ITEM 1. BUSINESS
OPERATIONAL OVERVIEW
Stone Energy is an independent oil and gas company engaged in the acquisition, exploration, development and operation of oil and gas properties located onshore and in shallow waters offshore Louisiana. We have been active in the Gulf Coast Basin since 1973 and have established extensive geophysical, technical and operational expertise in this area. As of December 31, 1999, we had estimated proved reserves of approximately 251.6 Bcf of natural gas and 22.6 MMBbls of oil, or an aggregate of approximately 387.4 Bcfe. As of December 31, 1999, the present value of estimated pre-tax net cash flows of our reserves was $561.3 million (based upon year-end 1999 prices which included the effect of hedges and a discount rate of 10%). In 1999, we increased production rates 17% from 1998, we replaced reserves at a rate of 157% and we achieved a drilling success rate of 93% based on wells completed during the year.
Our business strategy is to increase production, cash flow and reserves through the acquisition and development of mature properties located in the Gulf Coast Basin, either onshore or in shallow waters offshore. As a result of the successful and consistent application of this strategy, since our initial public offering in 1993, we have increased production 433%, cash flow from operations before working capital changes 468% and proved reserves 308%.
Since implementing our acquisition and exploitation strategy in 1990, we have acquired interests in 19 fields in the Gulf Coast Basin from major and large independent oil and gas companies. At December 31, 1999, we served as operator on all of our properties, which enables us to better control the timing and cost of field rejuvenation activities. We believe that there will continue to be numerous attractive opportunities to acquire properties in the Gulf Coast Basin due to the increased focus by major and large independent companies on projects in deeper waters and in foreign countries.
We seek to acquire properties that have the following characteristics:
o Gulf Coast Basin location;
o mature properties with an established production history and infrastructure;
o multiple productive sands and reservoirs;
o low current production levels with significant identified proven and potential reserve opportunities; and
o the opportunity for us to obtain a controlling interest and serve as operator.
We believe significant reserves remain to be discovered on properties in the shallow waters of the Gulf Coast Basin that satisfy our acquisition characteristics. We also believe that we can exploit these reserves by applying our technical expertise and patient approach in the evaluation and acquisition of such properties.
Prior to acquiring a property, we perform a thorough geological, geophysical and engineering analysis of the property to formulate a comprehensive development plan. To formulate this plan, we utilize the expertise of our technical team of 12 geologists, 7 geophysicists and 15 engineers. We also employ our extensive technical database, which includes 3-D seismic data on all of our current properties and some of the properties that we evaluate for acquisition. After acquisition, we seek to increase cash flow from existing reserves and to establish additional proved reserves through the drilling of new wells, workovers and recompletions of existing wells, and the application of other techniques designed to increase production. Our geographic focus, state-of-the-art equipment and high level of operated properties have enabled us to maintain low operating costs as evidenced by our per unit lease operating expense of $0.38 per Mcfe in 1999.
We have a substantial inventory of exploration and development projects that we believe provides us with a significant opportunity to increase our reserves and production from our existing properties. For the year ending December 31, 2000, we have budgeted exploration and development expenditures of $124.3 million, which includes plans to drill 30 new wells, conduct 39 workovers/recompletions on existing wells and, depending upon the success of specific development activities, install two new offshore production platforms. Our capital expenditures for 1999 totaled $123.9 million, of which $31 million related to the evaluation and acquisition of oil and gas properties.
FINANCIAL OVERVIEW
We completed our initial public offering of common stock in July 1993 (the "Initial Public Offering"), and our shares are listed on the New York Stock Exchange under the symbol "SGY". Additional offerings of common stock were completed in November 1996 and July 1999.
In September 1997, we completed an offering of $100 million principal amount of 8-3/4% Senior Subordinated Notes. These notes are due to mature in September 2007 and as of March 15, 2000 carried credit ratings by Moody's and Standard and Poor's of B2 and B, respectively. We also have a $200 million revolving credit agreement that as of December 31, 1999 had a borrowing base availability of $132.5 million with no outstanding draws.
We have maintained consistent, profitable growth since our initial public offering in 1993. We have generated net income in all calendar quarters except the fourth quarter of 1998, which included a non-cash ceiling test write-down of our oil and gas properties. The production increases discussed above combined with our focus on maintaining low lease operating and general and administrative costs on a per Mcfe basis have enabled us to increase EBITDA by 507% since 1993. Our net cash flow from operations has also grown consistently since our initial public offering resulting in per share growth of 241% since 1993 and 18% over 1998.
OIL AND GAS MARKETING
Our oil and natural gas condensate production is sold at current market prices under short-term contracts providing for variable or market sensitive prices. From time to time, we may enter into transactions hedging the price of oil, natural gas and natural gas condensate. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources."
COMPETITION AND MARKETS
Competition in the Gulf Coast Basin is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage. We compete with the major oil companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See "Risk Factors - Competition."
The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control, including but not limited to the amounts of domestic production and imports of foreign oil, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation, the conduct of drilling operations and federal regulation of natural gas. In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. See "Regulation-Federal Regulation of Sales and Transportation of Natural Gas." Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing area, generally may affect the supply and/or demand for oil and gas and thus the prices available for sales of oil and gas.
REGULATION
REGULATION OF PRODUCTION. In all areas where we conduct activities, there are statutory provisions regulating the production of oil and natural gas under which administrative agencies may enforce rules in connection with the location, spacing, drilling, operation and production of both oil and gas wells, determine the reasonable market demand for oil and gas, and establish allowable rates of production. These regulatory orders can limit the number of wells or the location where wells may be drilled. Regulations can also restrict the rate of production below the rate these wells would produce in the absence of such regulatory orders. Any of these actions could negatively impact the amount or timing of revenues.
FEDERAL LEASES. We have oil and gas leases in the Gulf of Mexico, which were granted by the federal government and are administered by the United States Department of the Interior Minerals Management Service (the "MMS"). For offshore operations, lessees must obtain MMS approval of exploration, development and production plans prior to the commencement of these operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the United States Environmental Protection Agency (the "EPA")), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has enacted regulations requiring offshore production facilities located on the Outer Continental Shelf ("OCS") to meet stringent engineering, construction and safety specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has enacted other regulations governing the plugging and abandoning of wells located offshore and the removal of all production facilities. Lessees must also comply with detailed MMS regulations governing the calculation of royalty payments and the valuation of production and permitted cost deductions for that purpose. On March 15, 2000, the MMS issued a final rule, to be effective June 1, 2000, modifying the valuation procedures for the calculation of royalties owed for crude oil sales. When oil production sales are not in arms-length transactions, the new royalty calculation will base the valuation of oil production on spot market prices instead of the posted prices that were previously utilized. We are currently selling our crude oil under arm's-length transactions in a manner that we believe to be acceptable to the MMS under its new rule. As such, we believe that the effect, if any, of this new rule will not have a material adverse effect on our results of operations.
With respect to any operations conducted on offshore federal leases, liability may generally be imposed under the Outer Continental Shelf Lands Act (the "OCSLA") for costs of clean-up and damages caused by pollution resulting from these operations, other than damages caused by acts of war or the negligence of third parties. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that these obligations will be met. The cost of bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases.
Since November 26, 1993, new levels of lease and areawide bonds have been required of lessees taking certain actions with regard to OCS leases. Operators in the OCS waters of the Gulf of Mexico were required to increase their areawide bonds and individual lease bonds to $3 million and $1 million, respectively, unless the MMS allowed exemptions or reduced amounts. We currently have an areawide right-of-way bond for $0.3 million and an areawide operator's bond totaling $3.0 million issued in favor of the MMS for our existing offshore properties. The MMS also has discretionary authority to require supplemental bonding in addition to the foregoing required bonding amounts but this authority is only exercised on a case-by-case basis at the time of filing an assignment of record title interest for MMS approval. Based upon certain financial parameters, we have been granted exempt status by the MMS, which exempts us from the supplemental bonding requirements. Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. Effective as of January 1, 1995, the Federal Energy Regulatory Commission (the "FERC") implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser. The implementation of these regulations has not had a material adverse effect on our results of operations.
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the FERC. In the past, the Federal government has regulated the prices at which gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, and 636-C (collectively, "Order No. 636"), which require interstate pipelines to provide transportation separate, or "unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas suppliers. Although Order No. 636 does not directly regulate our activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The implementation of these orders has not had a material adverse effect on our results of operations.
The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has recently begun a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas market restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts.
While any additional FERC action on these matters would affect us only indirectly, any new rules and policy statements may have the effect of enhancing competition in natural gas markets by, among other things, encouraging non-producer natural gas marketers to engage in certain purchase and sale transactions. We cannot predict what action the FERC will take on these matters, nor can we accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that we will be affected by any action taken materially differently than other natural gas producers and marketers with which we compete.
The OCSLA requires that all pipelines operating on or across the OCS provide open-access, non-discriminatory service. To date, the FERC has opted not to impose the regulations of Order No. 509, in which the FERC implemented the OCSLA with respect to interstate pipelines, on gatherers and other entities not subject to the FERC's NGA jurisdiction. The FERC has the authority under the OCSLA to exercise jurisdiction over those entities if necessary to permit non-discriminatory access to service on the OCS. The FERC recently proposed to adopt certain reporting requirements applicable (with limited exceptions) to both gatherers and pipelines operating on the OCS concerning their rates and terms and conditions of service. The purpose of the proposed requirements is to provide regulators and other interested parties with sufficient information to detect, and then seek to remedy, discriminatory conduct in such operations. We cannot predict the outcome of this proposal or what effect, if any, it may have on us. If the FERC were to apply Order No. 509 to gatherers in the OCS, and eliminate the exemption of gathering lines, then these acts could result in a reduction in available pipeline space for existing shippers in the Gulf of Mexico.
Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.
ENVIRONMENTAL REGULATIONS. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the oil and gas industry in general. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us.
The Oil Pollution Act ("OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by OPA.
OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from at least $10 million in specified state waters to at least $35 million in federal outer continental shelf waters, with higher amounts of up to $150 million if a formal risk assessment indicates that a higher amount should be required based on specific risks posed by the operations or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the MMS's final rule. On August 11, 1998, the MMS enacted a final rule implementing these financial responsibility requirements. We do not anticipate that we will experience any difficulty in continuing to satisfy the MMS's requirements for demonstrating financial responsibility under OPA.
The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The EPA has indicated that we may be potentially responsible for costs and liabilities associated with alleged releases of hazardous substances at one site. See "Item 3. Legal Proceedings-Environmental."
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain oil and gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
OPERATIONAL RISKS AND INSURANCE
Our operations are subject to the usual hazards incidental to the drilling of oil and gas wells, such as cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. Our activities are also subject to perils peculiar to marine operations, such as capsizing, collision, and damage or loss from severe weather. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.
We currently maintain loss of production insurance to protect against uncontrollable disruptions in production operations. The policy covers the majority of our anticipated production volumes from selected offshore properties on an individual facility basis. The value of lost production is calculated on estimated annual production volumes at insured prices of $19.00 per barrel of oil and $2.40 per Mcf of gas. We currently maintain coverage of up to $75 million per occurrence that becomes effective after 30 consecutive days of lost production.
We also maintain additional insurance of various types to cover our operations, including maritime employer's liability and comprehensive general liability. Amounts in excess of base coverages are provided by primary and excess umbrella liability policies with ultimate limits of $50 million. In addition, we maintain up to $50 million in operator's extra expense coverage, which provides coverage for the care, custody and control of wells drilled and/or completed plus redrill and pollution coverage. The exact amount of coverage for each well is dependent upon its depth and location.
The occurrence of a significant event, not fully insured or indemnified against, could materially and adversely affect our financial condition and operations. Moreover, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable.
Production from the E and D Platforms at our South Pelto Block 23 Field accounted for approximately 19% and 18%, respectively, of our total oil and gas production volumes during 1999. Production from this field accounted for approximately 39% of our total production for the year.
EMPLOYEES
At March 15, 2000, we had 129 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. From time to time we utilize the services of independent contractors to perform various field and other services.
FORWARD-LOOKING STATEMENTS
This Form 10-K and the information incorporated by reference contain statements that constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. The words "expect", "project", "estimate", "believe", "anticipate", "intend", "budget", "plan", "forecast", "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors with respect to, among other things:
o earnings growth;
o budgeted capital expenditures;
o increases in oil and gas production;
o future project dates;
o our outlook on oil and gas prices;
o estimates of our oil and gas reserves;
o our future financial condition or results of operations; and
o our business strategy and other plans and objectives for future operations.
When considering any forward-looking statement, you should keep in mind the risk factors and other cautionary statements in this Form 10-K that could cause our actual results to differ materially from those contained in any forward-looking statement. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publically update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.
All forward-looking statements attributable to Stone Energy Corporation are expressly qualified in their entirety by this cautionary statement.
RISK FACTORS
Our business is subject to a number of risks including, but not limited to, those described below:
OIL AND GAS PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUES, CASH FLOWS AND PROFITABILITY.
Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Factors that can cause this fluctuation include:
o relatively minor changes in the supply of and demand for oil and natural gas;
o market uncertainty;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries, particularly those in the Middle East;
o the foreign supply of oil and natural gas;
o the price of oil and gas imports; and
o overall economic conditions.
We cannot predict future oil and natural gas prices. At various times, excess domestic and imported supplies have depressed oil and gas prices. Declines in oil and natural gas prices may adversely affect our financial condition, liquidity and results of operations. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also create ceiling test write-downs of our oil and gas properties. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts.
In an attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.
In addition, the marketability of our production depends upon the availability, operation and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.
This Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this document and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. Such variances may be material.
At December 31, 1999, approximately 20% of our estimated proved reserves were undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we
have prepared estimates of our oil and gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated.
You should not assume that the present value of future net revenues referred to in this Form 10-K and the information incorporated by reference is the current fair value of our estimated oil and gas reserves. In accordance with Securities and Exchange Commission requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the Securities and Exchange Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.
We use the full cost method of accounting to account for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. Due to low oil and gas prices at the end of 1998, in December 1998 we recorded an after-tax write-down of $57.4 million ($89.1 million pre-tax). We cannot assure you that we will not experience ceiling test write-downs in the future.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING STRATEGY.
We have historically addressed our long-term liquidity needs through the use of bank credit facilities, the issuance of debt and equity securities and the use of cash provided by operating activities. We continue to examine the following alternative sources of long-term capital:
o bank borrowings or the issuance of debt securities;
o the sale of common stock, preferred stock or other equity securities;
o joint venture financing; and
o production payments.
The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value and operating performance. We may be unable to execute our operating strategy if we cannot obtain capital from these sources.
WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.
We spend and will continue to spend a substantial amount of capital for the development, exploration, acquisition and production of oil and gas reserves. Our capital expenditures were $123.9 million during 1999, $158.9 million during 1998 and $148.8 million during 1997. We estimate that our total capital expenditures for 2000 will be approximately $124.3 million. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our drilling program. We may be forced to raise additional debt or equity proceeds to fund such expenditures. We cannot assure you that additional debt or equity financing or cash generated by operations will be available to meet these requirements.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
In general, the volume of production from oil and gas properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves. Our recent growth is due in part to acquisitions of producing properties. The successful acquisition of producing properties requires an assessment of a number of factors beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and gas properties is intense and many of our competitors have financial and other resources which are substantially greater than those available to us.
Our strategy includes increasing our production and reserves by the implementation of a carefully designed field-wide development plan. This development plan is formulated prior to the acquisition of a property. However, we cannot assure you that our future development, acquisition and exploration activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND PRODUCTION ACTIVITIES.
Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o weather conditions;
o shortages in experienced labor; and
o shortages or delays in the delivery of equipment.
The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services.
We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.
OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS.
The exploration, development and operation of oil and gas properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.
As of December 31, 1999, our long-term debt was $100 million and we had $132.5 million of available borrowing capacity under our bank credit facility with no outstanding draws. The borrowing base limitation on our credit facility is periodically redetermined based on an evaluation of our reserves. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make such repayments.
Our level of debt affects our operations in several important ways, including the following:
o a large portion of our cash flow from operations may be used to pay interest on borrowings;
o the covenants contained in the agreements governing our debt limit our ability to borrow additional funds or to dispose of assets;
o the covenants contained in the agreements governing our debt may affect our flexibility in planning for, and reacting to, changes in business conditions;
o a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;
o our leveraged financial position may make us more vulnerable to economic downturns and may limit our ability to withstand competitive pressures;
o any debt that we incur under our credit facility will be at variable rates which makes us vulnerable to increases in interest rates; and
o a high level of debt will affect our flexibility in planning for or reacting to changes in market conditions.
In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. A higher level of debt increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control.
If we are unable to repay our debt at maturity out of cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings or equity financing will be available to pay or refinance such debt. The terms of our debt, including our credit facility and the indenture, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such offering or refinancing can be successfully completed.
COMPETITION WITHIN OUR INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.
We operate in a highly competitive environment. We compete with major and independent oil and gas companies for the acquisition of desirable oil and gas properties and the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than ours.
OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE AND LOCAL GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.
Our oil and gas operations are subject to various U. S. federal, state and local governmental regulations. These regulations may be changed in response to economic or political conditions. Regulated matters include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow of oil and gas wells below actual production capacity. In addition, the Oil Pollution Act of 1990 requires operators of offshore facilities to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under such law and other federal and state environmental statutes, owners and operators of certain defined facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. A substantial spill from one of our facilities could have a material adverse effect on our results of operations, competitive position or financial condition. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas, by-products from oil and gas and other substances, and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
Our operations are dependent upon a relatively small group of key management and technical personnel. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In order to manage our exposure to price risks in the marketing of our oil and gas, we enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedging policy provides that, without prior approval of our board of directors, generally not more than 50% of our production quantities can be hedged. In addition, such hedges shall not be longer than one year in duration. These arrangements may include future contracts on the New York Mercantile Exchange. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
o our production is less than expected;
o there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
o the counterparties to our future contracts fail to perform the contracts; or
o a sudden, unexpected event materially impacts oil or gas prices.
OWNERSHIP OF WORKING INTERESTS IN CERTAIN OF OUR PROPERTIES BY CERTAIN OF OUR OFFICERS AND DIRECTORS MAY CREATE CONFLICTS OF INTEREST.
James H. Stone and Joe R. Klutts collectively own 9% of the working interest in certain wells drilled on Section 19 on the east flank of the Weeks Island Field. These interests were acquired at the same time as our predecessor acquired its interests in the Weeks Island Field. In their capacity as working interest owners, they are required to pay their proportional share of all costs and are entitled to receive their proportional share of revenues.
Prior to our Initial Public Offering in 1993, The Stone Petroleum Corporation had formed partnerships to acquire and manage oil and gas properties. James H. Stone and Joe R. Klutts both participated in these partnerships. On December 31, 1999, the partnerships were dissolved and the working interests were transferred to Stone Energy Corporation. All participants in the partnerships, including James H. Stone and Joe R. Klutts, received overriding royalty interests in the related properties in exchange for their partnership interests.
Certain of our officers were granted net profits interests in some of our oil and gas properties acquired prior to 1993. The recipients of net profits interests are not required to pay capital costs incurred on the properties burdened by such interests.
As a result of these transactions, a conflict of interest may exist between us and such employees and officers with respect to the drilling of additional wells or other development operations.
WE DO NOT PAY DIVIDENDS.
We have never declared or paid any cash dividends on our common stock and have no intention to do so in the near future. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the Indenture executed in connection with our 8-3/4% Senior Subordinated Notes due 2007. In addition, we have entered into a credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.
OUR CERTIFICATE OF INCORPORATION AND BYLAWS HAVE PROVISIONS THAT DISCOURAGE CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON THEIR INVESTMENT.
Certain provisions of our Certificate of Incorporation, Bylaws and shareholders' rights plan and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. Our Bylaws provide for a classified board of directors. Also, our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares as the board may determine. Additional provisions include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions, alone or in combination with each other and with the rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.
During 1998, our board of directors adopted a shareholder rights agreement, pursuant to which uncertificated stock purchase rights were distributed to our stockholders at a rate of one right for each share of common stock held of record as of October 26, 1998. The rights plan is designed to enhance the board's ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts to acquire us by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by our board, including a takeover that may be desired by a majority of our stockholders or involving a premium over the prevailing stock price.
ITEM 2.
ITEM 2. PROPERTIES
We have grown principally through the acquisition and subsequent development and exploitation of properties purchased from major oil companies. During 1999, we acquired working interests in four new fields and increased our ownership interests in three existing fields. As a result, at December 31, 1999, we operated all of our 19 properties, twelve of which are in the Gulf of Mexico offshore Louisiana, and seven of which are onshore Louisiana. On December 31, 1999, we dissolved eight partnerships that were formed prior to our Initial Public Offering and owned less than 5% of our assets.
OIL AND GAS RESERVES
The following table sets forth our estimated net proved oil and gas reserves and the present value of estimated future pre-tax net cash flows related to such reserves as of December 31, 1999. Net revenue and net cash flow amounts include the effects of hedging contracts. The proved natural gas reserves at December 31, 1999 excluded 6.7 Bcf of gas dedicated to a production payment. Also excluded are the related estimated future net cash flows and the present value of estimated future net cash flows of $16.6 million and $14.8 million, respectively.
All information in this Form 10-K relating to estimated oil and gas reserves and the estimated future net cash flows attributable thereto is based upon the reserve reports (the "Reserve Reports") prepared as of December 31, 1999 by Atwater Consultants, Ltd. and Cawley, Gillespie & Associates, Inc., both independent petroleum engineers. Using the information contained in the Reserve Reports, the average 1999 year-end product prices, including the effects of hedging, for all of our properties were $25.07 per barrel of oil and $2.47 per Mcf of gas. All product pricing and cost estimates used in the Reserve Reports are in accordance with the rules and regulations of the Securities and Exchange Commission, and, except as otherwise
indicated, the reported amounts give no effect to federal or state income taxes otherwise attributable to estimated future cash flows from the sale of oil and gas. The present value of estimated future net cash flows has been calculated using a discount factor of 10%.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein only represents estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. As a result, estimates of reserves made by different engineers for the same property will often vary. Results of drilling, testing and production subsequent to the date of an estimate may justify a revision of such estimates. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately produced. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels and costs that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based.
As an operator of domestic oil and gas properties, we have filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells which it operates, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) and disregarding non-operated wells in which it owns an interest.
ACQUISITION, PRODUCTION AND DRILLING ACTIVITY
ACQUISITION AND DEVELOPMENT COSTS. The following table sets forth certain information regarding the costs incurred in our acquisition, development and exploratory activities during the periods indicated.
(1) Total additions to oil and gas properties during 1999 included non-cash additions of $20.3 million related to acquisitions made through production payments.
PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain statistics regarding the number of productive wells and developed and undeveloped acreage as of December 31, 1999.
Gross Net ------------------ -----------------
Productive Wells: Oil (1)........................ 87.00 62.46 Gas (2)........................ 64.00 52.17 ------------------ ----------------- Total........................ 151.00 114.63 ================== =================
Developed Acres: Onshore Louisiana.............. 3,913.31 3,108.15 Offshore Louisiana............. 11,907.31 9,765.01 ------------------ ----------------- Total........................ 15,820.62 12,873.16 ================== =================
Undeveloped Acres (3): Onshore Louisiana.............. 25,265.13 19,096.30 Offshore Louisiana............. 64,505.68 54,825.15 ------------------ -----------------
Total........................ 89,770.81 73,921.45 ================== =================
(1) 3 gross wells each have dual completions. (2) 10 gross wells each have dual completions. (3) Leases covering approximately 1% of our undeveloped acreage will expire in 2000, 4% in 2001, 3% in 2002, 1% in 2003 and 0% in 2004. Leases covering the remainder of our undeveloped gross acreage (91%) are held by production.
DRILLING ACTIVITY. The following table sets forth our drilling activity for the periods indicated.
TITLE TO PROPERTIES
We believe that we have satisfactory title on substantially all of our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our producing properties.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
ENVIRONMENTAL
In August 1989, we were advised by the EPA that it believed we were a potentially responsible party (a "PRP") for the cleanup of an oil field waste disposal facility located near Abbeville, Louisiana, which was included on CERCLA's National Priority List (the "Superfund List") by the EPA in March 1989. Although we did not dispose of wastes or salt water at this site, the EPA contends that transporters of salt water may have rinsed their trucks' tanks at this site. By letter dated December 9, 1998, the EPA made demand for cleanup costs on 23 of the PRP's, including us, who had not previously settled with the EPA. Since that time we, together with other PRPs, have been negotiating the settlement of our respective liability for environmental conditions at this site with the U.S. Department of Justice. Given the number of PRP's at this site and the current satisfactory progress of these negotiations, we do not believe that any liability for this site would have a material adverse affect on our financial condition.
OTHER PROCEEDINGS
We are named as a defendant in certain lawsuits and are a party to certain regulatory proceedings arising in the ordinary course of business. We do not expect these matters, individually or in the aggregate, to have a material adverse effect on our financial condition.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names, ages (as of March 15, 2000) and positions held by each of our executive officers. Our executive officers serve at the discretion of the Board of Directors.
The following biographies describe the business experience of our executive officers for at least the past five years. Stone Energy Corporation was formed in March 1993 to become a holding company for The Stone Petroleum Corporation ("TSPC") and its subsidiaries. In 1997, TSPC was dissolved after the majority of its assets were transferred to Stone Energy Corporation.
James H. Stone has served as Chairman of the Board and Chief Executive Officer since March 1993, as Chairman of the Board of TSPC from 1981 to 1997 and as President of TSPC from September 1992 to July 1993. Mr. Stone is currently a director of Newpark Resources, Inc.
D. Peter Canty was named President of the Company in March 1994. He previously served as Executive Vice President for one year. He has also served as Chief Operating Officer and as a Director since March 1993. Mr. Canty was President of TSPC from 1994 to 1997 and was its Chief Geologist from 1987 to 1994.
James H. Prince was named Chief Financial Officer in August 1999 and Treasurer in June 1999. He previously served as Chief Accounting Officer and Controller from 1993 to August 1999.
Phillip T. Lalande has served as Vice President - Engineering since March 1995. He served as Operations Manager from July 1993 to March 1995, and as a consulting engineer to TSPC from 1988 to July 1993.
J. Kent Pierret was named Vice President - Accounting and Controller in June 1999. Prior to rejoining us, he was a partner in the firm of Pierret, Veazey & Co., CPAs (and its predecessors) from May 1988 to May 1999, which performed a substantial amount of our financial reporting, tax compliance and financial advisory services.
Andrew L. Gates, III has served as Vice President - Legal, Secretary and General Counsel since August 1995. Previously, he was a partner in the law firm of Ottinger, Gates, Hebert & Sikes from 1987 to August 1995.
E. J. Louviere has served as Vice President - Land since June 1995. Previously, he served as Land Manager of TSPC and us from July 1981 to June 1995.
Craig L. Glassinger has served as Vice President - Acquisitions since December 1995. From October 1992 to December 1995 he served TSPC, and us, as Acquisitions Manager. Prior to joining TSPC, he was a division geologist for Forest Oil Corporation for approximately ten years.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since July 9, 1993, our Common Stock has been listed on the New York Stock Exchange under the symbol "SGY." The following table sets forth, for the periods indicated, the high and low closing prices per share of our Common Stock.
High Low ---------- ---------
First Quarter........................... $39 3/8 $28 9/16 Second Quarter.......................... 40 3/16 31 Third Quarter........................... 36 5/16 20 1/16 Fourth Quarter.......................... 36 7/8 25 3/4
First Quarter........................... $33 1/16 $22 3/4 Second Quarter.......................... 45 31 3/8 Third Quarter........................... 55 5/8 42 Fourth Quarter.......................... 50 15/16 33 3/4
First Quarter (through March 15, 2000).. $50 1/4 $32 1/4
On March 15, 2000, the last reported sales price on the New York Stock Exchange Composite Tape was $48.00 per share. As of that date there were approximately 156 holders of record of our Common Stock.
DIVIDEND RESTRICTIONS
We have not in the past, and do not intend to pay cash dividends on our Common Stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the Indenture executed in connection with our 8-3/4% Senior Subordinated Notes due 2007. In addition, we have entered into a credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
SELECTED HISTORICAL FINANCIAL INFORMATION
The following table sets forth a summary of selected historical financial information for each of the years in the five year period ended December 31, 1999. This information is derived from our consolidated financial statements and the notes thereto. See "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our financial position and results of operations for each year of the three-year period ended December 31, 1999. Our financial statements and the notes thereto contain detailed information that should be referred to in conjunction with the following discussion. See "Item 8. Financial Statements and Supplementary Data."
GENERAL
We are an independent oil and gas company engaged in the acquisition, exploration, development and operation of oil and gas properties onshore and in shallow waters offshore Louisiana. We have been active in the Gulf Coast Basin since 1973, which gives us extensive geophysical, technical and operational expertise in this area. Our business strategy is to increase production, cash flow and reserves through the acquisition and development of mature properties located in the Gulf Coast Basin.
OPERATING ENVIRONMENT
Our revenue, profitability and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Beginning in late 1997 and continuing throughout 1998 and the first quarter of 1999, the oil and gas industry experienced a trend of declines in natural gas and crude oil prices. The decline in natural gas prices was attributable to milder-than-normal weather conditions resulting in excess domestic supplies, while oil prices declined because of higher world supplies coupled with an anticipated decrease in demand resulting from the overall outlook of the global economy.
As a result of the worldwide decline in the supply of crude oil caused by OPEC's self imposed oil production reductions, since the first quarter of 1999, the price for crude oil has improved significantly. In addition, the price for natural gas has increased from the first quarter of 1999 because of the market's perception of lower than normal supplies combined with the expected increase in future demand. The average prices we received for our production during the fourth quarter of 1999 totaled $20.95 per barrel and $2.50 per Mcf, as compared to average prices received during the fourth quarter of 1998 of $11.72 per barrel and $2.12 per Mcf. All unit pricing amounts include the effects of hedging.
The demand for and the costs of drilling rigs and related products and services fluctuates with the prices of oil and natural gas. Therefore, with the recovery of oil and natural gas prices, the demand for and the costs of drilling rigs and related services have started to rise and could increase further. In an attempt to hedge against rising drilling costs, we have in the past entered into long-term, fixed rate contracts for drilling rigs that are capable of drilling on all our properties. We expect to be able to finance our 2000 budgeted operations and development activities with cash flows from operations. If the costs of drilling related products and services increase substantially from current levels, we believe that the available borrowings under our credit facility will be sufficient to fund any capital expenditures in excess of cash flows from operations.
As a result of fluctuating oil and gas prices and the related effects on oil and gas companies, there has been an increase in the number of properties available for acquisition in the Gulf Coast Basin. In addition, the recent merger and acquisition transactions among both major and independent oil and gas companies, coupled with the move of many companies to the deep-water region of the Gulf of Mexico, should increase the supply of properties available for acquisition in our area of operations. These trends should provide us with significant opportunities to acquire properties that fit our specific acquisition profile. While generally it is more expensive to buy properties at times when oil and natural gas prices have increased, we are somewhat insulated by our preference to acquire properties with low production rates and cash flows at the time of purchase.
At present, we do not expect that changes in the rates of overall economic growth or inflation will significantly impact product prices in the short-term. Furthermore, because most of the factors that affect the prices we receive for our production are beyond our control, our marketing efforts are devoted to achieving the best price available in each geographic location and entering into a limited amount of fixed price sales and hedging transactions to take advantage of short-term prices we believe to be attractive.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and gas reserves. See "Item 2. Properties-Oil and Gas Reserves."
1999 COMPARED TO 1998. We recognized net income for the year ended December 31, 1999 totaling $26.5 million, or $1.58 per share, as compared to 1998 net loss of $51.6 million, or $3.43 per share. The 1998 results included an after-tax non-cash ceiling test write-down of $57.4 million, or $3.82 per share. Excluding the write-down, favorable results in 1999 net income versus 1998 were due to improvements in the following components.
PRODUCTION. Production volumes of oil and gas reached a record high during 1999 and, as compared to 1998, rose 21% and 15%, respectively, totaling 3.5 million barrels of oil and 38.1 billion cubic feet of gas. On a thousand cubic feet of gas equivalent (Mcfe) basis, production rates for 1999 were 17% higher than 1998 production rates.
The increase in 1999 production rates, as compared to 1998, was due primarily to increases at four of our fields. First, we successfully executed an aggressive exploration and development program at Vermilion Block 255 by completing and placing on production three exploratory and two development wells. At the end of 1998, we began producing two high-pressured gas wells at the South Pelto Block 23 E Platform, which have significantly contributed to 1999's favorable production rates. From June 1998 through August 1999, we successfully drilled one exploratory well, three development wells and completed three workovers to enhance production at Clovelly Field. Finally, in May 1999, we increased our interest, and therefore our share of production, at Weeks Island Field through the acquisition of an additional 32% working interest in 11 producing wells.
PRICES. Average realized prices during 1999 were $16.42 per barrel of oil and $2.36 per Mcf of gas and represented a 10% increase, on an Mcfe basis, over average prices of $13.40 per barrel of oil and $2.29 per Mcf of gas recognized during 1998, including the effects of hedging. From time to time, we enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During 1999, hedging transactions reduced the average price we received for oil by $1.42 per barrel and increased the average gas price received by $0.02 per Mcf as compared to net increases of $0.28 per barrel of oil and $0.10 per Mcf of gas during 1998.
OIL AND GAS REVENUES. Oil and gas revenues reached a record high during 1999. The favorable increases in oil and gas production rates combined with higher commodity prices resulted in oil and gas revenues increasing 28% to $146.9 million, compared to oil and gas revenues of $114.6 million during 1998.
EXPENSES. Normal operating costs during 1999 increased to $22.6 million, compared to $18 million during 1998. On a unit of production basis, 1999 operating costs were $0.38 per Mcfe as compared to $0.36 per Mcfe for 1998. The increase in operating costs was due primarily to a 34% increase in the number of producing wells that we operate as a result of the acquisitions of the Lafitte Field, West Cameron Block 176 and East Cameron Block 46, the increases in working interest at East Cameron Block 64, Eugene Island Block 243 and Weeks Island Field and discoveries at many of our fields including Vermilion Block 255, Vermilion Block 131, Clovelly Field and Eugene Island Block 243.
As a result of increased 1999 production volumes due to acquisitions and discoveries combined with higher oil and gas prices during the year, production revenues from onshore properties increased 43% during 1999. Our production tax expense, however, declined during 1999 to $2 million from $2.1 million in 1998. This decrease resulted from the abatement of severance taxes for certain wells under Louisiana State Law. Accordingly, we accrued in December 1999, and will receive in early 2000, a production tax refund of $1 million.
General and administrative expenses for 1999 increased in total to $4.7 million from $4.3 million during 1998. However, on a unit basis, these costs were unchanged from the 1998 amount of $0.08 per Mcfe. Due to our operational results and stock performance during the year, incentive compensation expense for 1999 increased to $1.5 million compared to $0.8 million in 1998.
Depreciation, depletion and amortization (DD&A) expense on our oil and gas properties decreased to $64.6 million ($1.10 per Mcfe) compared to $67.3 million ($1.33 per Mcfe) for 1998. The decrease in DD&A expense resulted from a combination of the $89.1 million non-cash ceiling test write-down of oil and gas properties recorded at the end of 1998 and the improvement in oil and gas prices throughout 1999.
As a result of the July 1999 stock offering and the subsequent repayment of all outstanding borrowings under our bank credit facility, interest expense for 1999 decreased to $12.8 million, compared to $13 million during 1998.
Our provision for income taxes was $12.1 million for the year ended December 31, 1999 and was net of a $1.5 million reduction in deferred taxes relative to estimates of tax basis that were resolved during 1999.
RESERVES. At December 31, 1999, our estimated proved oil and gas reserves totaled 387.4 Bcfe, excluding approximately 6.7 Bcf of gas dedicated to a production payment associated with certain 1999 acquisitions, compared to December 31, 1998 reserves of 354.1 Bcfe. Oil reserves increased to 22.6 MMBbls at the end of 1999 from 18.5 MMBbls at the beginning of the year, and gas reserves grew to 251.6 Bcf at December 31, 1999, excluding the 6.7 Bcf of gas dedicated to a production payment, compared to 243.3 Bcf at year-end 1998.
The increases in our 1999 estimated proved reserves were primarily attributable to drilling results and acquisitions made during the year. The reserve estimates were prepared by independent petroleum consultants in accordance with the guidelines established by the SEC. Adherence to these guidelines limited us in booking reserves on certain successfully drilled wells to the extent of the base of known productive sands. Actual limits of the productive sands will ultimately be determined through production or additional drilling.
1998 COMPARED TO 1997. We recognized a net loss for the year ended December 31, 1998 totaling $51.6 million, or $3.43 per share, as compared to 1997 net income of $11.9 million, or $0.78 per share. The 1998 results included an after-tax, non-cash ceiling test write-down of $57.4 million or $3.82 per share.
During December 1997, we initiated production from the D Platform at our South Pelto Block 23 Field. Production from this structure, together with production increases at a number of our other fields, generated record levels of production volumes during 1998. Production volumes during 1998 increased 113%, on a Mcfe basis, over the previous record 1997 production levels. Production volumes of both oil and gas during 1998, compared to 1997, rose 81% and 135%, respectively, totaling 2.9 MMBbls of oil and 33.3 Bcf of gas. Despite a 22% decrease in the average price received per Mcfe, the growth in production volumes during 1998 resulted in oil and gas revenues rising to $114.6 million, a 66% increase from 1997 oil and gas revenues of $69.1 million. The average prices received, net of the effects of hedging contracts, for our production during 1998 were $13.40 per barrel of oil and $2.29 per Mcf of gas, as compared to $19.61 per barrel and $2.68 per Mcf during 1997.
Normal operating costs increased during 1998 to $18 million compared to $10.1 million in 1997. The increase was attributable to an increase in the number of properties and significantly higher production rates. However, on a unit basis, these costs declined 16% during 1998 to $0.36 per Mcfe from $0.43 per Mcfe in 1997.
Total DD&A expense attributable to oil and gas properties increased during 1998 because of higher production rates, an increased investment in the properties and lower quarter-end prices. DD&A on oil and gas properties increased to $67.3 million, or $1.33 per Mcfe, in 1998 from $28.1 million, or $1.19 per Mcfe, in 1997.
We follow the full cost method of accounting for our oil and gas properties. Securities and Exchange Commission regulations require that companies using full cost accounting value their proved year-end reserves based on oil and gas prices in effect at December 31. As a result of the low oil and gas price environment at year-end 1998, during the fourth quarter we recognized a ceiling test write-down on our oil and gas properties totaling $89.1 million, which on an after-tax basis was $57.4 million. We anticipate that the write-down will provide a positive impact on future earnings resulting from lower future unit depreciation expense.
To finance a portion of our 1998 capital expenditures budget, we increased our borrowings under our bank credit facility during 1998. As a result of these borrowings and the bond offering closed in September 1997, interest expense increased to $13 million during 1998, compared to $4.9 million in 1997. Because of the continued increase in our level of operations during 1998, general and administrative costs increased in total to $4.3 million. However, on a unit basis, general and administrative costs declined 50% to $0.08 per Mcfe, compared with $0.16 per Mcfe in 1997.
At December 31, 1998, our reserves totaled 354.1 Bcfe, a 20% increase from December 31, 1997 reserves of 295.8 Bcfe. Oil reserves increased to 18.5 MMBbls at the end of 1998 from 17.8 MMBbls at the beginning of the year, and gas reserves grew to 243.3 Bcf at December 31, 1998 compared to 189.2 Bcf at year-end 1997. As a result of the decline in oil and gas prices, the estimated discounted cash flows from our proved reserves declined 22% from 1997.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Pending the use of proceeds from the stock offering, in August 1999 we repaid all of the outstanding borrowings under our revolving credit facility. Net cash flow from operations before working capital changes for 1999 was $101.3 million, or $6.04 per share, compared to $77.2 million, or $5.12 per share, reported for 1998. Working capital at December 31, 1999 totaled $22.9 million.
CAPITAL EXPENDITURES. Capital expenditures during 1999 totaled $123.9 million and primarily consisted of exploration and development expenditures at many of our fields including Eugene Island Block 243, East Cameron Block 64 and Vermilion Block 255 in addition to acquisition costs primarily for an additional interest in East Cameron Block 64 and a 100% working interest in West Cameron Block 176. Capital expenditures for 1999 included $7 million of capitalized general and administrative costs and $0.3 million of capitalized interest. These investments were financed by a combination of cash flows from operations and production payments.
ACQUISITION COSTS. During 1999, we acquired additional interests in three of our existing fields and completed the acquisition of four new fields. Adjacent to our South Pelto Block 23, we farmed in a 100% working interest on South Timbalier Block 71. In May 1999, we acquired an additional 32% working interest in a portion of the Weeks Island Field for $4.8 million. In June 1999, we acquired a majority interest and control of operations in the Lafitte Field for $6.1 million in cash and a production payment to be satisfied through the sale of production from the purchased property. During September 1999, Goodrich Petroleum Company, L.L.C. exercised its option to participate for a 49% working interest in the Lafitte Field resulting in a cash reimbursement to us of approximately $3 million and a proportional reduction in the production payment. In June 1999, we acquired from other interest owners their residual interests in certain formation rights and farmin interests on a 29% working interest and a 24.24% net revenue interest in the Eugene Island Block 243 Field for $0.5 million. In July 1999, we acquired a 62.5% working interest in the East Cameron Block 64 Field and a 100% working interest in the West Cameron Block 176 Field, as well as control of operations for both fields, in exchange for a volumetric production payment of 8 Bcf of gas to be delivered over a three-year period from the South Pelto Block 23 Field. The accounting for this volumetric production payment resulted in the recording of a $17.9 million asset based upon the estimated discounted cash flow associated with the specific production volumes to be delivered. Finally, in November 1999, we acquired a 100% working interest in East Cameron Block 46 Field for $1 million. With the 1999 acquisitions, we now serve as operator on all of our 19 properties.
DEVELOPMENT COSTS. During 1999, we completed numerous development drilling, workover and recompletion operations and facilities installations in an effort to develop our property base and to increase cash flow from proved reserves. During 1999, our development drilling program achieved a 100% success rate consisting of the Eugene Island Block 243 No. D-1 Well, the OCS-G 1152 No. H-5 and OCS-G 1153 No. D-3 wells at Vermilion Block 255, the Clovelly Corporation No. 41 and Dereda Thomas No. 1 wells at Clovelly Field and the OCS-G 0775 No. 18 Well at Vermilion Block 131. The year's most significant workover projects included the OCS-G 0079 No. 1 Well at Vermilion Block 46, the OCS-G 0089 No., OCS-G 0089 No. 9 and OCS-G 0089 No. 7 wells at East Cameron Block 64 and the LL&E No. 189 and Rigolets No. 161 wells at Lafitte Field, four of which were successful. We also drilled and completed for saltwater injection the Dereda Thomas No. 2 SWD Well at Clovelly Field and upgraded the production facilities at several fields to accommodate additional production from discoveries.
EXPLORATORY COSTS. In an effort to provide additions to our existing oil and gas reserve base, during 1999, we completed drilling operations on nine exploratory wells, eight of which were successful. These eight wells included the OCS-G 2899 No. A-7 Well at Eugene Island Block 243's Orca 2 Prospect, the OCS-G 0775 No. 19 Well at Vermilion Block 131's Skate Prospect, the OCS-G 3135 No. 2 Well at Vermilion Block 255's Pylos Prospect, the OCS-G 1152 No. H-4 Well at Vermilion Block 255's Slide Prospect, the OCS-G 14519 No. 1 Well at South Timbalier Block 71's Triggerfish Prospect, the OCS-G 1152 No. A-7 STK Well at Vermilion Block 255's Bubble Prospect and two wells under a joint venture drilling project at Weeks Island Field: the Myles Salt No. 46 Well (formerly named the Myles Salt No. 1 Well) and the Meridian State Lease 500 No. 1 Well.
BUDGETED CAPITAL EXPENDITURES AND LONG-TERM FINANCING. For the year 2000, we have budgeted what would be a record year for drilling wells with 30 new wells scheduled, including 17 wells on properties acquired during 1999. We have budgeted $124.3 million for our 2000 exploration and development plans including $33.1 million for drilling on properties acquired during 1999. Approximately 50% of our capital expenditures budget has been allocated for activities at the Vermilion Block 255, Eugene Island Block 243, South Timbalier Block 8, West Cameron Block 176 and Lafitte Fields.
Based upon our outlook on oil and gas prices and production rates, we believe that our cash flows from operations will be sufficient to fund the current 2000 capital expenditures budget. If oil and gas prices or production rates fall below our current expectations, we believe that the available borrowings under our bank credit facility will be sufficient to fund the capital expenditures in excess of operating cash flows.
We believe that the opportunity for acquisitions in our area of operations remains strong due to the general exodus from the shallow water and shelf region of the Gulf. We do not budget acquisitions; however, we are currently evaluating several opportunities that fit our specific acquisition profile. One or a combination of certain of these possible transactions could fully utilize our existing sources of capital. Although we have no plans to access the public markets for purposes of capital, if the opportunity arose, we would consider such funding sources to provide capital in excess of what is currently available to us. We would compare and contrast the cost of debt financing with the potential dilution of equity offerings to determine the appropriate financing vehicle to maximize stockholder value.
HEDGING. Our production is sold on month-to-month contracts at prevailing prices. From time to time, however, we have entered into hedging transactions for our oil and gas production. The primary objective of these transactions is to reduce our exposure to future oil and gas price declines during the term of the hedge. This hedging policy provides that, unless prices increase by more than 50% of the prices utilized in our most recent budget, not more than one-half of our production quantities can be hedged without the consent of the Board of Directors. Additionally, not more than 75% of our production quantities can be committed to any swap agreement regardless of the prices available.
We currently utilize two forms of hedging contracts: fixed price swaps and collars. Fixed price swaps typically provide for monthly payments by us (if prices rise) or to us (if prices fall) based on the difference between the strike price and the agreed-upon average of NYMEX prices. For collars, monthly payments are made by us if NYMEX prices rise above the ceiling price and to us if NYMEX prices fall below the floor price. Oil contracts typically settle using the average of the daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices for near month NYMEX futures contracts for the three days prior to the settlement date. Because our properties are located in the Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely match changes in market prices for our production.
During 1999, we realized a net reduction in revenues from our hedging transactions of $4.3 million. Swap contracts totaled 1,363.1 MBbls of oil and 16,440 BBtus of gas, which represented approximately 39% and 47%, respectively, of our oil and gas production for the year. As of March 15, 2000, we had hedged oil and gas prices for the applicable periods, quantities and average prices as follows:
The net increase in revenues from hedging transactions for 1998 was $4.3 million. Swap contracts totaled 144 MBbls of oil and 9,580 BBtus of gas, which represented approximately 5% and 30%, respectively, of our oil and gas production for that year.
HISTORICAL FINANCING SOURCES. Since our Initial Public Offering in July 1993, we have financed our activities primarily with both debt and equity offering proceeds, cash flows from operations, production payments and borrowings under our bank credit facility.
In November 1995, we executed a term loan agreement with Bank One in the original principal amount of $3.3 million for the purchase of the RiverStone office building, the majority of which is used by us for our Lafayette office. During 1999, the loan was repaid with borrowings under our bank credit facility.
In September 1997, we completed an offering of $100 million principal amount of 8-3/4% Senior Subordinated Notes (the "Notes") due September 15, 2007 with interest payable semiannually. There are no sinking fund requirements on the Notes and they are redeemable at our option, in whole or in part, at 104.375% of their principal amount beginning September 15, 2002, and thereafter at prices declining annually to 100% on and after September 15, 2005. Provisions of the Notes include, without limitation, restrictions on liens, indebtedness, asset sales and other restricted payments.
On July 28, 1999, we completed an offering of 3.16 million shares of our common stock at a price to the public of $43.75 per share. After payment of the underwriting discount and expenses, we received net proceeds of $130.8 million. On August 3, 1999, we used a portion of the net proceeds from our stock offering to repay the outstanding borrowings under our credit facility. This reduced long-term debt to $100 million, representing our Senior Subordinated Notes. The proceeds from the stock offering will ultimately be used to fund specifically identified exploration and development activities, to finance potential property acquisitions and for other general corporate purposes.
During 1999, our bank group increased the borrowing base under our credit facility from $120 million to $140 million. The borrowing base limitation is based on a borrowing base amount established by the banks for our oil and gas properties. At December 31, 1999, we had no outstanding borrowings under our borrowing base and had outstanding letters of credit totaling $7.5 million. In February 2000, our bank group increased our credit facility from $150 million to $200 million and extended the maturity date from July 30, 2001 to July 30, 2005.
Our credit facility provides for certain covenants, including restrictions or requirements with respect to working capital, net worth, disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends.
REGULATORY AND LITIGATION ISSUES. In August 1989, we were advised by the EPA that it believed we were a potentially responsible party (a "PRP") for the cleanup of an oil field waste disposal facility located near Abbeville, Louisiana, which was included on CERCLA's National Priority List (the "Superfund List") by the EPA in March 1989. Although we did not dispose of wastes or salt water at this site, the EPA contends that transporters of salt water may have rinsed their trucks' tanks at this site. By letter dated December 9, 1998, the EPA made demand for cleanup costs on 23 of the PRP's, including us, who had not previously settled with the EPA. Since that time we, together with other PRPs, have been negotiating the settlement of our respective liability for environmental conditions at this site with the U.S. Department of Justice. Given the number of PRP's at this site and the current satisfactory progress of these negotiations, we do not believe that any liability for this site would have a material adverse affect on our financial condition.
Since November 26, 1993, new levels of lease and areawide bonds have been required of lessees taking certain actions with regard to OCS leases. Operators in the OCS waters of the Gulf of Mexico were required to increase their areawide bonds and individual lease bonds to $3 million and $1 million, respectively, unless the MMS allowed exemptions or reduced amounts. We currently have an areawide right-of-way bond for $0.3 million and an areawide operator's bond totaling $3.0 million issued in favor of the MMS for our existing offshore properties. The MMS also has discretionary authority to require supplemental bonding in addition to the foregoing required bonding amounts but this authority is only exercised on a case-by-case basis at the time of filing an assignment of record title interest for MMS approval. Based upon certain financial parameters, we have been granted exempt status by the MMS, which exempts us from the supplemental bonding requirements. Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.
OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from at least $10 million in specified state waters to at least $35 million in federal outer continental shelf waters, with higher amounts of up to $150 million if a formal risk assessment indicates that a higher amount should be required based on specific risks posed by the operations or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the MMS's final rule. On August 11, 1998, the MMS enacted a final rule implementing these financial responsibility requirements. We do not anticipate that we will experience any difficulty in continuing to satisfy the MMS's requirements for demonstrating financial responsibility under OPA.
We operate under numerous state and federal laws enacted for the protection of the environment. In the ordinary course of business, we conduct an ongoing review of the effects of these various environmental laws on our business and operations. The estimated cost of continued compliance with current environmental laws, based upon the information currently available, is not material to our results of operations or financial position. It is impossible to determine whether and to what extent our future performance may be affected by environmental laws; however, we believe that such laws will not have a material adverse effect on our results of operations or financial position.
YEAR 2000 COMPLIANCE. The year 2000 ("Y2K") issue was the result of concern that computerized systems would not be able to store and process the year portion of dates from and after January 1, 2000 without critical systems failure. During 1998 and 1999, we implemented and completed a plan to evaluate the potential Y2K risks of our critical Information Technology ("IT") and Non-IT Systems and replaced or made modifications to computer hardware and software that were deemed necessary for Y2K compliance. Costs expensed during the year related to Y2K compliance totaled $10,000. In addition, we capitalized $1.6 million of computer hardware and software costs that were necessary due to the growth in our number of employees and level of operations over the past 24 months.
As of March 15, 2000, we have not experienced any noticeable Y2K related systems failures or disruptions in the supply of materials or services provided by third parties.
FORWARD-LOOKING STATEMENTS
Certain of the statements set forth under this Item and elsewhere in this Form 10-K are forward-looking and are based upon assumptions and anticipated results that are subject to numerous risks and uncertainties. See "Item 1. Business --Forward-Looking Statements" and " --Risk Factors."
ACCOUNTING MATTERS
BASIS OF PRESENTATION. The consolidated financial statements include our accounts, our proportionate share of certain partnerships, TSPC and TSPC's proportionate share of certain partnerships. In June 1997, TSPC was dissolved after the majority of its assets, including its proportionate share of certain partnerships, were transferred to us. On December 31, 1999, the partnerships were also dissolved after their assets were transferred to us. All intercompany balances and transactions that existed prior to these dissolutions have been eliminated.
FULL COST METHOD. We use the full cost method of accounting for our oil and gas properties. Under this method, all acquisition and development costs, including certain related employee costs and general and administrative costs (less any reimbursements for such costs) incurred for the purpose of acquiring and finding oil and gas are capitalized. We amortize our investment in oil and gas properties using the future gross revenue method.
DEFERRED INCOME TAXES. Deferred income taxes have been determined in accordance with Financial Accounting Standards Board Statement No. 109, "Accounting for Income Taxes." As of December 31, 1999, we had a net deferred tax liability of $0.7 million which was calculated based on our assumption that it is more likely than not that we will have sufficient taxable income in future years to utilize certain tax attribute carryforwards.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES REGARDING MARKET RISKS
Our revenues are derived from the sale of crude oil and natural gas production. From time to time, we enter into hedging transactions. These hedges reduce our exposure to decreases in commodity prices and limit the benefit we might otherwise have received from any increases in commodity prices on the hedged volumes.
Based on projected annual sales volumes for 2000, a 10% decline in the prices we are projecting to receive for our crude oil and natural gas production would have an approximate $8.3 million impact on our annual revenues. This hypothetical impact of the decline in oil and gas prices is net of the incremental increase in revenues that we would realize, upon a decline in prices, from the oil and gas hedging contracts in place as of March 15, 2000.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on Page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
For information concerning Item 10.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) 1. FINANCIAL STATEMENTS:
The following financial statements and the Report of Independent Public Accountants thereon are included on pages through of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 1999 and 1998
Consolidated Statement of Operations for the three years in the period ended December 31, 1999
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 1999
Consolidated Statement of Changes in Equity for the three years in the period ended December 31, 1999
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is inapplicable or the information is presented in the Financial Statements or the notes thereto.
3. EXHIBITS:
3.1 -- Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as of October 15, 1998, between the Company and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A (File No. 001-12074)).
4.2 -- Indenture between Stone Energy Corporation and Texas Commerce Bank, National Association dated as of September 19, 1997 (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-4 dated October 22, 1997 (File No. 333-38425)).
+10.1 -- Stone Energy Corporation 1993 Nonemployee Directors' Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.2 -- Deferred Compensation and Disability Agreements between TSPC and D. Peter Canty dated July 16, 1981, and between TSPC and Joe R. Klutts and James H. Prince dated August 23, 1981 and September 20, 1981, respectively (incorporated by reference to Exhibit 10.8 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.3 -- Conveyances of Net Profits Interests in certain properties to D. Peter Canty and James H. Prince (incorporated by reference to Exhibit 10.9 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.4 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated by reference to Exhibit 10.12 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.5 -- Stone Energy Corporation Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 001-12074)).
10.6 -- Third Amended and Restated Credit Agreement between the Registrant, the financial institutions named therein and NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997 (incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 001-12074)).
+10.7 -- Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
10.8 -- Term Loan Agreement, dated November 30, 1995, between the Registrant and First National Bank of Commerce (incorporated by reference to Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended and Restated Effective as of May 15, 1997 (incorporated by reference to Exhibit 10.9 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 001-12074)).
10.10 -- First Amendment and Restatement of the Third Amended and Restated Credit Agreement between the Registrant, the financial institutions named therein and NationsBank of Texas, N.A., as Agent, dated as of March 31, 1998 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 001-12074)).
21.1 -- Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Financial Data Schedule
- ------------ * Filed herewith. + Identifies management contracts and compensatory plans or arrangements.
(B) REPORTS ON FORM 8-K
None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act, as amended, the Registrant has duly caused this Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Lafayette, State of Louisiana, on the 27th day of March 2000.
STONE ENERGY CORPORATION
By: /s/ JAMES H. STONE ------------------------------ James H. Stone Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act, this Form 10-K has been signed by the following persons in the capacities and on the dates indicated.
Report of Independent Public Accountants................................
Consolidated Balance Sheet of Stone Energy Corporation as of December 31, 1999 and 1998...........................................
Consolidated Statement of Operations of Stone Energy Corporation for the years ended December 31, 1999, 1998 and 1997.................
Consolidated Statement of Cash Flows of Stone Energy Corporation for the years ended December 31, 1999, 1998 and 1997.................
Consolidated Statement of Changes in Equity of Stone Energy Corporation for the years ended December 31, 1999, 1998 and 1997.................
Notes to Consolidated Financial Statements..............................
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Stone Energy Corporation:
We have audited the accompanying consolidated balance sheets of Stone Energy Corporation (a Delaware corporation) and subsidiary as of December 31, 1999 and 1998, and the related consolidated statements of operations, changes in equity and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Stone Energy Corporation and subsidiary as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana March 6, 2000
STONE ENERGY CORPORATION CONSOLIDATED BALANCE SHEET (Dollar amounts in thousands, except per share amounts)
STONE ENERGY CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS (Amounts in thousands, except per share amounts)
The accompanying notes are an integral part of this consolidated statement.
STONE ENERGY CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (Dollar amounts in thousands)
The accompanying notes are an integral part of this consolidated statement.
STONE ENERGY CORPORATION CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Dollar amounts in thousands)
The accompanying notes are an integral part of this consolidated statement.
STONE ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per share and price amounts)
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Stone Energy Corporation is an independent oil and gas company engaged in the acquisition, exploration, development and operation of oil and gas properties onshore and in shallow waters offshore Louisiana. We have been active in the Gulf Coast Basin since 1973, and have extensive geophysical, technical and operational expertise in this area. Our business strategy is focused on the acquisition of mature properties with an established production history that have significant exploitation and development potential. Since implementing this business strategy in 1990, we have acquired 19 properties that comprise our asset base including twelve offshore and seven onshore Louisiana. We are headquartered in Lafayette, Louisiana, with additional offices in New Orleans and Houston.
A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below:
CONSOLIDATION:
The consolidated financial statements include our accounts and our proportionate interest in certain partnerships: The Stone Petroleum Corporation ("TSPC"), a wholly owned subsidiary organized in June 1981 and TSPC's proportionate share of managed limited partnerships. TSPC was dissolved during 1997 and the limited partnerships were dissolved on December 31, 1999. All intercompany balances at December 31, 1999 have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.
USE OF ESTIMATES:
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization, unevaluated property costs, estimated future net cash flows, taxes and contingencies.
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The fair value of cash and cash equivalents, net accounts receivable and accounts payable approximated book value at December 31, 1999. The fair value of the 8-3/4% Notes totaled $96,500 at December 31, 1999 and the cost to unwind our hedging contracts in place at December 31, 1999 was $3,107.
CASH AND CASH EQUIVALENTS:
We consider all highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.
MARKETABLE SECURITIES:
We retain a third-party investment firm to manage our portfolio of short-term marketable securities, which are actively and frequently bought and sold with the primary objective of generating profits on the short-term differences in prices. Thus, the related security investments are classified as trading securities, which are marked to market in accordance with Statement of Financial Accounting Standards No. 115 ("SFAS No. 115"). All realized and unrealized gains and losses are included in current operating results. The net unrealized loss on the portfolio for the year ended December 31, 1999 was immaterial. The securities included in the portfolio are primarily U.S. Treasury obligations and mortgage-backed securities with an average maturity of not more than 360 days.
NOTE 1--ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
OIL AND GAS PROPERTIES:
We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs and general and administrative costs (less any reimbursements for such costs), incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. Fees received from managed partnerships for providing such services are accounted for as a reduction of capitalized costs. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred.
As required by the Securities and Exchange Commission, under the full cost method of accounting we are required to periodically compare the present value of the estimated net cash flows from proved reserves (based on current commodity prices) to the net capitalized costs of proved oil and gas properties. If the net capitalized costs of the proved oil and gas properties exceed the estimated discounted net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. Due to the impact of low year-end commodity prices on December 31, 1998 reserve values, we recorded an $89,135 reduction in the carrying value of our oil and gas properties at December 31, 1998.
Our investment in oil and gas properties is amortized using the future gross revenue method, a unit of production method, whereby the annual provision for depreciation, depletion and amortization is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development, restoration, dismantlement and abandonment costs. Transactions involving sales of reserves in place, unless extraordinarily large portions of reserves are involved, are recorded as adjustments to accumulated depreciation, depletion and amortization.
Oil and gas properties included $17,182 and $7,726 of unevaluated properties and related costs that were not being amortized at December 31, 1999 and 1998, respectively. These costs were associated with the acquisition and evaluation of unproved properties and major development projects expected to entail significant costs to ascertain quantities of proved reserves. We believe that a majority of unevaluated properties at December 31, 1999 will be evaluated within one to 24 months. The excluded costs and related proved reserves will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest capitalized on unevaluated properties during the years ended December 31, 1999 and 1998 was $320 and $606, respectively.
BUILDING AND LAND:
Building and land are recorded at cost. Our office building is being depreciated on the straight-line method over its estimated useful life of 39 years.
FIXED ASSETS:
Fixed assets at December 31, 1999 and 1998 included approximately $1,900 and $1,022, respectively, of computer hardware and software costs, net of accumulated depreciation. These costs are being depreciated on the straight-line method over an estimated useful life of 5 years.
OTHER ASSETS:
Other assets at December 31, 1999 and 1998 included approximately $2,910 and $3,183, respectively, of deferred financing costs, net of accumulated amortization, related to the sale of the 8-3/4% Notes (see Note 7). These costs are being amortized over the life of the Notes using the effective interest method.
NOTE 1--ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
EARNINGS PER COMMON SHARE:
Basic net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year. Diluted net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year plus the weighted-average number of dilutive stock options granted to outside directors and certain employees. There were 320,000 dilutive shares for the twelve-month period ending December 31, 1999, and there were no dilutive shares during 1998 and 206,000 dilutive shares during 1997.
Options that were considered antidilutive because the exercise price of the stock exceeded the average price for the applicable period totaled approximately 2,806 shares and 562 shares during 1999 and 1997, respectively. All options were considered antidilutive in 1998 due to our net loss incurred in that year.
GAS PRODUCTION REVENUES:
We record as revenue only that portion of gas production sold and allocable to our ownership interest in the related well. Any gas production proceeds received in excess of our ownership interest are reflected as a liability in the accompanying consolidated financial statements.
Revenues relating to net undelivered gas production to which we are entitled but for which we have not received payment are not recorded in the consolidated financial statements until compensation is received. These amounts at December 31, 1999, 1998 and 1997 were immaterial.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
From time to time, we utilize hedging activities to reduce the effect of product price volatility. These transactions are accounted for as increases or decreases in revenues from oil and gas production in the financial statements (See Note 9).
INCOME TAXES:
Income taxes are accounted for in accordance with SFAS No. 109. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the future gross revenue method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, and different reporting periods used in accounting for income and costs arising from oil and gas operations conducted through tax partnerships.
NEW ACCOUNTING STANDARDS:
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards that require every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. We expect to adopt SFAS No. 133 on January 1, 2001. The adoption may create volatility in equity through changes in other comprehensive income due to the marking to market of our hedging contracts (See Note 9); however, we believe these instruments will be treated as hedges under SFAS No. 133 and thus we do not anticipate that the standard will have a material impact on our results of operations.
NOTE 2 -- ACCOUNTS RECEIVABLE:
In our capacity as operator, manager and/or sponsor for our partners and other co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable was comprised of the following amounts:
December 31, ----------------------------------------------- 1999 1998 --------------------- -------------------- Accounts Receivable: Managed partnerships........... $ - $1,882 Other co-venturers............. 6,019 5,885 Trade.......................... 23,270 18,716 Officers and employees......... 27 3 Unbilled accounts receivable... 413 317 --------------------- -------------------- $29,729 $26,803 ===================== ====================
NOTE 3 -- SALES TO MAJOR CUSTOMERS:
Our production is sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold 10% or more of our total oil and gas revenues during each of the twelve-month periods ended:
December 31, -------------------------------------- 1999 1998 1997 ---- ---- ---- Amoco Energy Trading Corporation - 14% - Columbia Energy Services 28% - - Conoco, Incorporated - 24% - Engage Energy US LP 12% - - Genesis Crude Oil LP 12% - 16% Natural Gas Clearinghouse - - 18% Northridge Energy Marketing 22% 14% -
Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production.
NOTE 4--INVESTMENT IN OIL AND GAS PROPERTIES:
The following table discloses certain financial data relative to our oil and gas producing activities, which are located onshore and offshore the continental United States:
(1) Total costs incurred during 1999 included non-cash additions of $20,272 related to acquisitions made through production
NOTE 4--INVESTMENT IN OIL AND GAS PROPERTIES: (Continued)
The following table discloses financial data associated with capitalized unevaluated costs as of December 31, 1999:
NOTE 5--INCOME TAXES:
We follow the provisions of SFAS No. 109, "Accounting For Income Taxes," which provides for recognition of deferred taxes for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a "valuation allowance." An analysis of our deferred tax asset (liability) follows:
For tax reporting purposes, operating loss carryforwards totaled $15,909 at December 31, 1999. If not utilized, such carryforwards would begin expiring in 2003 and would completely expire by the year 2018. In addition, we had $12,034 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized.
During 1999, our provision for income taxes was net of a $1,460 reduction in deferred taxes relative to estimates of tax basis that were resolved during 1999. Reconciliations between the statutory federal income tax expense rate and our effective income tax expense rate as a percentage of income before income taxes were as follows:
NOTE 6 - PRODUCTION PAYMENTS:
In June 1999, we acquired a 100% working interest in the Lafitte Field by executing an agreement that included a dollar-denominated production payment to be satisfied through the sale of production from the purchased property. At that time, we recorded a production payment of $4,600 representing the estimated discounted present value of production payments to be made. As provided for in a separate agreement, on September 23, 1999, Goodrich Petroleum Company, L.L.C. exercised its option to participate for a 49% working interest in the Lafitte Field resulting in a reduction of the production payment to $2,346 at September 30, 1999. At December 31, 1999, the production payment associated with this transaction still totaled $2,346.
In July 1999, we acquired an additional working interest in East Cameron Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a volumetric production payment. This agreement requires that 7.3 MMcf of gas per day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have been distributed. At the transaction date, we recorded a volumetric production payment of $17,926 representing the estimated discounted cash flows associated with the specific production volumes to be delivered. We amortize the volumetric production payment as specified deliveries of gas are made to the seller and recognize non-cash revenue in the form of gas production revenues. At December 31, 1999, the volumetric production payment was $14,938 and $2,988 had been recognized as gas revenue during 1999.
NOTE 7--LONG-TERM DEBT:
Long-term debt consisted of the following at:
At December 31, 1999, there were no minimum principal payments due for the next five years.
In September 1997, we completed an offering of $100,000 principal amount 8-3/4% Senior Subordinated Notes (the "Notes") due September 15, 2007 with interest payable semiannually. At December 31, 1999, $2,601 had been accrued in connection with the March 2000 interest payment. The Notes were sold at a discount for an aggregate price of $99,283 and the net proceeds from the offering were used to repay amounts outstanding under our bank credit facility and for other general corporate purposes. There are no sinking fund requirements on the Notes and they are redeemable at our option, in whole or in part, at 104.375% of their principal amount beginning September 15, 2002, and thereafter at prices declining annually to 100% on and after September 15, 2005. Provisions of the Notes include, without limitation, restrictions on liens, indebtedness, asset sales and other restricted payments.
On August 3, 1999, we used a portion of the net proceeds from our recent stock offering (Note 10) to repay the outstanding borrowings under our credit facility. At December 31, 1999, the borrowing base under the facility had no outstanding borrowings and outstanding letters of credit totaling $7,522 had been issued pursuant to the facility. The borrowing base limitation, which is currently $140,000, is re-determined periodically and is based on a borrowing base amount established by the banks for our oil and gas properties. In February 2000, our bank group increased our credit facility from $150,000 to $200,000 and extended the maturity date from July 30, 2001 to July 30, 2005. The terms of this agreement contain, among other provisions, requirements for maintaining defined levels of working capital and tangible net worth.
In November 1995, we executed a term loan agreement with Bank One in the original principal amount of $3,250 for the purchase of the RiverStone building, the majority of which we use for our Lafayette office. During 1999, we repaid this loan with borrowings under our bank credit facility.
NOTE 8--TRANSACTIONS WITH RELATED PARTIES:
We received certain fees as a result of our function as managing partner of certain partnerships. For the years ended December 31, 1999, 1998 and 1997, management fees and overhead reimbursements from partnerships totaled $224, $834 and $868, respectively, the majority of which was treated as a reduction of the investment in oil and gas properties. These partnerships were dissolved on December 31, 1999. All participants in the partnerships, including James H. Stone and Joe R. Klutts, received overriding royalty interests in the related properties in exchange for their partnership interests.
Until their dissolution, we collected and distributed production revenues as managing partner for the partnerships' interests in oil and gas properties.
Our interests in certain oil and gas properties are burdened by various net profit interests granted at the time of acquisition to certain of our officers and other employees. Such net profit interest owners do not receive any cash distributions until we have recovered all acquisition, development, financing and operating costs. We believe the estimated value of these interests at the time of acquisition is not material to our financial position or results of operations.
Certain officers and directors and their affiliates are working interest owners in properties operated by us and are billed and pay their proportionate share of drilling and operating costs in the normal course of business.
NOTE 9--HEDGING ACTIVITIES:
We engage in futures contracts with certain of our production volumes. These futures contracts are considered to be hedging activities and, as such, monthly settlements on these contracts are reflected in revenues from oil and gas production. In order to consider these futures contracts as hedges, (i) we must designate the futures contract as a hedge of future production and (ii) the contract must reduce exposure to the risk of changes in prices. Changes in the market value of futures contracts treated as hedges are not recognized in income until the hedged item is also recognized in income. If the above criteria are not met, we will record the market value of the contract at the end of each month and recognize a related increase or decrease in oil and gas revenues. Any proceeds received or paid relating to terminated contracts or contracts that have been sold are amortized over the original contract period and reflected in revenues from oil and gas production. We enter into hedging transactions for the purpose of securing a price for a portion of future production that is acceptable at the time the transaction is entered into. The primary objective of these activities is to reduce the exposure to the possibility of declining oil and gas prices during the term of the hedge.
We currently utilize two forms of hedging contracts: fixed price swaps and collars. Fixed price swaps typically provide for monthly payments by us (if prices rise) or to us (if prices fall) based on the difference between the strike price and the agreed-upon average of NYMEX prices. For collars, monthly payments are made by us if NYMEX prices rise above the ceiling price and to us if NYMEX prices fall below the floor price. Oil contracts typically settle using the average of the daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices for near month NYMEX futures contracts for the three days prior to the settlement date. Because our properties are located in the Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely match changes in market prices for our production.
NOTE 9--HEDGING ACTIVITIES: (Continued)
As of March 15, 2000, our open hedge positions were:
For the years ended December 31, 1999, 1998 and 1997, we realized net increases (decreases) in oil and gas revenues related to hedging transactions of ($4,329), $4,265 and ($569), respectively.
NOTE 10--COMMON STOCK:
On July 28, 1999, we completed a secondary offering of 3.16 million shares of our common stock at a price to the public of $43.75 per share. After payment of the underwriting discount and estimated expenses, we received net proceeds of $130,760. The proceeds will ultimately be used to fund specifically identified exploration and development activities, to finance potential property acquisitions and for other general corporate purposes. We reduced indebtedness under our credit facility pending such uses.
During 1998, our Board of Directors authorized the adoption of a stockholder rights plan to protect and advance our interests and those of our stockholders in the event of a proposed takeover. The plan provides for the issuance of one right for each outstanding share of common stock. The rights will become exercisable only if a person or group acquires 15% or more of our outstanding voting stock or announces a tender or exchange offer that would result in ownership of 15% or more of the voting stock. The rights were issued on October 26, 1998 to stockholders of record on that date, and expire on September 30, 2008.
NOTE 11--COMMITMENTS AND CONTINGENCIES:
We lease office facilities in New Orleans, Louisiana and Houston, Texas under the terms of long-term, non-cancelable leases expiring on April 4, 2003 and May 31, 2004, respectively. Additionally, we lease automobiles under the terms of non-cancelable leases expiring at various dates through 2002. The minimum net annual commitments under all leases, subleases and contracts noted above at December 31, 1999 are as follows:
2000..................................................................... $421 2001..................................................................... 411 2002..................................................................... 393 2003..................................................................... 324 2004..................................................................... 127 Thereafter............................................................... -
Rent expense for the years ended December 31, 1999, 1998 and 1997 was approximately $268, $132 and $118, respectively.
NOTE 11--COMMITMENTS AND CONTINGENCIES: (Continued)
Until December 31, 1999, we were the managing general partner of eight partnerships and are contingently liable for any recourse debts and other liabilities that resulted from their operations until dissolution. We are not aware of the existence of any such liabilities that would have a material impact on future operations.
In August 1989, we were advised by the EPA that it believed we were a potentially responsible party (a "PRP") for the cleanup of an oil field waste disposal facility located near Abbeville, Louisiana, which was included on CERCLA's National Priority List (the "Superfund List") by the EPA in March 1989. Although we did not dispose of wastes or salt water at this site, the EPA contends that transporters of salt water may have rinsed their trucks' tanks at this site. By letter dated December 9, 1998, the EPA made demand for cleanup costs on 23 of the PRP's, including us, who had not previously settled with the EPA. Since that time we, together with other PRPs, have been negotiating the settlement of our respective liability for environmental conditions at this site with the U.S. Department of Justice. Given the number of PRP's at this site and the current satisfactory progress of these negotiations, we do not believe that any liability for this site would have a material adverse affect on our financial condition.
We are contingently liable to a surety insurance company in the aggregate amount of $14,821 relative to bonds issued on our behalf to the MMS and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance company that we will operate offshore in accordance with MMS rules and regulations and perform certain plugging and abandonment obligations as specified by the applicable working interest purchase and sale agreements.
We are also named as a defendant in certain lawsuits and are a party to certain regulatory proceedings arising in the ordinary course of business. We do not expect these matters, individually or in the aggregate, to have a material adverse effect on our financial condition.
OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties of offshore facilities to provide financial assurance in the amount of $35,000 to cover potential OPA liabilities. This amount can be increased up to $150,000 if a formal risk assessment indicates that an amount higher than $35,000 should be required. We do not anticipate that we will experience any difficulty in continuing to satisfy the MMS's requirements for demonstrating financial responsibility under OPA.
NOTE 12--EMPLOYEE BENEFIT PLANS:
We have entered into deferred compensation and disability agreements with certain of our employees whereby we have purchased split-dollar life insurance policies to provide certain retirement and death benefits for our employees and death benefits payable to us. The aggregate death benefit of the policies was $3,339 at December 31, 1999, of which $1,975 was payable to employees or their beneficiaries and $1,364 was payable to us. Total cash surrender value of the policies, net of related surrender charges at December 31, 1999, was approximately $1,117. Additionally, the benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 1999, the liability for such vested benefits was approximately $870. The difference between the actuarial determined liability for retirement benefits or the vested amounts, where applicable, and the net cash surrender value has been recorded as an other long-term liability.
We have adopted a series of incentive compensation plans designed to align the interests of our directors and employees with those of our stockholders. The following is a brief description of each of the plans:
i. The Annual Incentive Compensation Program provides for an annual incentive bonus that ties incentives to the annual return on our Common Stock, to a comparison of the price performance of our Common Stock to the average annual return on the shares of stock of a peer group of companies with which we compete and to the growth in our net earnings, net cash flows and net asset value. Incentive bonuses are awarded to participants based upon individual performance factors.
NOTE 12--EMPLOYEE BENEFIT PLANS: (Continued)
ii. The Nonemployee Directors' Stock Option Plan provides for the issuance of up to 250,000 shares of Common Stock upon the exercise of such options granted pursuant to this plan. Generally, options outstanding under the Nonemployee Directors' Stock Option Plan: (a) are granted at prices that equate to the fair market value of the Common Stock on date of grant, (b) vest ratably over a three year service vesting period, and (c) expire five years subsequent to award.
iii. The 1999 Stock Option Plan provides for 300,000 shares of Common Stock to be reserved for issuance pursuant to this plan. Under this plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees other than officers. All such options: (a) must have an exercise price of not less than the fair market value of the Common Stock on the date of grant, (b) vest ratably over a five year service vesting period, and (c) expire ten years subsequent to award.
iv. The 1993 Stock Option Plan (as amended and restated) provides for 1,170,000 shares of Common Stock to be reserved for issuance pursuant to this plan. Under this plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options. All such options: (a) must have an exercise price of not less than the fair market value of the Common Stock on the date of grant, (b) vest ratably over a five year service vesting period, and (c) expire ten years subsequent to award.
v. The 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee's deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 1999, 1998 and 1997, we contributed $313, $270 and $207, respectively, to the plan.
During the third quarter of 1998, our Board of Directors elected to reprice all non-Director employee stock options that had an exercise price above the then market value of $26.00 per share. As a result, 265,000 stock options, which were granted to non-Director employees during 1997 and 1998, were repriced from a weighted average exercise price of $29.35 per share to the then market value of $26.00 per share.
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," which became effective with respect to us in 1996. Under SFAS No. 123, companies can either record expense based on the fair value of stock-based compensation upon issuance or elect to remain under the current Accounting Principles Board Opinion No. 25 ("APB 25") method whereby no compensation cost is recognized upon grant if certain requirements are met. We have continued to account for our stock-based compensation under APB 25. However, pro forma disclosures as if we adopted the cost recognition requirements under SFAS No. 123 are presented below.
If the compensation cost for the 1999, 1998 and 1997 grants for stock-based compensation plans had been determined consistent with SFAS No. 123, our 1999, 1998 and 1997 net income (loss) and basic and diluted earnings (loss) per common share would have approximated the pro forma amounts below:
NOTE 12--EMPLOYEE BENEFIT PLANS: (Continued)
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to grants prior to 1995, and additional awards in the future are anticipated.
A summary of stock options as of December 31, 1999, 1998 and 1997 and changes during the years ended on those dates is presented below. The table reflects the effects of repricing certain options granted during 1997 and 1998.
The fair value of each option granted during the periods presented is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: (a) dividend yield of 0%, (b) expected volatility of 41.59%, 43.90% and 41.20% in the years 1999, 1998 and 1997, respectively, (c) risk-free interest rate of 6.32%, 5.50% and 6.04% in the years 1999, 1998 and 1997, respectively, and (d) expected life of 10 years for employee options and five years for director options.
The following table summarizes information regarding stock options outstanding at December 31, 1999:
NOTE 13--OIL AND GAS RESERVE INFORMATION - UNAUDITED:
A majority of our net proved oil and gas reserves at December 31, 1999 have been estimated by independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.
Proved natural gas reserves at December 31, 1999 excluded 6.7 Bcf of gas dedicated to a production payment. The excluded natural gas reserves were net of 1.3 Bcf of gas that was produced relative to the production payment from July to December 1999. Also excluded are the related estimated future net cash flows and the present value of estimated future net cash flows of $16.6 million and $14.8 million, respectively.
The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate) and natural gas, all located onshore and offshore the continental United States:
The following tables present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by the FASB. The oil, condensate and gas price structure utilized to project future net cash flows reflects current prices at each year-end and has been escalated only where known and determinable price changes are provided by contracts and law. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
NOTE 13--OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
NOTE 14--SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
(a) Includes a pre-tax, non-cash ceiling test write-down of $89,135.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used in this Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
Bbtu. One billion Btus.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
EBITDA. Represents net income attributable to common stock plus interest, income taxes, depreciation, depletion and amortization and non-cash ceiling test write-downs of oil and gas properties.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Farmin or farmout. An agreement under which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farmin" while the interest transferred by the assignor is a "farmout."
Finding costs. Costs associated with acquiring and developing proved oil and gas reserves which are capitalized by the Company pursuant to generally accepted accounting principles, excluding any capitalized general and administrative expenses.
Gross acreage or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
Mcf/d. One thousand cubic feet of gas per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
G-1 GLOSSARY OF CERTAIN INDUSTRY TERMS--(Continued)
MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.
MMcf/d. One million cubic feet of gas per day.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Present value. When used with respect to oil and gas reserves, present value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Production payment. An obligation of the purchaser of a property to pay a specified portion of gross revenues less related production taxes and transportation costs of the purchased property interest to the seller of the property.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude 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. Reserves that are expected to be recovered from new wells on developed acreage where the subject reserves cannot be recovered without drilling additional wells.
Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production.
Tcf. One trillion cubic feet of 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 gas regardless of whether such acreage contains proved reserves.
Volumetric production payment. An obligation of the purchaser of a property to deliver a specific volume of production, free and clear of all costs, to the seller of the property.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
G-2
EXHIBIT INDEX
Exhibit Number Description - ------- -----------
3.1 -- Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as of October 15, 1998, between the Company and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A (File No. 001-12074)).
4.2 -- Indenture between Stone Energy Corporation and Texas Commerce Bank, National Association dated as of September 19, 1997 (incorporated by reference to Exhibit 4.1 to the Registrant's Registration Statement on Form S-4 dated October 22, 1997 (File No. 333-38425)).
+10.1 -- Stone Energy Corporation 1993 Nonemployee Directors' Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.2 -- Deferred Compensation and Disability Agreements between TSPC and D. Peter Canty dated July 16, 1981, and between TSPC and Joe R. Klutts and James H. Prince dated August 23, 1981 and September 20, 1981, respectively (incorporated by reference to Exhibit 10.8 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.3 -- Conveyances of Net Profits Interests in certain properties to D. Peter Canty and James H. Prince (incorporated by reference to Exhibit 10.9 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.4 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated by reference to Exhibit 10.12 to the Registrant's Registration Statement on Form S-1 (Registration No. 33-62362)).
+10.5 -- Stone Energy Corporation Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 001-12074)).
10.6 -- Third Amended and Restated Credit Agreement between the Registrant, the financial institutions named therein and NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997 (incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 001-12074)).
+10.7 -- Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
10.8 -- Term Loan Agreement, dated November 30, 1995, between the Registrant and First National Bank of Commerce (incorporated by reference to Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended and Restated Effective as of May 15, 1997 (incorporated by reference to Exhibit 10.9 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 001-12074)).
10.10 -- First Amendment and Restatement of the Third Amended and Restated Credit Agreement between the Registrant, the financial institutions named therein and NationsBank of Texas, N.A., as Agent, dated as of March 31, 1998 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 001-12074)).
21.1 -- Subsidiaries of the Registrant (incorporated by reference to Exhibit 21.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Financial Data Schedule
- ------------ * Filed herewith. + Identifies management contracts and compensatory plans or arrangements.