2000 we completed a new well in Block 54, the #30 well. This new well was drilled to 7500' and encountered and estimated 110' of producing formation. The reserves in this well are primarily natural gas, adding approximately 6 Bcf of net reserves.
We have allowed third party operators to drill several wells in Block 58 through farmout agreements. In return, we receive either a working interest or overriding royalty interest in their wells at our option. We also process their oil and some of their natural gas for a fee. In February 2000, Basin Exploration completed a well that was farmed out from us in Block 58. Their well was drilled to a subsea true vertical depth of 11,300' and logged in excess of 150' of net oil and gas/condensate pay in multiple Miocene-aged sands. We retained a 10% overriding royalty interest before payout with the option of either escalating the overriding royalty interest to 12.5%, or converting to a 30% working interest. In addition, not withstanding the forgoing terms, in the event the completion is certain sands, our retained overriding royalty interest will triple for the period of time in which our booked reserves are being produced.
During 1994, we farmed out the deep rights (below 11,300') to an 1,875 acre parcel in Block 58 and sold "C" Platform to Energy Development Corporation which drilled a successful well to 16,800'. Production commenced in April 1995. We have a 15% overriding royalty interest in that acreage. The well is currently producing 7,000 Mcf per day and 427 Bbls of condensate per day. Energy Development Corporation was subsequently acquired by Samedan Oil Corporation.
In January 2000 we received a favorable judgement in a lawsuit we had filed with our insurance carrier in 1996 related to the West Delta Fields. Our part of the lawsuit was primarily for lost revenues in 1996 from a fire at Tank Battery #3 which was caused by a third party service company. The judgement against the service companies' insurance carrier was $1.1 million. Currently, we can not estimate when we will recognize and receive the proceeds from this judgement.
Price Lake
For more information regarding the Price Lake Field, see "Business Strategy-Price Lake Field."
Oil and Gas Information
Our reserve estimates are prepared by third party engineering firms who prepare their reports based on information we provide them. 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 77% of the Pretax PV-10 of our reserve estimates. Our proved oil reserves totaled 8.7 million barrels at December 31, 1999 compared to 7.5 million barrels at December 31, 1998. Our proved natural gas reserves totaled 82.8 Bcf at December 31, 1999 as compared to 81.2 Bcf at December 31, 1998. The Pretax PV-10 value of these reserves totaled $181 million
at December 31, 1999 compared to $95 million at December 31, 1998. Despite liquidity and capital resource we replaced 149% of our 1999 production which totaled 18.1 Bcf equivalent. 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.
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, 1997, 1998 and 1999.
- - ---------------------- (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. (c) Several projects scheduled for 1999 were delayed due to capital constraints.
Producing Wells(a)
The following table presents the number of producing oil and natural gas wells, as of December 31, 1999, attributable to our properties.
- - ---------------------- (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.
- - ----------------------
(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, 1999. 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 us 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 us and NEG, NEG is required to indemnify us from any damages attributable to NEG's operations on the property after the sale. However, NEG is in Chapter 11 bankruptcy proceedings, and so any action by us to assert our indemnity rights against NEG is currently stayed. Our Counsel has prepared and may file a motion to lift the stay so that we may assert its indemnification rights against NEG. But even if we are successful in proving our right to indemnity, NEG's ability to satisfy the judgement is questionable because of the bankruptcy.
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 may have insurance coverage for the claims asserted in the petition, and have notified all insurance carriers that might provide coverage under our policies. 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.
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, 2000 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 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 nonassessable.
Warrants and Options We also have outstanding options to acquire 1,150,000 Common Shares at a price of $4.45 per share, expiring June 20, 2000. These options are all held by current and former 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 1999, our Common Shares have been traded on the OTC Bulletin Board under the symbol "PANA." Prior to that, our Common Shares were traded on NASDAQ under the same symbol. 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 20, 2000, the last sale price of the Common Shares was $.90 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 and the Senior Notes contain restrictions 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, the 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 $.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 special meetings of shareholders may be called only by the Board of Directors, 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.
Item 6.
Item 6. Selected Financial Data.
The following historical data is derived from Consolidated 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 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. You should also understand that due to numerous acquisitions, the results of operations for the periods presented may not be necessarily comparative. See "Business Strategy - Strategic Acquisitions and Mergers," beginning on Page 2 for further discussion of our acquisitions.
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 can not 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.
Year 2000 Issue
To address this issue, we established a Year 2000 ("Y2K") Compliance Project Team consisting of representatives from Information Technology, Finance and Operations. The Team designed a schedule to identify information technology ("IT") and non-IT assets requiring readiness upgrades, and a timetable for performance and testing of the affected systems. In addition, the Team contacted third-party suppliers and customers to ascertain their state of readiness and developed contingency plans as necessary. We passed the milestone of the turn of the century with no major issues pertaining to the date change, and we do not anticipate any in the future. The costs to be prepared for Y2K were immaterial to our results of operations.
Liquidity and Capital Resources
In implementing our business strategy of increasing our reserve base and cash flows from operations, we have reinvested our cash flows from operations into capital expenditures. Our secondary source of capital expenditure resources is our Credit Facility, which is also used for working capital support and general corporate purposes. During 1999, our cash flows from operations totaled $8 million and our borrowings under the Credit Facility increased $23 million for our $26 million in capital expenditures. This left our balance under the Credit Facility at $36.7 million, with availability of $16 million at December 31, 1999. During 1999 we sold several of our non-core properties for $1 million. The properties we sold are non-operated, onshore and have relatively small values. By selling these properties we also became more efficient as we can focus our resources on our more significant properties. We plan to continuing reviewing all of our remaining similar properties for potential sale.
For the year 2000, our Board of Directors has approved a $30 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.
On October 9, 1997, we issued $100 million principal amount of 10 5/8% Senior Notes due October 1, 2004. Interest on the Notes is payable semi-annually in arrears on each April 1 and October 1, commencing April 1, 1998. 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.
On March 5, 1997, we completed an offering of 8,403,305 common shares at $4.00 per share, $3.728 net of the underwriter's commission. The offering consisted of 6,000,000 newly issued shares and 2,403,305 shares sold by shareholders, primarily Amoco Production Company (2,000,000 shares) and lenders advised by Kayne, Anderson Investment Management, Inc. (373,305 shares). Our net proceeds of $22 million from the offering were used to prepay $13.5 million of 12% subordinated debt and the remainder was used to reduce borrowings under the existing Credit Facility.
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, and includes Foothill Partners, L.P. and Ableco Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility is a $60 million line, with a term of two years, and extendable for an additional year at our option. 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 $36.7 million outstanding at December 31, 1999. We will continue to use this Facility in 2000 to fund part of our $30 million capital budget.
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, 1999 and anticipate compliance throughout the term of the loan.
At December 31, 1999, 81% of our total assets were represented by oil and natural gas properties, pipelines and equipment, net of depreciation, depletion and amortization.
Results of Operations
Improvements in natural gas and oil prices during 1999 helped support our revenues, while a decrease in natural gas production led to an overall decline in revenues. Impairments of our unproved properties and on the High Island 309 Fields were contributing factors to our net loss of $35 million.
During 1999, we hedged a total of 540,000 barrels of oil at an average NYMEX equivalent flow price of $15.34 per barrel. These hedges were primarily cost free collars, with 245,000 barrels having a floor of $15.00 and a cap of $19.12 per barrel and 214,000 barrels having a floor of $15.00 and a cap of $17.50 per barrel. We also hedged a total of 8.8 Bcf of natural gas at an average NYMEX equivalent price of $2.14 per MMbtu.
The decrease in natural gas production in 1999 was primarily due to three fields, the West Delta Fields, the High Island 309 Fields and the Umbrella Point Field. High Island 309 production decreased 4.5 Bcf from 1998 due to natural production declines, which was further complicated by compressor problems on both the High Island 309 and 310 platforms. West Delta production decreased 1.1 Bcf due to shut-ins earlier in 1999 while the pipeline owned by Tennessee Gas Pipeline was repaired along with the natural production decline of the wells. Also, production from the Umbrella Point Field was accelerated in 1998 with the successful completion of the SL 74 #10 well in January 1998. This well produced as much as 27 MMcf per day in 1998 and has reduced since then. The change in production from 1998 was a reduction of 2.4 Bcf. These decreases were somewhat offset by an addition of 1.4 Bcf during 1999 from the East Breaks 165 Fields. The Fields were acquired in May 1998 and produced for a full year in 1999.
The significant factor in our increased oil production was the acquisition of the East Breaks 165 Field in May 1998, which is primarily an oil field.
"Lease operating expense" decreased in 1999 due to several factors. We sold a group of non-core properties in 1999, which lowered these expenses. We also implemented some cost reduction programs on several of the offshore properties that we operate. A large percentage of the expenses associated with operating oil and natural gas leases are fixed. Our decrease in production in 1999 accounted for the increase in expenses per unit, or Mcf equivalent ("Mcfe") of production. We can significantly increase production on our properties without increasing these operating expenses.
"Depreciation, depletion and amortization expense" decreased proportionately with the decrease in total production. We also realized a lower cost per unit of production in 1999, from $1.60 per Mcfe in 1998 to $1.46 in 1999.
"General and administrative expense" was $560,000 lower in 1999 primarily due to a larger increase in our bad debt expense in 1998 versus 1999. Normal, recurring general and administrative expenses have remained relatively flat.
"Exploratory dry hole expense" and "Geological and Geophysical expense" are both representative of our decrease in exploratory projects in 1999 compared to 1998. During 2000, we plan to continue some participation in exploratory projects, but we also plan to continue to do so at a modest level and percentage of our capital budget.
"Impairment of oil and gas properties" in 1999 related to two property groups. We impaired most of our unproved properties in order to reflect the lack of planned drilling activity on those properties with associated unproved costs. We have an extensive drilling program for 2000, however, the projects identified do not include those properties that were impaired. We also impaired the carrying value of our High Island 309 Fields due to unsuccessful workovers completed during the fourth quarter. These unsuccessful workovers resulted in reserve reductions of approximately 5 Bcf.
"Interest expense (net)" increased in 1999 as we increased our borrowing levels over 1998. In early 1998 and throughout most that year, our Credit Facility borrowing was relatively low, as we had cash available for capital expenditures from our Senior Note Offering. We increased the Credit Facility balance during 1999 to $36.7 million at December 31, 1999 compared to the balance at December 31, 1998 of $13.5 million.
"Extraordinary item-loss on early retirement of debt" relates to a new Credit Facility we put in place in September 1999 and the write off of costs associated with the previous facility, that was prepaid.
The decreases in oil and natural gas prices we realized in 1998, in combination with other key factors led to the significant loss in 1998. Price declines led to a $20.4 million impairment of our oil and gas properties based on estimated recoverability of the book value of those assets. A substantial increase in non drilling exploration expenses and exploratory dry hole expense, along with the closing of our Kansas City, Missouri office and the related severance expense also contributed to the net loss for the year.
The BP Acquisition in May 1998, the Goldking Acquisition in July 1997 and successful developmental drilling programs in 1997 and 1998 were the primary factors in our increased natural gas production during 1998. The Goldking Acquisition and several wells completed on those properties during 1998 accounted for an increase of 4,844,000 Mcf. Successful developmental drilling in the High Island 309 and 310 Fields accounted for an increase in production of 2,537,000 Mcf, while a successful developmental well and the acquisition of a co-owner's working interest in the West Cameron 144 Field accounted for an increase of 600,000 Mcf. The primary factors in our increased oil production in 1998 were the acquisition of the East Breaks 165 Field in May 1998 and a successful developmental well completed in the Umbrella Point Field in January 1998.
During 1998 we had natural gas hedged in quantities ranging from 10,000 to 50,000 MMbtu per day in each month for a total of 11,980,000 MMbtu, at pipeline prices averaging approximately $2.05 per MMbtu, for a NYMEX equivalent of approximately $2.20 per MMbtu.
Our 1998 oil hedge program improved the average net oil price we realized by $2.27 per barrel. We hedged oil prices on 1,268 Bbls of oil for each day in 1998 at an average swap price of $19.06 per Bbl, with a 40% participation above $19.28 on 500 of the 1,268 Bbls.
"Lease operating expense" increased $7.0 million primarily due to the BP and Goldking Acquisitions, these expenses increased to $0.78 per Mcfe, from $0.77 per Mcfe in 1997.
"Depletion, depreciation and amortization" increased $18.6 million primarily due to the increase in 1998 production as discussed above. The amount per Mcfe also increased from $1.30 in 1997 to $1.60 in 1998. The increase in the amount per Mcfe was in part due to the decline in reserve value of several small, non-operated oil properties. The magnitude of depletion is also impacted by the relatively short lives of our proved reserves. At December 31, 1998, the average life of our proved reserves was approximately five and one-half years.
"General and administrative expense" increased $2.7 million in 1998 due to acquisitions we made in July 1997, April 1998 and May 1998. We also increased an allowance for doubtful accounts by $1 million in 1998 which also accounted for a large percentage of the increase.
"Production and ad valorem taxes" increased $630,000 in 1998, to 3% of oil and natural gas sales, from 2% in 1997. The increase is due to production from properties subject to state taxes that we acquired in July 1997.
"Exploratory dry hole expense" reflects our increased exploratory activities in 1998. Of the 19 wells we drilled or participated in during 1998, six of the exploratory wells were not commercially productive. The wells were operated by third parties and we owned working interests ranging from 10 to 20%.
"Geological and geophysical expense" during 1998 resulted from our non-drilling exploratory activities.
"Impairment of oil and gas properties" represents an impairment of the book value of our proved oil and gas properties based on estimated future net cash flows from those properties. The impairment was primarily due to much lower estimates of oil and natural gas prices at December 31, 1998. The impairment tests were based upon future cash flows using an initial price of $11.50 per barrel of oil and $1.90 per MMbtu of natural gas, each moderately escalated thereafter. Costs and expenses were also escalated at 3%.
"Office consolidation and severance expense" was a non-recurring charge for the costs associated with closing our Kansas City, Missouri office. The charge includes costs for the relocation of personnel and equipment to its Houston, Texas office and severance costs for several former employees.
"Interest expense (net)" increased $5.8 million in 1998 primarily due to increased borrowing levels. The increase in borrowing is due to our Senior Note offering completed in October 1997. The increase is somewhat offset by a reduced interest rate on a majority of long term debt. In connection with the offering, we prepaid or repaid long term debt, a significant amount of which had rates in excess of the 10 5/8% rate on the Notes. This included amounts borrowed in connection with the Amoco Acquisition in October 1996 and debt assumed in connection with the Goldking Acquisition in July 1997.
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 or to take advantage of unusual strength in the market.
During 1997, 1998 and 1999, we hedged a portion of our oil and natural gas production in accordance with our hedging policy and as a requirement of our Credit Facilities. During these periods, the hedges we entered into 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 we would receive a predetermined range of prices for our products. Following is a summary of our historical hedging activity.
For the year 2000, the Company has purchased options to put oil and natural gas produced to a purchaser at an agreed upon price. The natural gas put option is for 10,000 MMbtu per day at a NYMEX price of $2.04 per MMbtu. The Company paid $366,000 for the put option which will be amortized over the period the hedged item is produced, fiscal year 2000. The oil put option is for 1,000 barrels of oil per day beginning March 1 and continuing through December 31 at a NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and will also be amortized over the period the hedge item is produced, fiscal year 2000. The Company also has a small swap in place on an average of 232 barrels of oil for each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its hedges was a loss of $800,000. The fair values of its hedges on December 31, 1998 and 1997 was a gain of $1.8 million and a loss of $61,000, respectively.
The fair value of our commodity hedging instruments is the estimated amount 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 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 consolidated balance sheets as of December 31, 1999 and 1998. A 10% change in commodity prices would not have a material change in the fair value of our hedging instruments.
These hedge agreements provide for the counterparty to make payments to us to the extent the market prices (as determined in accordance with the agreement) are less than the fixed prices for the notional amount hedged and to make payments to the counterparty to the extent market prices are greater than the fixed prices.
At December 31, 1998 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, 1999, was $70 million. We also had $36.7 million outstanding under our Credit Facility at December 31, 1999. The Credit Facility is a floating rate facility, with a fair value of $36.7 million. We do not have any interest rate hedge agreements at December 31, 1999.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The financial statements are included herein beginning at. The table of contents at the front of the financial statements lists the financial statements and schedules included therein.
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, 1999. 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, 1999. 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, 1999. 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, 1999. 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. No reports on Form 8-K were filed during the last quarter of the period covered by this report:
(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.
10.23**** Employment contract between the Company and Larry M. Wright.
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.
27**** Financial Data Schedule.
*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, 1999, 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, 1999, 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\ Larry M. Wright March 27, 2000 ----------------------- -------------- Larry M. Wright, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
By: \s\ Larry M. Wright March 27, 2000 ------------------------ -------------- Larry M. Wright, Chief Executive Officer and Director
By: \s\ Todd R. Bart March 27, 2000 ------------------------ -------------- Todd R. Bart Chief Financial Officer & Principal Accounting Officer
By: \s\ Harold First March 27, 2000 ------------------------ -------------- Harold First, Director
By: \s\ A. Theodore Stautberg March 27, 2000 ------------------------ -------------- A. Theodore Stautberg, Director
By: \s\ James B. Kreamer March 27, 2000 ------------------------ -------------- James B. Kreamer, Director
By: \s\ Richard Lampen March 27, 2000 ------------------------ -------------- Richard Lampen, Director
By: ------------------------ Felix Pardo, Director
By: ------------------------ Stanley Nortman, Director
By: ------------------------ Mark C. Barrett, Director
By: ------------------------ Donald Chesser, Director
PANACO, Inc.
PANACO, Inc. - AUDITED FINANCIAL STATEMENTS Page Number
Independent Auditors' Report
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1999 and 1998
Consolidated Statements of Operations for the Years Ended December 31, 1999, 1998 and 1997
Consolidated Statements of Changes in Stockholders' Equity (Deficit) for the Years Ended December 31, 1999, 1998 and 1997
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997
Notes to Consolidated Financial Statements for the Years Ended December 31, 1999, 1998 and 1997
Independent Auditors' Report
The Board of Directors and Shareholders PANACO, Inc.:
We have audited the accompanying consolidated balance sheets of PANACO, Inc. and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of operations, changes in stockholders' equity (deficit), and cash flows for the years then ended. 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 audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides 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. and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
KPMG LLP Houston, Texas March 20, 2000
Report of Independent Public Accountants
To the Stockholders and Board of Directors of PANACO, Inc.:
We have audited the accompanying consolidated statements of operations, changes in stockholders' equity (deficit) and cash flows of PANACO, INC. (a Delaware Corporation) and Subsidiaries for the year ended December 31, 1997. The financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above presents fairly, in all material respects, the results of operations and cash flows of PANACO, Inc. and Subsidiaries for the year ended December 31, 1997, in conformity with generally accepted accounting principles.
Arthur Andersen LLP Kansas City, Missouri April 7, 1998
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, 1997, 1998 AND 1999
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, 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.
For the year ended December 31, 1997: - - -------------------------------------
The Company issued 10,649 common shares as director and employee bonuses and contributed 24,332 shares to the ESOP. The Company also issued 3,238,930 common shares, $6.0 million in notes, assumed $19.2 million in debt and net liabilities and recorded a $3.1 million deferred tax liability in connection with an acquisition.
The Company issued 2,060,606 warrants to acquire common shares to a former lender in connection with debt which was prepaid in 1997.
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, 1999, 1998, AND 1997
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business - - ------------------ PANACO, Inc. and subsidiaries (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. It operates in an environment with many financial and operating risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the highly competitive nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent upon obtaining the necessary capital through operating cash flow, borrowings or the issuance of additional equity. The Company's subsidiaries are consolidated as wholly-owned subsidiaries.
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, 1999 and 1998 both the quantity and dollar amounts 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 7). 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. Changes in the market value of swap contracts or put options that are designated as hedges are deferred and subsequent gains and losses are recognized monthly as adjustments to revenues in the same production period as the hedged production. Contracts are placed with major financial institutions 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.
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 delay 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 depreciation and depletion is determined on a depletable unit basis using the unit-of-production method. Estimated future abandonment costs are recorded by charges to depreciation and depletion expense over the lives of the proved reserves of the properties.
The Company performs a review for impairment of proved oil and gas properties on a depletable unit basis when circumstances suggest there is a need for such a review. For each depletable unit determined to be impaired, an impairment loss equal to the difference between the carrying value and the fair value of the depletable unit will be recognized. Fair value, on a depletable unit basis, is estimated to be the present value of expected future cash flows computed by applying estimated future oil and gas prices, as determined by management, to estimated future production of oil and gas reserves over the economic lives of the reserves. Future cash flows are based upon the Company's estimate of approved 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 - - ----------------------- Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Company's commitment to a formal plan of action.
Capitalized Interest - - -------------------- The Company capitalizes interest costs associated with unproved properties under development. Interest capitalized in 1999, 1998 and 1997 was $544,000, $936,000 and $513,000, 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. Basic and diluted earnings per share were the same as reported prior to adoption of SFAS No. 128 for all periods presented. In 1999 and 1998 the Company had options outstanding that were exercisable at prices above the market. Due to losses in 1999 these shares are not considered dilutive 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 8.
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 and Note Receivable - - ---------------------------- At December 31, 1999 and 1998 accounts receivable are net of an allowance of $830,000 and $1 million, respectively. 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. The note bears interest at 7%, requires monthly interest payments and matures March, 2002.
Note 2 - ACQUISITIONS ------------
On May 14, 1998 the Company entered into a definitive agreement with BP Exploration and Oil, Inc. ("BP") to acquire BP's 100% working interest in East Breaks Blocks 165 and 209 and 75% working interest in High Island Block 587. The acquisition was accounted for using the purchase method and closed on May 26, 1998. 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 is 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.
On July 31, 1997, the Company acquired Goldking by merging its corporate parent, The Union Companies, Inc. ("Union") into Goldking Acquisition Corp., a newly formed, wholly-owned subsidiary of the Company. The individual shareholders of Union received merger consideration consisting of $7.5 million in cash, $6 million in notes (which were paid in October 1997) and 3,154,930 Company common shares, valued at $14 million. The Company assumed the debt of Goldking of $15.9 million and other net liabilities of $3.3 million and recorded a $3.1 million deferred tax liability based upon the complete utilization of the Company's deferred tax asset valuation allowance and the requirement for additional deferred tax liabilities resulting from the acquisition.
Both of these acquisitions were accounted for using the purchase method. The following unaudited pro forma financial information assumes the BP and Goldking acquisitions had been consummated January 1, 1997. The pro forma financial information does not purport to be indicative of the results of the Company had these transactions occurred on the date assumed, nor is it necessarily indicative of the future results of the Company.
Unaudited Pro Forma Financial Information For the Years Ended December 31, 1998 and 1997
1998 1997 ---- ----
Revenues $54,666,000 $59,768,000
Income (loss) before extraordinary item (46,177,000) 6,419,000
Net income (loss) (46,177,000) 5,485,000
Net income (loss) per share $ (1.93) $ 0.24
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 $337,000, $275,000 and $165,000 in costs for the years ended December 31, 1999, 1998 and 1997, respectively.
Note 4 - RESTRICTED DEPOSITS -------------------
Pursuant to existing agreements the Company is required to deposit funds in bank trust and escrow accounts to provide a reserve against satisfaction of its eventual responsibility to plug and abandon wells and remove structures when certain fields no longer produce oil and gas. Through November 30, 1997 the Company funded $900,000 into an escrow account with respect to the West Delta Fields. At that time, the Company completed its obligation for the funding under West Delta agreement. The Company has entered into an escrow agreement with Amoco Production Company under which the Company deposits, for the life of the fields, in a bank escrow account ten percent (10%) of the net cash flow, as defined in the agreement, from the Amoco properties. The Company has established the "PANACO East Breaks 110 Platform Trust" in favor of RLI, Underwriter's Indemnity. This trust required an initial funding of $846,720 in December 1996, and remaining deposits of $250,000 due at the end of each quarter until the balance in the account reaches $5.4 million. In connection with the BP Acquisition, the Company deposited $1.0 million into an escrow account on July 1, 1998. On the first day of each quarter thereafter, the Company will deposit $250,000 into the escrow account until the balance in the escrow account reaches $6.5 million.
Note 5 - 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 beginning April 1, 1998. 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, 1998 was $76,000,000 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, 1999 was $55.1 million, with availability of $16.2 million. The principal amount of the loan is due September 30, 2001, and may be extended for an additional year. 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.
The Company's previous credit facility was more restrictive and included covenants that the Company was not in compliance with at December 31, 1998. These covenant violations were remedied by waivers, but the Company most likely would not have been in compliance with them for the entire year had the new credit facility not been put in place.
(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 in the Goldking Acquisition. The agreement requires repayment of principal plus an amount sufficient to provide an internal rate of return of 18%.
Note 6 - EXTRAORDINARY ITEM-LOSS ON EARLY RETIREMENT OF DEBT ---------------------------------------------------
In 1999 the Company replaced its credit facility, see Note 5. In connection with the prepayment of the previous credit facility, the Company wrote off the remaining deferred financing costs associated with the previous facility.
In October 1997, the Company issued $100 million of 10.625% Senior Notes due 2004, see Note 5. A portion of the proceeds from the offering was used to repay or prepay substantially all of the Company's outstanding indebtedness. With the early retirement of the debt, the Company incurred a $ 484,000 charge to write-off the deferred financing costs associated with the previous debt facilities. In addition, as part of the prepayment of the convertible subordinated notes, the Company issued 2,060,606 warrants to acquire common shares at an exercise price of $4.125 per share which were the existing conversion terms of the prepaid notes. The fair value of these warrants has been estimated by an investment banker to be approximately $450,000, which has been recorded as an extraordinary item and additional paid-in capital.
Note 7 - COMMODITY HEDGE AGREEMENTS --------------------------
During 1997, 1998 and 1999, 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.
For the year 2000, the Company has purchased options to put oil and natural gas produced to a purchaser at an agreed upon price. The natural gas put option is for 10,000 MMbtu per day at a NYMEX price of $2.04 per MMbtu. The Company paid $366,000 for the put option which will be amortized over the period the hedged item is produced, fiscal year 2000. The oil put option is for 1,000 barrels of oil per day beginning March 1 and continuing through December 31 at a NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and will also be amortized over the period the hedge item is produced, fiscal year 2000. The Company also has a small swap in place on an average of 232 barrels of oil for each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its hedges was a loss of $800,000. The fair values of its hedges on December 31, 1998 and 1997 was a gain of $1.8 million and a loss of $61,000, 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, no respective carrying amounts for these instruments were included in the accompanying consolidated balance sheets as of December 31, 1999 and 1998. A 10% change in commodity prices would not have a material change in the fair value of our hedging instruments.
These hedge agreements provide for the counterparty to make payments to the Company to the extent the market prices (as determined in accordance with the agreement) are less than the fixed prices for the notional amount hedged and the Company to make payments to the counterparty to the extent market prices are greater than the fixed prices. The Company accounts for the gains and losses in oil and natural gas revenue in the month of hedged production.
Note 8 - STOCK OPTIONS AND WARRANTS --------------------------
On August 26, 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 options 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 expire June 20, 2000. Ownership of the stock acquired upon exercise is contractually restricted for a three-year period from the date of exercise, except in certain circumstances as described in the plan.
The fair value of each option in 1997 was estimated at the date of grant using the Black-Scholes Modified American Option Pricing Model with the following assumptions: Expected option life-year 3 Risk-free interest rate 6.1% Dividend yield 0% Volatility 38.4%
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 Company's net income (loss) and earnings (loss) per share for 1999 and 1998 would have been as shown below:
Note 9 - MAJOR CUSTOMERS ---------------
In 1999, the purchaser for a majority of the Company's oil production accounted for 37% of total revenues in 1999, while the purchaser for a majority of the Company's gas production accounted for 39% of total revenues in 1999. One purchaser accounted for 42% and 62% of revenues in 1998 and 1997, respectively. These transactions represented spot sales of natural gas to one customer.
Note 10 - INCOME TAXES ------------
At December 31, 1999, the Company had net operating loss carry forwards for federal income tax purposes of approximately $104 million which are available to offset future federal taxable income through 2019. 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 and the purchase of Goldking's common stock.
Significant components of the Company's deferred tax assets (liabilities) as of December 31 are as follows:
At December 31, 1999 the Company determined that it is more likely than not the deferred tax assets will not be realized and the valuation allowance was increased by $13,283,000.
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 11 - 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 the Company and NEG, NEG is required to indemnify the Company from any damages attributable to NEG's operations on the property after the sale. However, NEG is in Chapter 11 bankruptcy proceedings, and so any action by the Company to assert indemnity rights against NEG is currently stayed. The Company's Counsel has prepared and may file a motion to lift the stay so that the Company may assert its indemnification rights against NEG. But even if the Company is successful in proving its right to indemnity, NEG's ability to satisfy the judgement is questionable because of the bankruptcy.
Pursuant to another purchase and sale agreement, the Company may owe indemnity to Shell and Exxon, from whom it acquired the property prior to selling same to NEG. The Company may have insurance coverage for the claims asserted in the petition, and has notified all insurance carriers that might provide coverage under its policies. 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.
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. At December 31, 1999, the future minimum rental payments due under the lease are as follows:
2000 $ 336,000 2001 $ 389,000 2002 $ 102,000 ---------- Total $ 827,000 ==========
Note 12 - 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, 1999, 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 prices used for estimates of future revenues at December 31, 1999 averaged $24.99 per barrel of oil and $2.43 per Mcf of natural gas, adjusted for transportation, gravity and Btu content. 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: