Item 1. Business
General
Abraxas Petroleum Corporation is an independent energy company engaged primarily in the acquisition, exploration, exploitation and production of crude oil and natural gas. Since January 1, 1991, our principal means of growth has been through the acquisition and subsequent development and exploitation of producing properties and related assets. As a result of our historical acquisition activities, we have a substantial inventory of low risk exploration and development opportunities, the development of which is critical to the maintenance and growth of our current production levels. We seek to complement our acquisition and development activities by selectively participating in exploration projects with experienced industry partners.
Our principal areas of operation are Texas and western Canada. At December 31, 1999, we owned interests in 1,406,412 gross acres (904,908 net acres) and operated properties accounting for 69% of our PV-10, affording us substantial control over the timing and incurrence of operating and capital expenditures. PV-10 means estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the Securities and Exchange Commission. An Mcf is one thousand cubic feet of natural gas. MMcf is used to designate one million cubic feet of natural gas and Bcf refers to one billion cubic feet of natural gas. Mcfe means thousands of cubic feet of natural gas equivalents, using a conversion ratio of one barrel of crude oil to six Mcf of natural gas. MMcfe means millions of cubic feet of natural gas equivalents and Bcfe means billions of cubic feet of natural gas equivalents. Mmbtu means million British Thermal Units. The term Bbl means one barrel of crude oil and MBbls is used to designate one thousand barrels of crude oil.
At December 31, 1999, our estimated total proved reserves were 265.9 Bcfe and aggregate PV-10 was $257.1 million. As of December 31, 1999, we had net natural gas processing capacity of 121 MMcf per day through our 20 natural gas processing plants and compression facilities in Canada, giving us substantial control over our Canadian production and marketing activities.
Business Strategy
Our primary business objectives are to increase reserves, production and cash flow through the following:
o IMPROVED LIQUIDITY. Since January 1999, we have sought to improve our liquidity in order to allow us to meet our debt service requirements and to maintain and increase existing production.
o Our sale in March 1999 of our 12.875% Senior Secured Notes due 2003 (the "first lien notes") allowed us to refinance our bank debt, meet our near-term debt service requirements and make limited crude oil and natural gas capital expenditures.
o In October 1999, we sold a dollar denominated production payment for $4.0 million relating to existing natural gas wells in the Edwards Trend in South Texas to a unit of Southern Energy, Inc. ("Southern") and in January 2000, we sold an additional production payment for $2.0 million relating to additional natural gas wells in the Edwards Trend to Southern. We have the ability to sell up to $50 million to Southern for drilling opportunities in the Edwards Trend.
o In December 1999, Abraxas and our wholly-owned Canadian subsidiary, Canadian Abraxas Petroleum Limited, completed an exchange offer whereby we exchanged our 11 1/2% Senior Secured Notes due 2004, Series A (the "second lien notes"), common stock, and contingent value rights for approximately 98.43% of our outstanding 11 1/2% Senior Notes due 2004, Series D (the "old notes"). The exchange offer reduced our long-term debt by approximately $76 million after expenses.
o In March 2000, we sold our interest in certain crude oil and natural gas properties that we owned and operated in Wyoming. Simultaneously, a limited partnership of which one of our subsidiaries was the general partner sold its interest in crude oil and natural gas properties in the same area. Our net proceeds from these transactions were approximately $34.0 million.
o We are continuing to rationalize our significant non-core Canadian assets to allow us to continue to grow while reducing our debt. We may sell non-core assets or seek partners to fund a portion of the exploration costs of undeveloped acreage and are considering other potential strategic alternatives.
o LOW COST OPERATIONS. We seek to maintain low operating and G&A expenses per Mcfe by operating a majority of our producing properties and related assets and by maintaining a high rate of production on a per well basis. As a result of this strategy, we have achieved per unit operating and G&A expenses that compare favorably with similar companies.
o EXPLOITATION OF EXISTING PROPERTIES. We will allocate a portion of our operating cash flow to the exploitation of our producing properties. We believe that the proximity of our undeveloped reserves to existing production makes development of these properties less risky and more cost-effective than other drilling opportunities available to us. Given our high degree of operating control, the timing and incurrence of operating and capital expenditures is largely within our discretion. Our capital expenditure budget for 2000 for existing leaseholds is approximately $49.6 million including approximately $16.3 million for our horizontal drilling exploitation program. We currently have horizontal drilling or completion operations in West Texas, South Texas, Wyoming and Kansas. We focus our horizontal drilling activities in deep wells containing known columns of hydrocarbons. We believe that this drilling method provides increased production at low incremental costs and very high rates of return.
o PRODUCING PROPERTY ACQUISITIONS. As cash flow permits, we intend to continue to acquire producing crude oil and natural gas properties that can increase cash flow, production and reserves through operational improvements and additional development.
o FOCUSED EXPLORATION ACTIVITY. We intend to allocate a portion of our capital budget to the drilling of exploratory wells that have high reserve potential. We believe that by devoting a relatively small amount of capital to high impact, high risk projects while reserving the majority of our available capital for development projects, we can reduce drilling risks while still benefiting from the potential for significant reserve additions.
MARKETS AND CUSTOMERS
The revenue generated by our operations is highly dependent upon the prices of, and demand for, crude oil and natural gas. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we received for our crude oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors beyond our control including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic regulation, legislation and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenue, profitability and cash flow from operations.
In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, from time to time we have entered into fixed price delivery contracts, financial swaps and crude oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, we may sell a futures contract and thereafter either (i) make physical delivery of crude oil or natural gas to comply with such contract or (ii) buy a matching futures contract to unwind our futures position and sell our production to a customer. These contracts may expose us to the risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase or deliver the contracted quantities of crude oil or natural gas, or a sudden, unexpected event materially impacts crude oil or natural gas prices. These contracts may also restrict our ability to benefit from unexpected increases in crude oil and natural gas prices. You should read the discussion under "Management's Discussion and Analysis of Financial Condition And Results of Operations -- Liquidity and Capital Resources," and "Quantitative and Qualitative Disclosures about Market Risk; Commodity Price Risk" for more information regarding our hedging activities.
Substantially all of our crude oil and natural gas is sold at current market prices under short-term contracts, as is customary in the industry. During the year ended December 31, 1999, three purchasers accounted for approximately 58% of our crude oil and natural gas sales and approximately 56% of our gas processing revenues. We believe that there are numerous other companies available to purchase our crude oil and natural gas and that the loss of any or all of these purchasers would not materially affect our ability to sell crude oil and natural gas. The prices we receive for the sale of our crude oil and natural gas are subject to our hedging activities. You should read the discussion under "Management's Discussion and Analysis of Financial Condition And Results of Operations -- Liquidity and Capital Resources" and "Quantitative and Qualitative Disclosures about Market Risk; Commodity Price Risk" for more information regarding our hedging activities.
RISK FACTORS
WE LACK LIQUIDITY DUE TO OUR REDUCED CASH FLOW. We have historically funded our operations primarily through cash flow from operations and borrowings under our bank credit facilities and other credit sources. Due to severely depressed crude oil and natural gas market prices, our cash flow from operations in 1999 was substantially reduced. In 1999, our sale of the first lien notes, the production payment to Southern and certain non-core properties together with cash generated by operations provided us with the liquidity necessary to service our debt and pay operating expenses. We anticipate that we will have three principal sources of liquidity during the next 12 months: (i) cash on hand including the net proceeds from the sale of the Wyoming properties, (ii) cash generated by operations and (iii) the production payment with Southern. You should read the discussions under the heading "-- Our debt levels and our debt covenants may limit our ability to pursue business opportunities and to obtain additional financing," "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and the Consolidated Financial Statements and the notes thereto included elsewhere in this report for more information regarding our indebtedness.
Our ability to raise funds through additional indebtedness will be substantially limited by the terms of the indenture governing the first lien notes, the indenture governing the old notes and the indenture governing the second lien notes, although many of the restrictive covenants contained in the indenture governing the old notes were eliminated in connection with the exchange offer.
The first lien notes indenture and the second lien notes indenture restrict, among other things, our ability to:
o incur additional indebtedness; o incur liens; o pay dividends or make certain other restricted payments; o consummate certain asset sales; o enter into certain transactions with affiliates; o merge or consolidate with any other person; or o sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of our assets.
Additionally, our ability to raise funds through additional indebtedness will be limited because substantially all of our crude oil and natural gas properties and natural gas processing facilities are subject to a first lien or floating charge for the benefit of the holders of the first lien notes and a second lien or floating charge for the benefit of the holders of the second lien notes. We may also choose to issue equity securities or sell certain of our assets to fund our operations, although the first lien notes indenture and the second lien notes indenture will substantially limit our use of the proceeds of any such asset sales. Because of our diminished cash flow from operations and depressed prices for our common stock, we may not be able to obtain equity financing on satisfactory terms.
OUR DEBT LEVELS AND OUR DEBT COVENANTS MAY LIMIT OUR ABILITY TO PURSUE BUSINESS OPPORTUNITIES AND TO OBTAIN ADDITIONAL FINANCING. We have substantial indebtedness and debt service requirements. Our total debt and stockholders' (deficit) were $273.4 million and $(9.5) million, respectively, as of December 31, 1999. We may incur additional indebtedness in the future in connection with acquiring, developing and exploiting producing properties, although our ability to incur additional indebtedness is substantially limited by the terms of the first lien notes indenture and the second lien notes indenture. You should read the discussions under the heading "-- We lack liquidity due to our reduced cash flow," "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and the Consolidated Financial Statements and the notes thereto included elsewhere in this annual report for more information regarding our indebtedness.
Our high level of debt affects our operations in several important ways, including:
o A substantial amount of our cash flow from operations will be used to pay interest on the first lien notes, any outstanding old notes and the second lien notes;
o The covenants contained in the first lien notes indenture and the second lien notes indenture will limit our ability to borrow additional funds or to dispose of assets and may affect our flexibility in planning for, and reacting to, changes in our business, including possibly limiting acquisition activities;
o Our debt level may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, interest payments, scheduled principal payments, general corporate purposes or other purposes; and
o The terms of the first lien notes indenture, the old notes indenture and the second lien notes indenture will permit the holders of the first lien notes, any outstanding old notes and the second lien notes to accelerate payments upon an event of default or a change of control.
OUR ABILITY TO REPLACE PRODUCTION WITH NEW RESERVES IS HIGHLY DEPENDENT ON ACQUISITIONS OR SUCCESSFUL DEVELOPMENT AND EXPLORATION ACTIVITIES. The rate of production from crude oil and natural gas properties declines as reserves are depleted. Our proved reserves will decline as reserves are produced unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify
additional behind-pipe zones or secondary recovery reserves. Our future crude oil and natural gas production is therefore highly dependent upon our level of success in acquiring or finding additional reserves. We cannot assure you that our exploration and development activities will result in increases in reserves. Our operations may be curtailed, delayed or cancelled if we lack necessary capital and by other factors, such as title problems, weather, compliance with governmental regulations, mechanical problems or shortages or delays in the delivery of equipment.
Our ability to continue to acquire producing properties or companies that own such properties assumes that major integrated oil companies and independent oil companies will continue to divest many of their crude oil and natural gas properties. We cannot assure you that such divestitures will continue or that we will be able to acquire such properties at acceptable prices or develop additional reserves in the future. In addition, under the terms of the first lien notes indenture, the old notes indenture and the second lien notes indenture, our ability to obtain additional financing in the future for acquisitions and capital expenditures will be limited.
CRUDE OIL AND NATURAL GAS PRICE DECLINES AND THEIR VOLATILITY COULD ADVERSELY AFFECT OUR REVENUE, CASH FLOWS AND PROFITABILITY. Our revenue, profitability and future rate of growth depend substantially upon prevailing prices for crude oil and natural gas. Crude oil and natural gas prices fluctuate and until recently have declined significantly. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In 1999, we reduced our capital expenditures budget because of lower crude oil and natural gas prices. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that we can produce economically.
We enter into hedge agreements and other financial arrangements at various times to attempt to minimize the effect of crude oil and natural gas price fluctuations. We cannot assure you that such transactions will reduce risk or minimize the effect of any decline in crude oil or natural gas prices. Any substantial or extended decline in crude oil or natural gas prices would have a material adverse effect on our business and financial results. Hedging activities may limit the risk of declines in prices, but such arrangements may also limit additional revenues from price increases. You should read the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Liquidity and Capital Resources - Hedging Activities" for more information regarding our hedging activities.
LOWER CRUDE OIL AND NATURAL GAS PRICES INCREASE THE RISK OF CEILING LIMITATION WRITEDOWNS. We use the full cost method to account for our crude oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under full cost accounting rules, the net capitalized cost of crude oil and natural 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 market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation writedown." 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 crude oil and natural gas properties increases when crude oil and natural gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for our natural gas production. In 1999 , we recorded a writedown of $19.1 million ($11.9 million after tax) as a result of a downward adjustment to our proved reserves in Canada. We cannot assure you that we will not experience additional ceiling limitation writedowns in the future.
ESTIMATES OF OUR PROVED RESERVES AND FUTURE NET REVENUE ARE UNCERTAIN AND INHERENTLY IMPRECISE. This annual report contains estimates of our proved crude oil and natural gas reserves and the estimated future net revenue from such reserves. The process of estimating crude oil and natural gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any
significant variance could materially affect the estimated quantities and present value of reserves set forth in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues referred to in this annual report is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural 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 crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. For example, we reduced our 1999 capital expenditure budget. This reduction will delay cash flows and thereby reduce present value. In addition, the 10% discount factor, which is required by the SEC 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 crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor.
The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this document are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 1999. The average sales prices as of such date used for purposes of such estimates were $24.88 per Bbl of crude oil, $14.79 per Bbl of NGLs and $2.11 per Mcf of natural gas. This compares with $9.95 per Bbl of crude oil, $8.97 per Bbl of NGLs and $1.90 per Mcf of natural gas as of December 31, 1998. It is also assumed that we will make future capital expenditures of approximately $31.7 million in the aggregate, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.
WE HAVE EXPERIENCED RECURRING NET LOSSES. The following table shows the net losses we had in 1994, 1995, 1997, 1998 and 1999:
You should read the discussions under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our Consolidated Financial Statements and the notes thereto included elsewhere in this document for more information regarding these losses. We cannot assure you that we will become profitable in the future.
OUR CANADIAN OPERATIONS ARE SUBJECT TO THE RISKS OF CURRENCY FLUCTUATIONS AND IN SOME INSTANCES ECONOMIC AND POLITICAL DEVELOPMENTS. We have significant operations in Canada. The expenses of such operations are payable in Canadian dollars while most of the revenue from crude oil and natural gas sales is based upon U.S. dollar price indices. As a result, Canadian operations are subject to the risk of fluctuations in the relative values of the Canadian and U.S. dollars. We are also required to recognize foreign currency translation gains or losses related to the debt issued by our Canadian subsidiary because the debt is denominated in U.S. dollars and the functional currency of such subsidiary is the Canadian dollar. Our foreign operations may also be adversely affected by local political and economic developments, royalty and tax increases and other foreign laws or policies, as well as U.S. policies affecting trade, taxation and investment in other countries.
WE DEPEND ON OUR KEY PERSONNEL. We depend to a large extent on Robert L.G. Watson, our Chairman of the Board, President and Chief Executive Officer, for our management and business and financial contacts. The unavailability of Mr. Watson would have a materially adverse effect on our business. Mr. Watson has a five-year employment contract with Abraxas which provides that he can be terminated for cause only. Our success is also dependent upon our ability to employ and retain skilled technical personnel. While we have not experienced difficulties in employing or retaining such personnel, our failure to do so in the future could adversely affect our business.
ANTI-TAKEOVER PROVISIONS COULD MAKE A THIRD PARTY ACQUISITION OF ABRAXAS DIFFICULT. Abraxas' articles of incorporation and by-laws provide for a classified board of directors, with each member serving a three-year term and eliminate the ability of stockholders to call special meetings or take action by written consent. Abraxas has also adopted a stockholder rights plan. Each of the provisions in the articles of incorporation and by-laws and the stockholder rights plan could make it more difficult for a third party to acquire Abraxas without the approval of Abraxas' board. In addition, the Nevada corporate statute also contains certain provisions which could make an acquisition by a third party more difficult
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF CRUDE OIL AND NATURAL GAS DRILLING AND PRODUCTION ACTIVITIES. Crude oil and natural gas drilling and production activities are subject to numerous risks, many of which are beyond our control. These risks include the following:
o that no commercially productive crude oil or natural gas reservoirs will be found; o that crude oil and natural gas drilling and production activities may be shortened, delayed or canceled; and o that our ability to develop, produce and market our reserves may be limited by:
- title problems, - weather conditions, - compliance with governmental requirements, and - mechanical difficulties or shortages or delays in the delivery of drilling rigs, work boats and other equipment.
In the past, we have had difficulty securing drilling equipment in certain of our core areas. 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 crude oil and natural gas may be unprofitable. Dry wells and wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs are unprofitable. In addition, our properties may be susceptible to hydrocarbon draining from production by other operations on adjacent properties.
Our industry also experiences numerous operating risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, ruptures or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses also may result from injury or loss of life, severe damage to or destruction of property, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. 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.
WE OPERATE IN A HIGHLY COMPETITIVE INDUSTRY WHICH MAY ADVERSELY AFFECT OUR OPERATIONS. We operate in a highly competitive environment. Competition is particularly intense with respect to the acquisition of desirable undeveloped crude oil and natural gas properties. The principal competitive factors in the acquisition of such undeveloped crude oil and natural gas properties include the staff and data necessary to identify, investigate and purchase such properties, and the financial resources necessary to acquire and develop such properties. We compete with major and independent crude oil and natural gas companies for 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.
The principal resources necessary for the exploration and production of crude oil and natural gas are leasehold prospects under which crude oil and natural gas reserves may be discovered, drilling rigs and related equipment to explore for such reserves and knowledgeable personnel to conduct all phases of crude oil and natural gas operations. We must compete for such resources with both major crude oil and natural gas companies and independent operators. Although we believe our current operating and financial resources are adequate to preclude any significant disruption of our operations in the immediate future we cannot assure you that such materials and resources will be available to us.
We face significant competition for obtaining additional natural gas supplies for gathering and processing operations, for marketing NGLs, residue gas, helium, condensate and sulfur, and for transporting natural gas and liquids. Our principal competitors include major integrated oil companies and their marketing affiliates and national and local gas gatherers, brokers, marketers and distributors of varying sizes, financial resources and experience. Certain competitors, such as major crude oil and natural gas companies, have capital resources and control supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.
We compete against other companies in our natural gas processing business both for supplies of natural gas and for customers to which we sell our products. Competition for natural gas supplies is based primarily on location of natural gas gathering facilities and natural gas gathering plants, operating efficiency and reliability and ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price and delivery capabilities.
OUR CRUDE OIL AND NATURAL GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE AND LOCAL AND CANADIAN FEDERAL AND PROVINCIAL GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS. Matters regulated include discharge permits for drilling operations, drilling and abandonment bonds, 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 production. In order to conserve supplies of crude oil and natural gas, these agencies have restricted the rates of flow of crude oil and natural gas wells below actual production capacity. Federal, state, provincial and local laws regulate production, handling, storage, transportation and disposal of crude oil and natural gas, by-products from crude oil and natural gas and other substances and materials produced or used in connection with crude oil and natural gas operations. To date, our expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant. We believe that we are in substantial compliance with all applicable laws and regulations. However, the requirements of such laws and regulations are frequently changed. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.
SHARES ELIGIBLE FOR FUTURE SALE MAY DEPRESS OUR STOCK PRICE. At March 15, 2000, we had 22,595,016 shares of common stock outstanding of which 6,929,239 shares were held by affiliates, 1,890,000 shares of common stock subject to outstanding options granted under certain stock option plans (of which 696,202 shares were vested at March 15, 2000) and 13,500 shares issuable upon exercise of warrants. In addition, as part of the exchange offer, we issued CVRs which entitle the holders thereof to receive up to a total of 105,408,978 shares of our common stock if the price of our common stock does not reach certain target prices. The target price on December 21, 2000, is $5.64. If we elect to extend the target date to May 21, 2001 the target price will be $5.97
All of the shares of common stock held by affiliates are restricted or control securities under Rule 144 promulgated under the Securities Act of 1933, as amended (the "Securities Act"). The shares issuable pursuant to the CVRs are
exempt from registration under the Securities Act. The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act. The shares of the common stock issuable upon exercise of the warrants are subject to certain registration rights and, therefore, will be eligible for resale in the public market after a registration statement covering such shares has been declared effective. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair our ability to raise additional capital through the sale of equity securities.
USE OF OUR NET OPERATING LOSS CARRYFORWARDS MAY BE LIMITED. At December 31, 1999, the Company had, subject to the limitation discussed below, $94,573,000 of net operating loss carryforwards for U.S. tax purposes, of which it is estimated a maximum of $7,260,000 may be utilized before it expires, absent the application of Section 382(h) which allows built-in gains to offset carryforwards otherwise limited by Section 382 of the Internal Revenue Code of 1986, as amended, (Section 382). These loss carryforwards will expire from 2002 through 2018 if not utilized. At December 31, 1999, the Company had approximately $10,262,000 of net operating loss carryforwards for Canadian tax purposes of which $274,000 will expire in 2000, $3,542,000 will expire in 2001, $151,000 will expire in 2002 and $6,295,000 will expire in 2003-2005.
As a result of the acquisition of certain partnership interests and crude oil and natural gas properties in 1990 and 1991, an ownership change under Section 382 occurred in December 1991. Accordingly, it is expected that the use of the U.S. net operating loss carryforwards generated prior to December 31, 19991 of $4,909,000 will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an unrelated corporation. The use of net operating loss carryforwards of the acquired corporation of $837,000 acquired in the acquisition are limited to approximately $115,000 per year.
As a result of the issuance of additional shares of common stock for acquisitions and sales of common stock, an additional ownership change under Section 382 occurred in October 1993. Accordingly, it is expected that the use of all U.S. net operating loss carryforwards generated through October 1993 (including those subject to the 1991 and 1992 ownership changes discussed above) of $8,875,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following the issuance of additional shares, as described in Note 8 of the financial statements. It is expected that the annual use of U.S. net operating loss carryforwards subject to this Section 382 limitation will be limited to approximately $363,000, subject to the lower limitations described above. Future changes in ownership may further limit the use of the Company's carryforwards.
The annual Section 382 limitation may be increased during any year, within 5 years of a change in ownership, in which built-in gains that existed on the date of the change in ownership are recognized.
In addition to the Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, the Company has established a valuation allowance of $32,822,000 and $36,134,000 for deferred tax assets at December 31, 1998 and 1999, respectively.
REGULATION OF CRUDE OIL AND NATURAL GAS ACTIVITIES
Our operations are affected from time to time in varying degrees by political developments and federal, state, provincial and local laws and regulations. In particular, oil and gas production operations and economics are, or in the past have been, affected by price controls, taxes, conservation, safety, environmental, and other laws relating to the petroleum industry, by changes in such laws and by constantly changing administrative regulations.
PRICE REGULATIONS
In the recent past, maximum selling prices for certain categories of crude oil, natural gas, condensate and NGLs in the United States were subject to federal regulation. In 1981, all federal price controls over sales of crude oil, condensate and NGLs were lifted. In 1993, the Congress deregulated natural gas prices for all "first sales" of natural gas. As a result, all sales of our United States produced crude oil, natural gas, condensate and NGLs may be sold at market prices, unless otherwise committed by contract.
Crude oil and natural gas exported from Canada is subject to regulation by the National Energy Board ("NEB") and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB and the government of Canada. Crude oil and natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration, pursuant to an NEB license and Governor in Council approval.
The provincial governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from these provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and marketing considerations.
THE NORTH AMERICAN FREE TRADE AGREEMENT
On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of the United States, Canada and Mexico became effective. In the context of energy resources, Canada remains free to determine whether exports to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.
NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.
UNITED STATES NATURAL GAS REGULATION
Historically, interstate pipeline companies in the United States generally acted as wholesale merchants by purchasing natural gas from producers and reselling the gas to local distribution companies and large end users. Commencing in late 1985, the Federal Energy Regulatory Commission (the "FERC") issued a series of orders that have had a major impact on interstate natural gas pipeline operations, services, and rates, and thus have significantly altered the marketing and price of natural gas. The FERC's key rule making action, Order No. 636 ("Order 636"), issued in April 1992, required each interstate pipeline to, among other things, "unbundle" its traditional bundled sales services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and standby sales and gas balancing services), and to adopt a new ratemaking methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate markets natural gas as a merchant, it does so pursuant to private contracts in direct competition with all of the sellers, such as us; however, pipeline companies and their affiliates were not required to remain "merchants" of natural gas, and most of the interstate pipeline companies have become "transporters only," although many have affiliated marketers. In subsequent orders, the FERC largely affirmed the major features of Order 636. By the end of 1994, the FERC had concluded the Order 636 restructuring proceedings, and, in general, accepted rate filings implementing Order 636 on every major interstate pipeline. The federal appellate courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines. We do not believe that Order 636 and the related restructuring proceedings affect us any differently than other natural gas producers and marketers with which we compete.
In recent years the FERC also has pursued a number of other important policy initiatives which could significantly affect the marketing of natural gas in the United States. Some of the more notable of these regulatory initiatives include:
(1) a series of orders in individual pipeline proceedings articulating a policy of generally approving the voluntary divestiture of interstate pipeline owned gathering facilities by interstate pipelines to their affiliates (the so-called "spin down" of previously regulated gathering facilities to the pipeline's nonregulated affiliates),
(2) the completion of rule-making involving the regulation of pipelines with marketing affiliates under Order No. 497,
(3) various FERC orders adopting rules proposed by the Gas Industry Standards Board which are designed to further standardize pipeline transportation tariffs and business practices,
(4) a notice of proposed rulemaking that, among other things, proposes (a) to eliminate the cost-based price cap currently imposed on natural gas transactions of less than one year in duration, (b) to establish mandatory "transparent" capacity auctions of short-term capacity on a daily basis, and (c) to permit interstate pipelines to negotiate terms and conditions of service with individual customers,
(5) a notice of inquiry which continues the FERC's review of its regulatory policies with respect to the pricing of long-term pipeline transportation services by presenting a range of questions to the industry dealing with current cost-based pricing of new and existing capacity and alternative rate mechanism options, including the desirability of pricing interstate pipeline capacity utilizing market-based rates, incentive rates, or indexed rates, and
(6) a notice of proposed rulemaking that proposes generic procedures to expedite the FERC's handling of complaints against interstate pipelines with the goals of encouraging and supporting consensual resolutions of complaints and organizing the complaint procedures so that all complaints are handled in a timely and fair manner.
Several of these initiatives are intended to enhance competition in natural gas markets, although some, such as "spin downs," may have the adverse effect of increasing the cost of doing business on some in the industry, including us, as a result of the geographic monopolization of those facilities by their new, unregulated owners. As to all of these FERC initiatives, the ongoing, or, in some instances, preliminary and evolving nature of these regulatory initiatives makes it impossible at this time to predict their ultimate impact on our business. However, we do not believe that these FERC initiatives will affect us any differently than other natural gas procedures and marketers with which we compete.
Since Order 636 FERC decisions involving onshore facilities have been more liberal in their reliance upon traditional tests for determining what facilities are "gathering" and therefore exempt from federal regulatory control. In many instances, what was once classified as "transmission" may now be classified as "gathering." We ship certain of our natural gas through gathering facilities owned by others, including interstate pipelines, under existing long term contractual arrangements. Although these FERC decisions have created the potential for increasing the cost of shipping our gas on third party gathering facilities, our shipping activities have not been materially affected by these decisions.
Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows or may require pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. In certain circumstances, these rules permit oil pipelines to establish rates using traditional cost of service or other methods of rate making. We do not believe that these rules affect us any differently than other crude oil producers and marketers with which we compete.
Additional proposals and proceedings that might affect the natural gas industry in the United States are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The oil and gas industry historically has been very heavily regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.
STATE AND OTHER REGULATION
All of the jurisdictions in which we own producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions requiring permits for the drilling of wells and maintaining bonding requirements in order to drill or operate wells and provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units on an acreage basis and the density of wells which may be drilled and the unitization or pooling of crude oil and natural gas properties. In this regard, some states and provinces allow the forced pooling or integration of tracts to facilitate exploration while other states and provinces rely on voluntary pooling of lands and leases. In addition, state and provincial conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Some states, such as Texas and Oklahoma, have, in recent years, reviewed and substantially revised methods previously used to make monthly determinations of allowable rates of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the location at which we can drill.
State and provincial regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements, but does not generally entail rate regulation. In the United States, natural gas gathering has received greater regulatory scrutiny at both the state and federal levels in the wake of the interstate pipeline restructuring under Order 636. For example, on August 19, 1997, the Texas Railroad Commission enacted a Natural Gas Transportation Standards and Code of Conduct to provide regulatory support for the State's more active review of rates, services and practices associated with the gathering and transportation of gas by an entity that provides such services to others for a fee, in order to prohibit such entities from unduly discriminating in favor of their affiliates.
In the event we conduct operations on federal or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies. In addition, in the United States, the Minerals Management Service ("MMS") has recently issued a final rule to clarify the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, MMS will not allow deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS has been engaged in a three-year process of promulgating new rules and procedures for determining the value of oil produced from federal lands for purposes of calculating royalties owed to the government. The oil and gas industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase. We cannot predict what, if any, effect any new rule will have on our operations.
CANADIAN ROYALTY MATTERS
In addition to Canadian federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed preference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced.
From time to time the governments of Canada, Alberta and Saskatchewan have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging crude oil and natural gas exploration or enhanced planning projects.
Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing crude oil reserves in Alberta. Crude oil produced from horizontal extensions commenced at least five years after the well was originally spudded may qualify for a royalty reduction. A 24-month, 8,000 cubic metres exemption is available to production from a well that has not produced for a 12-month period, if resuming production after January 31, 1993. In addition, crude oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992, is entitled to a 12-month royalty exemption (to a maximum of CDN$1 million). Crude oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions.
The Alberta government also introduced the Third Tier Royalty with a base rate of 10% and a rate cap of 25% from oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30% and for old oil a base rate of 10% and a rate cap of 35%.
Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process. The royalty reserved to the Crown, subject to various incentives, is between 15% or 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory gas wells spudded or deepened after July 1, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.
In Alberta, a producer of crude oil or natural gas is entitled to credit against the royalties payable to the Crown by virtue of the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies between 75% for prices for crude oil at or below CDN $100 per cubic metre and 35% for prices above CDN $210 per cubic metre. The ARTC rate is currently applied to a maximum of CDN $2.0 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on average "par price", as determined by the Alberta Department of Energy for the previous quarterly period. On December 22, 1997, the Government of Alberta gave notice that they intended to review the ARTC program with expected changes to take effect prior to 2001.
The Government of Saskatchewan's fiscal regime for the oil and gas industry provides an incentive to encourage the drilling of new vertical oil wells through a revised royalty/tax structure for new vertical oil wells and incremental production from new or expanded water flood projects. This "third tier" Crown royalty rate is price sensitive and varies between heavy and non-heavy oil (from a minimum of 10% for heavy oil at a base price to a maximum of 35% for non-heavy oil at a price above the base price). Previous time-based royalty/tax holidays applicable to vertically drilled oil wells have been replaced with volume-based royalty/tax reduction incentives in which a maximum royalty of 5% will apply to various volumes depending on the depth and nature of the well (up to 25,000 cubic meters of oil in the case of deep exploratory wells). The maximum royalty applicable to the first 12,000 cubic meters of oil has been increased from 5% to 10% for production from certain horizontal wells. In addition, royalty/tax holidays for deep horizontal oil wells have been replaced with a 25,000 cubic meters volume incentive (5% maximum royalty). Oil production from qualifying reactivated oil wells are subject to a maximum new royalty rate of 5% for the first 5 years following re-activation in the case of wells reactivated after 1993 and shut-in or suspended prior to January 1, 1993. With respect to qualifying exploratory natural gas wells, the first 25 million cubic meters of natural gas produced will be subject to an incentive maximum royalty rate of 5%. On February 9, 1998, the Government of Saskatchewan announced further royalty incentive programs to encourage oil and gas exploration.
Producers of oil and natural gas in British Columbia are also required to
pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands respectively. The amount payable as a royalty in respect of oil depends on the vintage of the oil (whether it was produced from a pool discovered before or after October 31, 1975), the quantity of oil produced in a month and the value of the oil. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on a reference price which is the greater of the amount obtained by the producer and at prescribed minimum price. Gas produced in association with oil has a minimum royalty of 8% while the royalty in respect of other gas may not be less than 15%.
ENVIRONMENTAL MATTERS
Our operations are subject to numerous federal, state, provincial and local laws and regulations controlling the generation, use, storage, and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling, production, and gas processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as use of pits and plugging of abandoned wells; restrict injection of liquids into subsurface strata that may contaminate groundwater; and impose substantial liabilities for pollution resulting from our operations. Environmental permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.
In the United States, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and comparable state statutes impose strict, joint, and several liability on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that generated, disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA such persons or companies may be retroactively liable 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 common for neighboring land owners and other third parties to file claims for personal injury, property damage, and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize imposition of substantial civil and criminal penalties for failing to prevent surface and subsurface pollution, as well as to control the generation, transportation, treatment, storage and disposal of hazardous waste generated by oil and gas operations. Although CERCLA currently contains a "petroleum exclusion" from the definition of "hazardous substance," state laws affecting our operations impose cleanup liability relating to petroleum and petroleum related products, including crude oil cleanups. In addition, although RCRA regulations currently classify certain oilfield wastes which are uniquely associated with field operations as "non-hazardous," such exploration, development and production wastes could be reclassified by regulation as hazardous wastes thereby administratively making such wastes subject to more stringent handling and disposal requirements.
We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although we utilized standard industry operating and disposal practices at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we owned or leased or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA,
and analogous state laws. Our operations are also impacted by regulations governing the disposal of naturally occurring radioactive materials ("NORM"). We must comply with the Clean Air Act and comparable state statutes which prohibit the emissions of air contaminants, although a majority of our activities are exempted under a standard exemption. Moreover, owners, lessees and operators of oil and gas properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom, and are usually causes of action based on negligence, trespass, nuisance, strict liability and fraud.
United States federal regulations also require certain owners and operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of oil into surface waters. The federal Oil Pollution Act ("OPA") contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. For facilities that may affect state waters, OPA requires an operator to demonstrate $10 million in financial responsibility. State laws mandate crude oil cleanup programs with respect to contaminated soil.
Our Canadian operations are also subject to environmental regulation pursuant to local, provincial and federal legislation which generally require operations to be conducted in a safe and environmentally responsible manner. Canadian environmental legislation provides for restrictions and prohibitions relating to the discharge of air, soil and water pollutants and other substances produced in association with certain crude oil and natural gas industry operations, and environmental protection requirements, including certain conditions of approval and laws relating to storage, handling, transportation and disposal of materials or substances which may have an adverse effect on the environment. Environmental legislation can affect the location of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders.
Certain federal environmental laws that may affect us include the Canadian Environmental Assessment Act which ensures that the environmental effects of projects receive careful consideration prior to licenses or permits being issued, to ensure that projects that are to be carried out in Canada or on federal lands do not cause significant adverse environmental effects outside the jurisdictions in which they are carried out, and to ensure that there is an opportunity for public participation in the environmental assessment process; the Canadian Environmental Protection Act ("CEPA") which is the most comprehensive federal environmental statute in Canada, and which controls toxic substances (broadly defined), includes standards relating to the discharge of air, soil and water pollutants, provides for broad enforcement powers and remedies and imposes significant penalties for violations; the National Energy Board Act which can impose certain environmental protection conditions on approvals issued under the Act; the Fisheries Act which prohibits the depositing of a deleterious substance of any type in water frequented by fish or in any place under any condition where such deleterious substance may enter any such water and provides for significant penalties; the Navigable Waters Protection Act which requires any work which is built in, on, over, under, through or across any navigable water to be approved by the Minister of Transportation, and which attracts severe penalties and remedies for non-compliance, including removal of the work.
In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act ("AEPEA") since September 1, 1993. In addition to consolidating a variety of environmental statutes, the AEPEA also imposes certain new environmental responsibilities on oil and natural gas operators in Alberta. The AEPEA sets out environmental standards and compliance for releases, clean-up and reporting. The Act provides for a broad range of liabilities, enforcement actions and penalties.
British Columbia's Environmental Assessment Act became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process which contemplates public participation in the environmental review.
Saskatchewan's Environmental Management and Protection Act is the primary environmental legislation for that province. This Act provides significant enforcement and penalty provisions, and includes a compensation scheme respecting losses or damage from spills. The Clean Air Act provides a permitting scheme for certain industrial activities, broad enforcement provisions and
significant penalties for non-compliance. The Environmental Assessment Act provides that certain development activities which can affect the environment must undergo environmental assessment and approval from the provincial government.
We are not currently involved in any administrative, judicial or legal proceedings arising under domestic or foreign federal, state, or local environmental protection laws and regulations, or under federal or state common law, which would have a material adverse effect on our financial position or results of operations. Moreover, we maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.
We have a Corporate Environmental Policy and a detailed Environmental Management System in place to ensure continued compliance with environmental, health and safety laws and regulations. We believe that we have obtained and are in compliance with all material environmental permits, authorizations and approvals.
TITLE TO PROPERTIES
As is customary in the crude oil and natural gas industry, we make only a cursory review of title to undeveloped crude oil and natural gas leases at the time we acquire them. However, before drilling commences, we require a thorough title search to be conducted, and any material defects in title are remedied prior to the time actual drilling of a well begins. To the extent title opinions or other investigations reflect title defects, we, rather than the seller of the undeveloped property, are typically obligated to cure any title defect at our expense. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our crude oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. The crude oil and natural gas properties we own are also typically subject to royalty and other similar non-cost bearing interests customary in the industry. We do not believe that any of these encumbrances or burdens will materially affect our ownership or use of our properties.
EMPLOYEES
As of March 1, 2000, we had 51 full-time employees in the United States, including 3 executive officers, 2 non-executive officers, 4 petroleum engineers, 1 geologist, 6 managers, 10 secretarial and clerical personnel and 25 field personnel. Additionally, we retain contract pumpers on a month-to-month basis. We retain independent geological and engineering consultants from time to time on a limited basis and expects to continue to do so in the future.
As of March 1, 2000, Grey Wolf Exploration, Inc. ("Grey Wolf") had 43 full-time employees, including 4 executive officers, 2 non-executive officers, 1 manager, 3 petroleum engineers, 4 geologists, 1 geophysicist, 14 secretarial and clerical personnel and 14 field personnel.
OFFICE FACILITIES
Our executive and administrative offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland, Texas. These offices, consisting of approximately 12,650 square feet in San Antonio and 960 square feet in Midland, are leased until March 2005 at an aggregate rate of $18,000 per month.
Canadian Abraxas leases 7,427 square feet of office space in Calgary, Alberta pursuant to a lease which expires on July 1, 2001.
Grey Wolf leases 8,683 square feet of office space in Calgary, Alberta pursuant to a lease which expires on December 31, 2001.
ITEM 2.
ITEM 2. PROPERTIES.
PRIMARY OPERATING AREAS
TEXAS
Our U.S. operations are concentrated in South and West Texas with over 91% of the PV-10 of our U.S. crude oil and natural gas properties at December 31, 1999, located in those two regions. We operate 85% of our wells in Texas. Operations in South Texas are concentrated along the Edwards trend in Live Oak and Dewitt Counties and in the Frio/Vicksburg trend in San Patricio County. We own an average 87% working interest in 88 wells with average daily production of 671 net Bbls of crude oil and NGLs and 15,773 net Mcf of natural gas per day for the year ended December 31, 1999. As of December 31, 1999, we had estimated net proved reserves in South Texas of 79,997 Mmcfe (70% natural gas) with a PV-10 of $82.0 million, 63.5% of which was attributable to proved developed reserves. Our West Texas operations are concentrated along the deep Devonian/Ellenberger formations and shallow Cherry Canyon sandstones in Ward County, the Spraberry trend in Midland County and in the Sharon Ridge Clearfork Field in Scurry County. We own an average 73% working interest in 235 wells with average daily production of 897 net Bbls of crude oil and NGLs and 6,080 net Mcf of natural gas per day for the year ended December 31, 1999. As of December 31, 1999, we had estimated net proved reserves in West Texas of 38,957 Mmcfe (44% natural gas) with a PV 10 of $41.3 million, 79.3% of which was attributable to proved developed reserves. During 1999, we drilled a total of 12 new wells (11.9 net) in Texas with a 100% success rate.
WESTERN CANADA
We own producing properties in Western Canada, consisting primarily of natural gas reserves and interests ranging from 10% to 100% in approximately 200 miles of natural gas gathering systems and 20 natural gas processing plants. As of December 31, 1999, Canadian Abraxas and Grey Wolf had estimated net proved reserves of 104,458 Mmcfe (80% natural gas) with a PV-10 of $121.5million, 93.5% of which was attributable to proved developed reserves.. We recorded a writedown of our Canadian reserves under the ceiling test rules of $19.1 million ($11.9 million after tax) as a result of a downward adjustment to our estimated proved reserves in Canada. This adjustment primarily affected properties we acquired in January 1999 from New Cache Petroleums, Ltd. Pro forma reserves of New Cache were 76.5 Bcfe as of December 31, 1998 compared to 41.0 Bcfe as if December 31, 1999. For the year ended December 31, 1999, the Canadian properties produced an average of approximately 1,563 net Bbls of crude oil and NGL's per day and 47,966 net Mcf of natural gas per day from 135.9 net wells. The natural gas processing plants had aggregate capacity of approximately 313 MMcf of natural gas per day (121 net MMcf). During 1999, we drilled a total of 45 new wells (20.8 net) in Canada with a 56% success rate.
Grey Wolf Exploration, Ltd. manages the operations of Canadian Abraxas pursuant to a management agreement between Canadian Abraxas and Grey Wolf. Under the management agreement, Canadian Abraxas reimburses Grey Wolf for reasonable costs or expenses attributable to Canadian Abraxas and for administrative expenses based upon the percentage that Canadian Abraxas' gross revenue bears to the total gross revenue of Canadian Abraxas and Grey Wolf. Abraxas and Canadian Abraxas own approximately 49% of the outstanding capital stock of Grey Wolf.
EXPLORATORY AND DEVELOPMENTAL ACREAGE
Our principal crude oil and natural gas properties consist of non-producing and producing crude oil and natural gas leases, including reserves of crude oil and natural gas in place. The following table indicates our interest in developed and undeveloped acreage as of December 31, 1999:
- ---------------
(1) Developed acreage consists of acres spaced or assignable to productive wells. (2) Undeveloped acreage is considered to be those leased acres 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 or not such acreage contains proved reserves. (3) Gross acres refers to the number of acres in which we own a working interest. (4) Net acres represents the number of acres attributable to an owner's proportionate working interest and/or royalty interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres).
PRODUCTIVE WELLS
The following table sets forth our total gross and net productive wells, expressed separately for crude oil and natural gas, as of December 31, 1999:
- -----------
(1) Productive wells are producing wells and wells capable of production. (2) A gross well is a well in which we own an interest. The number of gross wells is the total number of wells in which we own an interest. (3) A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of our fractional working interest owned in gross wells. (4) Included in the above wells are 23 gross and 21 net crude oil and 11 gross and 3 net natural gas wells with multiple completions.
Substantially all of our existing crude oil and natural gas properties are pledged to secure our indebtedness under the first lien notes and second lien notes. You should read the discussion under the heading "Management's Discussion of Financial Condition and Results of Operations--Liquidity and Capital Resources" for more information regarding our indebtedness.
RESERVES INFORMATION
The crude oil and natural gas reserves of Abraxas have been estimated as of January 1, 2000, January 1, 1999, and January 1, 1998, by DeGolyer and MacNaughton, of Dallas, Texas. The reserves of Canadian Abraxas and Grey Wolf as of January 1, 2000, January 1, 1999 and January 1, 1998 have been estimated by McDaniel and Associates Consultants Ltd. of Calgary, Alberta. Crude oil and natural gas reserves, and the estimates of the present value of future net revenues therefrom, were determined based on then current prices and costs. Reserve calculations involve the estimate of future net recoverable reserves of crude oil and natural gas and the timing and amount of future net revenues to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain.
The following table sets forth certain information regarding estimates of our crude oil, natural gas liquids and natural gas reserves as of January 1, 2000, January 1, 1999 and January 1, 1998:
- ------------------
(1) Includes 128,900, 31,900 and 33,000 barrels of crude oil reserves owned by Grey Wolf of which 69,500, 16,400 and 16,900 barrels are applicable to the minority interests share of these reserves as of January 1, 1998, 1999 and 2000, respectively. (2) Includes 131,300, 443,500 and 236,000 barrels of natural gas liquids reserves owned by Grey Wolf of which 70,889, 227,600 and 121,098 barrels are applicable to the minority interests share of these reserves as of January 1, 1998, 1999 and 2000, respectively. (3) Includes 7,446, 28,610 and 21,710 Mmcf of natural gas reserves owned by Grey Wolf of which 4,020, 14,700 and 11,140 Mmcf are applicable to the minority interests share of these reserves as of January 1, 1998, 1999 and 2000, respectively. (4) Includes 343,941 Bbls of crude oil reserves; 2,448.6 Mbbls of natural gas liquids reserves and 25,810 Mmcf of natural gas reserves, attributable to the Wyoming properties which were sold in March 2000. These reserves were estimated internally.
The process of estimating crude oil and natural gas reserves is complex and involves decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data. Therefore, these estimates are imprecise.
Actual future production, crude oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves most likely will vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this annual report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing crude oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues referred to in this annual statement is the current market value of our estimated crude oil and natural gas reserves. In accordance with SEC requirements, the estimated
discounted future net cash flows from proved reserves are generally based on prices and costs as of the end of the year of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the end of the year of the estimate. Any changes in consumption by natural 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 crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. For example, we reduced our 1999 capital expenditure budget. This reduction will delay cash flows and thereby reduce present value. In addition, the 10% discount factor, which is required by the SEC 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 crude oil and natural gas industry in general will affect the accuracy of the 10% discount factor.
The estimates of our reserves are based upon various assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the PV-10 thereof for the crude oil and natural gas properties described in this report are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices at December 31, 1999. The average sales prices as of such date used for purposes of such estimates were $24.88 per Bbl of crude oil, $14.79 per Bbl of NGLs and $2.11 per Mcf of natural gas. It is also assumed that we will make future capital expenditures of approximately $31.7 million in the aggregate, which are necessary to develop and realize the value of proved undeveloped reserves on our properties. Any significant variance in actual results from these assumptions could also materially affect the estimated quantity and value of reserves set forth herein.
We file reports of our estimated crude oil and natural gas reserves with the Department of Energy and the Bureau of the Census. The reserves reported to these agencies are required to be reported on a gross operated basis and therefore are not comparable to the reserve data reported herein.
CRUDE OIL, NATURAL GAS LIQUIDS, AND NATURAL GAS PRODUCTION AND SALES PRICES
The following table presents our net crude oil, net natural gas liquids and net natural gas production, the average sales price per Bbl of crude oil and natural gas liquids and per Mcf of natural gas produced and the average cost of production per BOE of production sold, for the three years ended December 31, 1999:
(1) All sales prices are net of hedge gains or losses.
(2) Oil and gas were combined by converting gas to a barrel oil equivalent ("BOE") on the basis of 6 Mcf gas =1 Bbl of oil. Production costs include direct operating costs, ad valorem taxes and gross production taxes.
DRILLING ACTIVITIES
The following table sets forth our gross and net working interests in exploratory, development, and service wells drilled during the three years ended December 31, 1999:
- ------------------
(1) A gross well is a well in which we own an interest. (2) The number of net wells represents the total percentage of working interests held in all wells (e.g., total working interest of 50% is equivalent to 0.5 net well. A total working interest of 100% is equivalent to 1.0 net well). (3) An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be producing crude oil or natural gas in another reservoir, or to extend a known reservoir. (4) A productive well is an exploratory or a development well that is not a dry hole. (5) A dry hole is an exploratory or development well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. (6) A development well is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of stratigraphic horizon (rock layer or formation) noted to be productive for the purpose of extracting proved crude oil or natural gas reserves. (7) A service well is used for water injection in secondary recovery projects or for the disposal of produced water.
As of March 15, 2000, we had five wells in process of drilling.
OFFICE FACILITIES
Our executive and administrative offices are located at 500 North Loop 1604 East, Suite 100, San Antonio, Texas 78232. We also have an office in Midland, Texas. These offices, consisting of approximately 12,650 square feet in San Antonio and 960 square feet in Midland, are leased until March 2005 at an aggregate rate of $18,000 per month.
Canadian Abraxas leases 7,427 square feet of office space in Calgary, Alberta pursuant to a lease which expires on July 1, 2001.
Grey Wolf leases 8,683 square feet of office space in Calgary, Alberta pursuant to a lease which expires on December 31, 2001.
OTHER PROPERTIES
We own 10 acres of land, an office building, workshop, warehouse and house in Sinton, Texas, 160 acres of land in Coke County, Texas and a 50% interest in approximately two acres of land in Bexar County, Texas. All three properties are used for the storage of tubulars and production equipment. We also own 19 vehicles which are used in the field by employees.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
General. From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. As of March 28, 2000, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on us.
Hornburg Litigation. In May 1995, certain plaintiffs filed a lawsuit against us alleging negligence and gross negligence, tortious interference with contract, conversion and waste. In March 1998, a jury found against us and on May 22, 1998, final judgment in the amount of $1.3 million was entered. We filed an appeal and in March 2000, the Court of Appeals reduced the plaintiff's award to $362,495 plus post-judgment interest of $68,915. We are currently evaluating whether to file an appeal to this decision or to pay the judgment.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of our security holders during the fourth quarter of the fiscal year ended December 31, 1999.
ITEM 4A. EXECUTIVE OFFICERS OF ABRAXAS
Certain information is set forth below concerning our executive officers, each of whom has been selected to serve until the 2000 annual meeting of directors and until his successor is duly elected and qualified.
Robert L. G. Watson, age 49, has served as Chairman of the Board, President, Chief Executive Officer and a director of Abraxas since 1977. Since May 1996, Mr. Watson has also served as Chairman of the Board and a director of Grey Wolf. In November 1996, Mr. Watson was elected Chairman of the Board, President and as a director of Canadian Abraxas. Prior to joining Abraxas, Mr. Watson was employed in various petroleum engineering positions with Tesoro Petroleum Corporation, a crude oil and natural gas exploration and production company, from 1972 through 1977, and DeGolyer and McNaughton, an independent petroleum engineering firm, from 1970 to 1972. Mr. Watson received a Bachelor of Science degree in Mechanical Engineering from Southern Methodist University in 1972 and a Master of Business Administration degree from the University of Texas at San Antonio in 1974.
Chris E. Williford, age 48, was elected Vice President, Treasurer and Chief Financial Officer of Abraxas in January 1993, and as Executive Vice President and a director of Abraxas in May 1993. In November 1996, Mr. Williford was elected Vice President and Assistant Secretary of Canadian Abraxas. In December 1999, Mr. Williford resigned as a director of Abraxas. Prior to joining Abraxas, Mr. Williford was Chief Financial Officer of American Natural Energy Corporation, a crude oil and natural gas exploration and production company, from July 1989 to December 1992 and President of Clark Resources Corp., a crude oil and natural gas exploration and production company, from January 1987 to May 1989. Mr. Williford received a Bachelor of Science degree in Business Administration from Pittsburgh State University in 1973.
Robert W. Carington, Jr., age 38, was elected Executive Vice President and a director of the Company in July 1998. In December 1999, Mr. Carington resigned as a director of Abraxas. Prior to joining the Company, Mr. Carington was a Managing Director with Jefferies & Company, Inc. Prior to joining Jefferies & Company, Inc. in January 1993, Mr. Carington was a Vice President at Howard, Weil, Labouisse, Friedrichs, Inc. Prior to joining Howard, Weil, Labouisse, Friedrichs, Inc., Mr. Carington was a petroleum engineer with Unocal Corporation from 1983 to 1990. Mr. Carington received a degree of Bachelor of Science in Mechanical Engineering from Rice University in 1983 and a Masters of Business Administration from the University of Houston in 1990.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
MARKET INFORMATION
Our common stock is currently traded on the OTC Bulletin Board under the symbol "AXAS." Our common stock was formerly listed on the NASDAQ Stock Market; however, effective June 16, 1999, the common stock was delisted from general quotation on the NASDAQ Stock Market for failure to satisfy NASDAQ's listing and maintenance standards.
The following table sets forth certain information as to the high and low bid quotations quoted on NASDAQ for 1997, 1998 and in 1999 through June 16, 1999, and on the OTC Bulletin Board for the remainder of 1999. Information with respect to over-the-counter bid quotations represents prices between dealers, does not include retail mark-ups, mark-downs, or commissions, and may not necessarily represent actual transactions.
Period High Low
First Quarter..................$14.00 $8.88 Second Quarter..................14.13 10.00 Third Quarter...................15.75 12.50 Fourth Quarter..................19.50 13.88 First Quarter..................$15.00 $7.00 Second Quarter..................11.25 8.25 Third Quarter................... 9.50 5.31 Fourth Quarter.................. 7.56 4.00 First Quarter..................$ 3.19 $1.19 Second Quarter.................. 2.82 0.88 Third Quarter................... 2.97 0.88 Fourth Quarter.................. 2.44 0.81
HOLDERS
As of March 15, 2000 we had 22,595,016 shares of common stock outstanding and had approximately 1,561 stockholders of record.
DIVIDENDS
We have not paid any cash dividends on our common stock and it is not presently determinable when, if ever, we will pay cash dividends in the future. In addition, the indentures governing the first lien and second lien notes prohibit the payment of cash dividends and stock dividends on our common stock. You should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources" for more information regarding the restrictions on our ability to pay dividends.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data are derived from our consolidated financial statements. The data should be read in conjunction with our Consolidated Financial Statements and Notes thereto, and other financial information included herein. See "Financial Statements."
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of our consolidated financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes thereto. See "Financial Statements."
GENERAL
We have incurred net losses for a number of years and there can be no assurance that operating income and net earnings will be achieved in future periods. Our revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for crude oil and natural gas and the volumes of crude oil, natural gas and natural gas liquids we produce. Natural gas and crude oil prices weakened somewhat during 1997 and continued to decrease during 1998. Crude oil and natural gas prices increased somewhat in 1999. In addition, because our proved reserves will decline as crude oil, natural gas and natural gas liquids are produced, unless we are successful in acquiring properties containing proved reserves or conduct successful exploration and development activities, our reserves and production will decrease. Our ability to acquire or find additional reserves in the near future will be dependent, in part, upon the amount of available funds for acquisition, exploration and development projects. If crude oil and natural gas prices revert to depressed levels, or if our production levels decrease, our revenues, cash flow from operations and financial condition will be materially adversely affected.
RESULTS OF OPERATIONS
The factors which most significantly affect our results of operations are:
o the sales prices of crude oil, natural gas liquids and natural gas, o the level of total sales volumes of crude oil, natural gas liquids and natural gas, o the level of and interest rates on borrowings, and o the level and success of exploration and development activity.
SELECTED OPERATING DATA. The following table sets forth certain of our operating data for the periods presented:
COMPARISON OF YEAR ENDED DECEMBER 31, 1999 TO YEAR ENDED DECEMBER 31, 1998
OPERATING REVENUE. During the year ended December 31, 1999, operating revenue from crude oil, natural gas and natural gas liquids sales, and natural gas processing revenues increased by $4.7 million from $54.3 million in 1998 to $59.0 million in 1999. This increase was primarily attributable to an increase in commodity prices. Increased prices contributed $8.1 million in additional revenue, which was offset by $3.4 million due to a decrease in production volumes.
Natural gas liquids volumes declined from 867.4 MBbls in 1998 to 376.5 in 1999. The decline in natural gas liquids was primarily a result of the sale of oil and gas producing properties in Wyoming in late 1998. The Wyoming properties contributed 440.6 MBbls of natural gas liquids in 1998. Also contributing to the decline in natural gas liquids volumes was the closing of two gas processing plants in South Texas, one in late 1998 and one in January 1999 and our decision to stop processing gas in early 1999 due to depressed prices. We resumed processing natural gas in April 1999 as prices improved and third party facilities became available. Crude oil sales volumes increased by 6.8% from 728.6 MBbls in 1998 to 777.9 MBbls during 1999. Natural gas sales volumes
increased by 13.8% from 24.9 Bcf in 1998 to 25.7 Bcf in 1999. The increase in crude oil and natural gas sales volumes was attributable to increased production attributable to our ongoing development program on existing and acquired properties.
Average sales prices in 1999 were:
o $14.57 per Bbl of crude oil, o $13.40 per Bbl of natural gas liquids, and o $1.66 per Mcf of natural gas.
Average sales prices in 1998 were:
o $13.65 per Bbl of crude oil, o $6.81 per Bbl of natural gas liquids, and o $1.54 per Mcf of natural gas.
We also had gas processing revenue of $4.2 million in 1999 as compared to $3.1 million in 1998.
LEASE OPERATING EXPENSE. Lease operating expense ("LOE") and natural gas processing costs decreased by $0.2 million from $18.1 million for the year ended December 31, 1998 to $17.9 million for the same period of 1999. LOE on a per Mcfe basis for 1999 was $0.55 per Mcfe as compared to $0.52 per Mcfe in 1998. The increase in the per Mcfe LOE is due to the sale of low cost gas wells in Wyoming which were replaced with higher cost oil wells acquired in Canada with the acquisition of New Cache Petroleums, Ltd. in January 1999. The decrease was due primarily to the greater number of wells we owned for the year ended December 31, 1999 compared to the year ended December 31, 1998.
G&A EXPENSE. G&A expense decreased from $5.5 million for the year ended December 31, 1998 to $5.3 million for the year ended December 31, 1999. This is primarily a result of cost control measures implemented in the climate of depressed prices. Our G&A expense on a per Mcfe basis was unchanged at $0.16 per Mcfe in 1999 and 1998.
DD&A EXPENSE. Depreciation, depletion and amortization ("DD&A") expense increased by $3.6 million from $31.2 million for the year ended December 31, 1998 to $34.8 million for the year ended December 31, 1999. Our DD&A expense on a per Mcfe basis for 1999 was $1.07 per Mcfe as compared to $0.90 per Mcfe in 1998. The increase in DD&A is the result of higher finding and acquisition costs in 1998 and downward reserve revisions in 1999, primarily related to Canadian operations.
INTEREST EXPENSE. Interest expense increased by $6.2 million from $30.8 million to $37.0 million for the year ended December 31, 1999 compared to 1998. This increase was attributable to our increased borrowings during 1999. In March 1999, we issued $63.5 million in principal amount of the first lien notes . In December 1999, we consummated the exchange offer whereby $188.8 million in second lien notes, 16,078,990 shares of our common stock, and 16,078,990 CVRs were exchanged for $269.7 million of the old notes. Long-term debt decreased from $299.8 million at December 31, 1998 to $273.4 million at December 31, 1999.
CEILING LIMITATION WRITEDOWN. We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, we are subject to a ceiling limitation writedown to the extent of such excess. A ceiling limitation writedown is a charge to earnings which does not impact cash flow from operating activities. However, such writedowns do impact the amount of our stockholders' equity.
The risk that we will be required to writedown the carrying value of our oil and gas assets increases when oil and gas prices are depressed or volatile. In addition, writedowns may occur if we have substantial downward revisions in our
estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. For the year ended December 31, 1999, we recorded a writedown of $19.1 million, $11.9 million after tax, related to our Canadian properties. We cannot assure you that we will not experience additional writedowns in the future. Should commodity prices decline, a further writedown of the carrying value of our crude oil and natural gas properties may be required. See Note 17 of Notes to Consolidated Financial Statements.
COMPARISON OF YEAR ENDED DECEMBER 31, 1998 TO YEAR ENDED DECEMBER 31, 1997
OPERATING REVENUE. During the year ended December 31, 1998, operating revenue from crude oil, natural gas and natural gas liquids sales, and natural gas processing revenues decreased by $12.0 million from $69.4 million in 1997 to $57.4 million in 1998, of which $11.8 million was attributable to the Wyoming Properties. This decrease was primarily attributable to a decline in commodity prices.
Production volumes increased 5.8% from 32,622 MMcfe in 1997 to 34,505 MMcfe for the year ended December 1998, of which 8,609 MMcfe were attributable to the Wyoming Properties. Crude oil and natural gas liquids sales volumes decreased by 17.2% from 1,930 MBbls in 1997 to 1,596 MBbls during 1998, and natural gas sales volumes increased by 18.4% from 21.1 Bcf in 1997 to 38.4 Bcf in 1998. The increase in natural gas sales volumes was attributable to increased production attributable to our ongoing development program on existing and acquired properties. Crude oil sales volumes decreased 22.2% to 729 MBbls during 1998 from 937 MBbls in 1997. This decrease was due primarily to our decreased emphasis on crude oil development projects during 1998 in response to the continuing decline in crude oil prices.
Natural gas liquids sales volumes decreased 12.6% to 867 MBbls in 1998 from 992 MBbls in 1997. Approximately 66 MBbls of the decline in natural gas liquids was attributable to the loss of production from the Wyoming Properties. In the ten and one-half months that we owned the Wyoming Properties during 1998, they contributed 89 MBbls of crude oil, 454 MBbls of natural gas liquids and 5.4 Bcf of natural gas production.
Average sales prices in 1998 were:
o $13.65 per Bbl of crude oil, o $6.81 per Bbl of natural gas liquids, and o $1.54 per Mcf of natural gas.
Average sales prices in 1997 were:
o $18.63 per Bbl of crude oil, o $10.75 per Bbl of natural gas liquids, and o $1.79 per Mcf of natural gas.
We also had natural gas processing revenues of $3.1 million in 1998 as compared to $3.6 million in 1997.
LEASE OPERATING EXPENSE. LOE and natural gas processing costs increased by $2.0 million from $16.1 million for the year ended December 31, 1997 to $18.1 million for the same period of 1998, of which $2.0 million was attributable to the Wyoming Properties. The increase was due primarily to the greater number of wells we owned for the year ended December 31, 1998, compared to the year ended December 31, 1997. Our LOE on a per Mcfe basis for 1998 was $0.49 per Mcfe as compared to $0.46 per Mcfe in 1997. Natural gas processing costs remained constant at $1.2 million in 1998 as compared to $1.2 million in 1997.
G&A EXPENSE. G&A expense increased from $4.2 million for the year ended December 31, 1997 to $5.3 million for the year ended December 31, 1998, as a result of our hiring of additional staff. The sale of the Wyoming Properties did not have a material effect on G&A expense. Our G&A expense on a per Mcfe basis was $0.16 per Mcfe in 1998 compared to $0.13 per Mcfe for 1997.
DD&A EXPENSE. Due to the increase in sales volumes of crude oil and natural gas, DD&A expense increased by $600,000 from $30.6 million for the year ended
December 31, 1997 to $31.2 million for the year ended December 31, 1998, of which $3.4 million was attributable to the Wyoming Properties. Our DD&A expense on a per Mcfe basis for 1998 was $0.90 per Mcfe as compared to $0.94 per Mcfe in 1997.
INTEREST EXPENSE AND PREFERRED DIVIDENDS. Interest expense and preferred dividends increased by $6.2 million from $24.6 million to $30.8 million for the year end December 31, 1998 compared to 1997. This increase was attributable to our increased borrowings during 1998. In January 1998, Abraxas and Canadian Abraxas issued $60.0 million in principal amount of 11.5% Senior Notes due 2004, Series C ("Series C Notes"), and in June 1998, Abraxas and Canadian Abraxas exchanged all of their outstanding Series C Notes and their 11.5% Senior Notes due 2004, Series B in the original principal amount of $215.0 million ("Series B Notes") for $275.0 million of the old notes.
During 1998, we also made additional borrowings under our revolving credit facility. Long-term debt increased from $248.6 million at December 31, 1997 to $299.7 million at December 31, 1998. During 1998, we paid no preferred dividends as compared to $183,000 in 1997. Preferred dividends were eliminated on July 1, 1997, as the result of the conversion of all outstanding preferred stock into Abraxas common stock.
CEILING LIMITATION WRITEDOWN. We record the carrying value of our crude oil and natural gas properties using the full cost method of accounting for oil and gas properties. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties less related deferred taxes, are limited by country, to the lower of the unamortized cost or the cost ceiling, defined as the sum of the present value of estimated unescalated future net revenues from proved reserves, discounted at 10%, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. If the net capitalized cost of crude oil and natural gas properties exceeds the ceiling limit, we are subject to a ceiling limitation writedown to the extent of such excess. A ceiling limitation writedown is a charge to earnings which does not impact cash flow from operating activities. However, such writedowns do impact the amount of our stockholders' equity.
The risk that we will be required to writedown the carrying value of our crude oil and natural gas assets increases when crude oil and natural gas prices are depressed or volatile. In addition, writedowns may occur if we have substantial downward revisions in our estimated proved reserves or if purchasers or governmental action cause an abrogation of, or if we voluntarily cancel, long-term contracts for our natural gas. For the year ended December 31, 1998, we recorded a writedown of $61.2 million related to our United States properties. No assurance can be given that we will not experience additional writedowns in the future. Should commodity prices decline, a further writedown of the carrying value of our crude oil and natural gas properties may be required. See Note 17 of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
General. Capital expenditures in 1997, 1998 and 1999 were $87.8 million, $57.9 million and $128.7 million, respectively. The table below sets forth the components of these capital expenditures on a historical basis for the three years ended December 31, 1997, 1998 and 1999.
Year Ended December 31, 1997 1998 1999 --------- --------- --------- (dollars in thousands) Expenditure category: Property acquisitions (1) $ 24,210 $ 2,729 $ 89,743 Development 61,414 51,821 37,344 Facilities and other 2,140 3,311 1,621 -------- --------- ---------
Total $ 87,764 $ 57,861 $ 128,708 ======== ========= ========= - ----------
(1) Acquisition cost includes 7,585,000 common shares and 4,000,000 special warrants of Grey Wolf valued at approximately $3.7 million in 1997 and 71,063 shares of Abraxas common stock valued at approximately $449,000 in 1998 related to the acquisition of certain crude oil and natural gas properties.
During 1999, expenditures were primarily for the acquisition of New Cache Petroleums, Ltd. During 1997 and 1998, expenditures were primarily for the development of existing properties. These expenditures were funded through internally generated cash flow, the issuance of the Series C Notes and the first lien notes and borrowings under our credit facility.
At December 31, 1999, we had current assets of $19.0 million and current liabilities of $26.3 million resulting in a working capital deficit of $(7.3) million. The material components of our current liabilities at December 31, 1999, included trade accounts payable of $8.4 million, revenues due third parties of $10.6 million and accrued interest of $6.4 million. Stockholders' equity increased from a deficit of $(63.5) million at December 31, 1998, to $(9.5) million at December 31, 1999, primarily due to the restructuring of our debt in 1999 in the exchange offer.
Our current budget for capital expenditures for 2000 other than acquisition expenditures is $49.6 million, approximately $8.1 million of which has been spent to date. The remaining portion of such expenditures is largely discretionary and will be made primarily for the development of existing properties. Additional capital expenditures may be made for acquisition of producing properties if such opportunities arise, but we currently have no agreements, arrangements or undertakings regarding any material acquisitions. We have no material long-term capital commitments and are consequently able to adjust the level of our expenditures as circumstances dictate. Additionally, the level of capital expenditures will vary during future periods depending on market conditions and other related economic factors. Should the prices of crude oil and natural gas decline, our cash flows will decrease which may result in a further reduction of the capital expenditures budget.
Operating activities for the year ended December 31, 1999, provided us $3.9 million of cash. Investing activities used $111.2 million during 1999, $17.5 million was provided from the sale of oil and gas producing properties and $128.7 million was used primarily for the acquisition and development of producing properties. Financing provided $49.1 million during 1999.
Operating activities for the year ended December 31, 1998, provided $4.8 million of cash to us. Investing activities provided $2.0 million in 1998, $59.4 million was provided from the sale of oil and gas producing properties, primarily the Wyoming Properties, and $57.4 million was used primarily for the acquisition and development of producing properties. Financing provided $52.5 million during 1998.
Operating activities for the year ended December 31, 1997, provided $36.6 million of cash. Investing activities required $74.5 million primarily for the acquisition and development of producing properties. Financing activities provided $33.3 million during 1997.
We are heavily dependent on crude oil and natural gas prices which have historically been volatile. Although we have hedged a portion of our natural gas production and substantially all of our crude oil production and intend to continue this practice, future crude oil and natural gas price declines would have a material adverse effect on our overall results, and therefore, our liquidity. Furthermore, low crude oil and natural gas prices could affect our ability to raise capital on terms favorable to us.
CURRENT LIQUIDITY NEEDS. Since January 1999, we have sought to improve our liquidity in order to allow us to meet our debt service requirements and to maintain and increase existing production.
Our sale in March 1999 of our first lien notes allowed us to refinance our bank debt, meet our near-term debt service requirements and make limited crude oil and natural gas capital expenditures.
In October 1999, we sold a dollar denominated production payment for $4.0 million relating to existing natural gas wells in the Edwards Trend in South Texas to a unit of Southern Energy, Inc. and in January 2000, we sold an additional production payment for $2.0 million relating to additional natural gas wells in the Edwards Trend to Southern. We have the ability to sell up to $50 million to Southern for drilling opportunities in the Edwards Trend.
In December 1999, Abraxas and our wholly-owned Canadian subsidiary, Canadian Abraxas Petroleum Limited, completed an exchange offer whereby we exchanged the second lien notes, common stock, and contingent value rights for approximately 98.43% of our outstanding old notes. The exchange offer reduced our long term debt by $76 million net of fees and expenses.
In March 2000, we sold our interest in certain crude oil and natural gas properties that we owned and operated in Wyoming. Simultaneously, a limited partnership of which one of our subsidiaries was the general partner sold its interest in crude oil and natural gas properties in the same area. Our net proceeds from these transactions were approximately $34.0 million.
We are continuing to rationalize our significant non-core Canadian assets to allow us to continue to grow while reducing our debt. We may sell non-core assets or seek partners to fund a portion of the exploration costs of undeveloped acreage and are considering other potential strategic alternatives.
We will have three principal sources of liquidity going forward: (i) cash on hand, including the proceeds from the sale of the Wyoming properties, (ii) cash flow from operations, and (iii) the production payment with Southern. We also intend to sell certain non-core properties, although the terms of the first lien notes indenture, the second lien notes indenture and the old notes indenture substantially limit our use of proceeds from such sales. While the availability of capital resources cannot be predicted with certainty and is dependent upon a number of factors including factors outside of management's control, management believes that the net cash flow from operations plus cash on hand, cash available under the production payment and the proceeds from the sale of certain non-core properties will be adequate to fund operations and planned capital expenditures.
HEDGING ACTIVITIES. Our results of operations are significantly affected by fluctuations in commodity prices and we seek to reduce our exposure to price volatility by hedging our production through swaps, options and other commodity derivative instruments.
In November 1996, we assumed hedge agreements extending through October 2001 with a counterparty involving various quantities and fixed prices. These hedge agreements provided that we make payments to the counterparty to the extent the market prices, determined based on the price for crude oil on the NYMEX and the Inside FERC, Tennessee Gas Pipeline Co. Texas (Zone O) price for natural gas exceeded certain fixed prices and for the counterparty to make payments to us to the extent the market prices were less than such fixed prices. We accounted for the related gains or losses in crude oil and natural gas revenue in the period of the hedged production. We terminated these hedge agreements in January 1999 and were paid $750,000 by the counterparty for such termination. This amount is included in other income in the accompanying financial statements.
In March 1998, we entered into a costless collar hedge agreement with Enron Capital and Trade Resources Corp. for 2,000 Bbls of crude oil per day with a floor price of $14.00 per Bbl and a ceiling price of $22.30 per Bbl for crude oil on the NYMEX. The agreement was effective April 1, 1998 and extended through March 31, 1999. Under the terms of the agreement we were paid when the average monthly price for crude oil on the NYMEX is below the floor price and will pay the counterparty when the average monthly price exceeds the ceiling price. During the year ended December 31, 1999, we realized a gain of $204,600 on this agreement, which is accounted for in crude oil and natural gas revenue. We have also entered into a hedge agreement with Barrett Resources Corporation ("Barrett") for the period November 1999 through October 2000. This agreement is for 1,000 Bbls per day with us being paid $20.30 and 1,000 barrels per day with a floor price of $18.00 per barrel and a ceiling of $22.00 per Bbl. Additionally, Barrett has a call on either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day at Barrett's option at fixed prices through October 31, 2002. We realized a loss of $1.8 million for the year ended December 31, 1999 in connection with this agreement, which is accounted for in crude oil and natural gas revenue.
As of March 1, 2000, we had 22.5 MMBtupd hedged through October 31, 2000 of which 2.5 MMBtupd is hedged at an average NYMEX price less $0.83 (approximately $1.75 per MMBtu as of February 2000) and 20.0 MMBtupd with a ceiling of $2.39 and a floor of $2.07 based on an AECO index. Both of these hedges are with Barrett Resources. In connection with the 20.0 MMBtupd Barrett hedge, we realized a loss of $2.5 million for the year ended December 31, 1999, which is accounted for in crude oil and natural gas revenue.
LONG-TERM INDEBTEDNESS
OLD NOTES. On November 14, 1996, Abraxas and Canadian Abraxas consummated the offering of $215.0 million of their 11.5% Senior Notes due 2004, Series A, which were exchanged for Series B Notes in February 1997. On January 27, 1998, Abraxas and Canadian Abraxas completed the sale of $60.0 million of the Series C Notes. The Series B Notes and the Series C Notes were subsequently exchanged for $275.0 million in principal amount of the old notes in June 1998.
Interest on the old notes is payable semi-annually in arrears on May 1 and November 1 of each year at the rate of 11.5% per annum. The old notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas, on or after November 1, 2000, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1 of the years set forth below:
Year Percentage
2000...................................... 105.750% 2001...................................... 102.875% 2002 and thereafter....................... 100.000%
The old notes are joint and several obligations of Abraxas and Canadian Abraxas and rank pari passu in right of payment to all existing and future unsubordinated indebtedness of Abraxas and Canadian Abraxas. The old notes rank senior in right of payment to all future subordinated indebtedness of Abraxas and Canadian Abraxas. The old notes are, however, effectively subordinated to the first lien notes to the extent of the value of the collateral securing the first lien notes and the second lien notes to the extent of the value of the collateral securing the second lien notes. The old notes are unconditionally guaranteed, on a senior basis by a wholly-owned Abraxas subsidiary, Sandia Oil & Gas Corporation. The guarantee is a general unsecured obligation of Sandia and ranks pari passu in right of payment to all unsubordinated indebtedness of Sandia and senior in right of payment to all subordinated indebtedness of Sandia. The guarantee is effectively subordinated to the first lien notes and the second lien notes to the extent of the value of the collateral securing these obligations.
Upon a change of control, each holder of the old notes will have the right to require Abraxas and Canadian Abraxas to repurchase all or a portion of such holder's old notes at a redemption price equal to 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase the old notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase in the event of certain asset sales.
FIRST LIEN NOTES. In March 1999, Abraxas consummated the sale of $63.5 million of the first lien notes. Interest on the first lien notes is payable semi-annually in arrears on March 15 and September 15, commencing September 15, 1999. The first lien notes are redeemable, in whole or in part, at the option of Abraxas on or after March 15, 2001, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on March 15 of the years set forth below:
Year Percentage
2001.................................. 103.000% 2002 and thereafter................... 100.000%
At any time, or from time to time, prior to March 15, 2001, Abraxas may, at its option, use all or a portion of the net cash proceeds of one or more equity offerings to redeem up to 35% of the aggregate original principal amount of the first lien notes at a redemption price equal to 112.875% of the aggregate principal amount of the first lien notes be redeemed, plus accrued and unpaid interest.
The first lien notes are senior indebtedness of Abraxas secured by a first lien on substantially all of the crude oil and natural gas properties of Abraxas and the shares of Grey Wolf owned by Abraxas. The first lien notes are unconditionally guaranteed on a senior basis, jointly and severally, by Canadian Abraxas, Sandia and one of our wholly-owned subsidiaries, Wamsutter Holdings, Inc.. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors and the shares of Grey Wolf owned by Canadian Abraxas.
Upon a change of control, each holder of the first lien notes will have the right to require Abraxas to repurchase such holder's first lien notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas will be obligated to offer to repurchase the first lien notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales.
The first lien notes indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the guarantors of the first lien notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas.
The first lien notes indenture provides, among other things, that Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas or any other Restricted Subsidiary except for such encumbrances or restrictions existing under or by reason of:
(1) applicable law;
(2) the first lien notes indenture;
(3) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an acquisition, which encumbrance or restriction is not applicable to such Restricted Subsidiary or the properties or assets of such subsidiary other than the entity or the properties or assets of the entity so acquired;
(5) agreements existing on the Issue Date (as defined in the first lien notes indenture) to the extent and in the manner such agreements were in effect on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such Restricted Subsidiary to be consummated in accordance with the terms of the first lien notes indenture or any Security Documents (as defined in the first lien notes indenture) solely in respect of the assets or capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the first lien notes indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or
(8) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (2), (4) or (5) above; provided, however, that the provisions relating to such encumbrance or restriction contained in any such refinancing indebtedness are no less favorable to the holders of the first lien notes in any material respect as determined by the Board of Directors of Abraxas in their reasonable and good faith judgment that the provisions relating to such encumbrance or restriction contained in the applicable agreement referred to in such clause (2), (4) or (5) and do not extend to or cover any new or additional property or assets and, with respect to newly created liens, (A) such liens are expressly junior to the liens securing the first lien notes, (B) the refinancing results in an improvement on a pro forma basis in Abraxas' Consolidated EBITDA Coverage Ratio (as defined in the first lien notes indenture) and (C) the instruments creating such liens expressly subject the foreclosure rights of the holders of the refinanced indebtedness to a stand-still of not less than 179 days.
SECOND LIEN NOTES. In December 1999, Abraxas and Canadian Abraxas consummated an exchange offer whereby $188,778,000 of the second lien notes were exchanged for $269,699,000 of the old notes. An additional $5,000,000 of the second lien notes were issued in payment of fees and expenses. Interest on the second lien notes is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000. The second lien notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas on or after December 1, 2000, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1 of the years set forth below:
Year Percentage
2000....................................... 105.750% 2001....................................... 102.875% 2002 and thereafter........................ 100.000%
Prior to December 1, 2000, Abraxas and Canadian Abraxas may use all or a portion of the net cash proceeds of one or more equity offerings to redeem up to 50% of the aggregate original principal amount of the second lien notes at a redemption price equal to 111.50% of the principal amount of the second lien notes be redeemed, plus accrued and unpaid interest.
The second lien notes are senior indebtedness of Abraxas and Canadian Abraxas and are secured by a second lien on substantially all of the crude oil and natural gas properties of Abraxas and Canadian Abraxas and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. The second lien notes are unconditionally guaranteed on a senior basis, jointly and severally, by Sandia and Wamsutter. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors. The second lien notes are,
however, effectively subordinated to the first lien notes and related guarantees to the extent the value of the collateral securing the second lien notes and related guarantees and the first lien notes and related guarantees is insufficient to pay both the second lien notes and the first lien notes.
Upon a change of control, each holder of the second lien notes will have the right to require Abraxas and Canadian Abraxas to repurchase such holder's second lien notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase the second lien notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales.
The second lien notes indenture contains certain covenants that limit the ability of Abraxas and Canadian Abraxas and certain of their subsidiaries, including the guarantors of the second lien notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas or Canadian Abraxas.
The second lien notes indenture provides, among other things, that Abraxas and Canadian Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas, Canadian Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary except for such encumbrances or restrictions existing under or by reason of:
(1) applicable law;
(2) the old notes indenture, the first lien notes indenture, or the second lien notes indenture;
(3) customary non-assignment provisions of any contract or any lease governing leasehold interest of such subsidiaries;
(4) any instrument governing indebtedness assumed by us in an acquisition, which encumbrance or restriction is not applicable to such Restricted Subsidiary or the properties or assets of such subsidiary other than the entity or the properties or assets of the entity so acquired;
(5) agreements existing on the Issue Date (as defined in the second lien notes indenture) to the extent and in the manner such agreements were in effect on the Issue Date;
(6) customary restrictions with respect to subsidiaries of Abraxas and Canadian Abraxas pursuant to an agreement that has been entered into for the sale or disposition of capital stock or assets of such Restricted Subsidiary to be consummated in accordance with the terms of the second lien notes solely in respect of the assets or capital stock to be sold or disposed of;
(7) any instrument governing certain liens permitted by the second lien notes indenture, to the extent and only to the extent such instrument restricts the transfer or other disposition of assets subject to such lien; or
(8) an agreement governing indebtedness incurred to refinance the indebtedness issued, assumed or incurred pursuant to an agreement referred to in clause (2), (4) or (5) above; provided, however, that the provisions relating to such encumbrance or restriction contained in any such refinancing indebtedness are no less favorable to the holders of the second lien notes in any material respect as determined by the Board of Directors of Abraxas in their reasonable and good faith judgment that the provisions relating to such encumbrance or restriction contained in the applicable agreement referred to in such clause (2), (4) or (5).
NET OPERATING LOSS CARRYFORWARDS At December 31, 1999, the Company had, subject
to the limitation discussed below, $94,573,000 of net operating loss carryforwards for U.S. tax purposes, of which it is estimated a maximum of $7,260,000 may be utilized before it expires, absent the application of Section 382(h) which allows built-in gains to offset carryforwards otherwise limited by Section 382 of the Internal Revenue Code of 1986, as amended, (Section 382). These loss carryforwards will expire from 2002 through 2018 if not utilized. At December 31, 1999, the Company had approximately $10,262,000 of net operating loss carryforwards for Canadian tax purposes of which $274,000 will expire in 2000, $3,542,000 will expire in 2001, $151,000 will expire in 2002 and $6,295,000 will expire in 2003-2005.
As a result of the acquisition of certain partnership interests and crude oil and natural gas properties in 1990 and 1991, an ownership change under Section 382 occurred in December 1991. Accordingly, it is expected that the use of the U.S. net operating loss carryforwards generated prior to December 31, 19991 of $4,909,000 will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an unrelated corporation. The use of net operating loss carryforwards of the acquired corporation of $837,000 acquired in the acquisition are limited to approximately $115,000 per year.
As a result of the issuance of additional shares of common stock for acquisitions and sales of common stock, an additional ownership change under Section 382 occurred in October 1993. Accordingly, it is expected that the use of all U.S. net operating loss carryforwards generated through October 1993 (including those subject to the 1991 and 1992 ownership changes discussed above) of $8,875,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following the issuance of additional shares, as described in Note 8 of the financial statements. It is expected that the annual use of U.S. net operating loss carryforwards subject to this Section 382 limitation will be limited to approximately $363,000, subject to the lower limitations described above. Future changes in ownership may further limit the use of the Company's carryforwards.
The annual Section 382 limitation may be increased during any year, within 5 years of a change in ownership, in which built-in gains that existed on the date of the change in ownership are recognized.
In addition to the Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, the Company has established a valuation allowance of $32,822,000 and $36,134,000 for deferred tax assets at December 31, 1998 and 1999, respectively.
YEAR 2000
We assessed the impact of the Year 2000 issue on our operations, including developing and implementing project plans and cost estimates required to make our information system infrastructure, information systems and embedded technology Year 2000 compliant. We were advised by the vendors of each of our most material hardware and software systems that such systems were Year 2000 compliant. We also performed independent testing of critical applications to verify the accuracy of such assertions.
In the area of third party suppliers and customers, we monitored and assessed the readiness of such third parties. We monitored third party readiness based on correspondence received from our major vendors and suppliers, review of Year 2000 disclosure in documents filed with the SEC and verbal communications. We did not identify any material problems associated with the Year 2000 readiness efforts of our major suppliers and customers and, other than correspondence, documents filed with the SEC and verbal communications, we did not receive any assurances that such customers and suppliers were Year 2000 compliant.
We spent approximately $120,000 in replacing computer hardware and software
we did not believe to be Year 2000 compliant, some of which we had already anticipated replacing for other reasons. Such expenditures were funded out of our operational cash flows. Based on existing information, we do not anticipate spending any further material amounts in connection with Year 2000 compliance and that any such required amounts would not have a material effect on our financial position, cash flows or results of operations.
As of March 14, 2000, we have not and, to our knowledge, none of our third-party suppliers or customers have experienced any Year 2000 related failures. However, there is a continuing risk of such failures for both us and our third-party suppliers and customers. These failures could result in an interruption in or a failure of certain business activities or functions. Such failures could materially and adversely affect our results of operations, liquidity or financial condition. The principal areas of risk are thought to be oil and gas production control systems, other imbedded operations control systems and third party Year 2000 readiness. Furthermore, there can be no assurance that critical contractors, customers or other parties with which we do business will not experience failures.
We believe that the "most reasonably likely worst case" scenarios are as follows: (i) unanticipated Year 2000 induced failures in information systems could cause a reliance on manual contingency procedures and significantly reduce efficiencies in the performance of certain normal business activities; (ii) unanticipated failures in embedded operations process control systems due to Year 2000 causes could result in temporarily suspending operations at certain operating facilities with consequent loss of revenue; and (iii) slowdowns or disruptions in the third party supply chain due to Year 2000 performance of certain normal business activities.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK; COMMODITY PRICE RISK
COMMODITY PRICE RISK
Our exposure to market risks rest primarily with the volatile nature of crude oil, natural gas and natural gas liquids prices. We manage crude oil and natural gas prices through the periodic use of commodity price hedging agreements. You should read the discussion under "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" for more information regarding our hedging activities. Assuming the production levels we attained during the year ended December 31, 1999, a 10% decline in crude oil, natural gas and natural gas liquids prices would have reduced our operating revenue, cash flow and net income (loss) by approximately $6.0 million for the year.
INTEREST RATE RISK
At December 31, 1999, substantially all of our long-term debt is at fixed interest rates and not subject to fluctuations in market rates.
FOREIGN CURRENCY
Our Canadian operations are measured in the local currency of Canada. As a result , our financial results could be affected by changes in foreign currency exchange rates or weak economic conditions in the foreign markets. Canadian operations reported a pre tax loss of $25.6 million for the year ended December 31, 1999. It is estimated that a 5% change in the value of the U.S. dollar to the Canadian dollar would have changed our net income by approximately $1.3 million. We do not maintain any derivative instruments to mitigate the exposure to translation risk. However, this does not preclude the adoption of specific hedging strategies in the future.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS.
For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements and Schedules.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not Applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There is incorporated in this Item 10 by reference that portion of our definitive proxy statement for the 2000 Annual Meeting of Stockholders which appears therein under the caption "Election of Directors". See also the information in Item 4a of Part I of this Report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
There is incorporated in this Item 11 by reference that portion of our definitive proxy statement for the 2000 Annual Meeting of Stockholders which appears therein under the caption "Executive Compensation", except for those parts under the captions "Compensation Committee Report on Executive Compensation," "Performance Graph" and "Report on Repricing of Options."
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
There is incorporated in this Item 12 by reference that portion of our definitive proxy statement for the 2000 Annual Meeting of Stockholders which appears therein under the caption "Securities Holdings of Principal Stockholders, Directors and Officers."
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
There is incorporated in this Item 13 by reference that portion of our definitive proxy statement for the 2000 Annual Meeting of Stockholders which appears therein under the caption "Certain Transactions."
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)1. Consolidated Financial Statements Page
Report of Ernst & Young, LLP, Independent Auditors.................F-2
Consolidated Balance Sheets, December 31, 1999 and 1998.......................................F-3
Consolidated Statements of Operations, Years Ended December 31, 1999, 1998, and 1997....................F-5
Consolidated Statements of Stockholders' Equity (deficit) Years ended December 31, 1999, 1998 and 1997....................F-7
Consolidated Statements of Cash Flows Years Ended December 31, 1999, 1998 and 1997.....................F-9
Notes to Consolidated Financial Statements........................F-11
(a)2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.
Item 14 (b): Reports on Form 8-K Filed in the Fourth Quarter of 1999
None (a)3.Exhibits
The following Exhibits have previously been filed by the Registrant or are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to Abraxas' Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated October 22, 1990 (Filed as Exhibit 3.3 to the S-4 Registration Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration Statement).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated June 8, 1995. (Filed as Exhibit 3.4 to Abraxas' Registration Statement on Form S-3, No. 333-00398 (the "S-3 Registration Statement")).
3.5 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.5 to the S-3 Registration Statement).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to the S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2 to Abraxas' Annual Report on Form 10-K filed on March 31, 1995).
4.3 Rights Agreement dated as of December 6, 1994 between Abraxas and First Union National Bank of North Carolina ("FUNB"). (Filed as Exhibit 4.1 to Abraxas' Registration Statement on Form 8-A filed on December 6, 1994).
4.4 Amendment to Rights Agreement dated as of July 14, 1997 by and between Abraxas and American Stock Transfer and Trust Company (Filed as Exhibit 1 to Amendment No. 1 to Abraxas' Registration Statement on Form 8-A filed on August 20, 1997).
4.5 Contingent Value Rights Agreement dated December 21, 1999, by and between Abraxas and American Stock Transfer & Trust Company (Filed as Exhibit 4.5 to Abraxas' Registration Statement on Form S-1, No. 333-95281).
4.6 Indenture dated January 27, 1999 by and among Abraxas, Canadian Abraxas and IBJ Schroder Bank & Trust Company (filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K dated February 5, 1999).
4.7 Third Supplemental Indenture dated December 21, 1999, by and among Abraxas, Canadian Abraxas and The Bank of New York f/k/a IBJ Schroder Bank & Trust Company (Filed as Exhibit 4.7 to Abraxas' Registration Statement on Form S-1, No. 333-95281 (the "2000 S-1 Registration Statement")).
4.8 Indenture dated March 26, 1999 by and among Abraxas, Canadian Abraxas, New Cache, Sandia and Norwest Bank Minnesota, National Association (Filed as Exhibit 4.6 to Abraxas' Annual Report on Form 10-K dated March 31, 1999).
4.9 Indenture dated December 21, 1999, by and among Abraxas, Canadian Abraxas, Sandia, New Cache, Wamsutter and Firstar Bank, National Association (Filed as Exhibit T3C to Abraxas' and Canadian Abraxas' Indenture Qualification on Form T3-A, No. 022-22449).
4.10 Form of Old Note (Filed as Exhibit A to Exhibit 4.6).
4.11 Form of First Lien Note (Filed as Exhibit A to Exhibit 4.8).
4.12 Form of Second Lien Note (Filed as Exhibit A to Exhibit 4.9).
*10.1 Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan, as amended and restated. (Filed as Exhibit 10.7 to Abraxas' Annual Report on Form 10-K filed April 14, 1993).
*10.2 Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan, as amended and restated. (Filed as Exhibit 10.8 to Abraxas' Annual Report on Form 10-K filed April 14, 1993).
*10.3 Abraxas Petroleum Corporation 1993 Key Contributor Stock Option Plan. (Filed as Exhibit 10.9 to Abraxas' Annual Report on Form 10-K filed April 14,
*10.4 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as Exhibit 10.4 to Abraxas and Canadian Abraxas' Registration Statement on Form S-4, No. 333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.5 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.6 Abraxas Petroleum Corporation Restricted Share Plan for Directors. (Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
*10.7 Abraxas Petroleum Corporation 1994 Long Term Incentive Plan. (Filed as Exhibit 10.21 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
*10.8 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April 12, 1994).
10.9 Registration Rights and Stock Registration Agreement dated as of August 11, 1993 by and among Abraxas, EEP and Endowment Energy Partners II, Limited Partnership ("EEP II"). (Filed as Exhibit 10.33 to Abraxas' Registration Statement on Form S-1, Registration No. 33-66446 (the "1993 S-1 Registration Statement")).
10.10 First Amendment to Registration Rights and Stock Registration Agreement dated June 30, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit 10.3 to the Registrant's Current Report on Form 8-K filed on July 14, 1994).
10.11 Second Amendment to Registration Rights and Stock Registration Agreement dated September 2, 1994 by and among Abraxas, EEP and EEP II. (Filed as Exhibit 10.3 to Abraxas' Annual Report on Form 10-K filed March 31, 1995)
10.12 Third Amendment to Registration Rights and Stock Registration Agreement dated November 17, 1995 by and among Abraxas, EEP and EEP II. (Filed as Exhibit 10.17 to Abraxas' Annual Report on Form 10-K filed March 31, 1995)
10.13 Common Stock Purchase Warrant dated as of December 18, 1991 between Abraxas and EEP. (Filed as Exhibit 12.3 to Abraxas' Current Report on Form 8-K filed January 9, 1992).
10.14 Common Stock Purchase Warrant dated as of August 1, 1993 between Abraxas and EEP. (Filed as Exhibit 10.35 to the 1993 S-1 Registration Statement).
10.15 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and EEP II. (Filed as Exhibit 10.36 to the 1993 S-1 Registration Statement).
10.16 Common Stock Purchase Warrant dated August 11, 1993 between Abraxas and Associated Energy Managers, Inc. (Filed as Exhibit 10.37 to the 1993 S-1 Registration Statement).
10.17 Letter dated September 2, 1994 from Abraxas to EEP and EEP II. (Filed as Exhibit 10.13 to Abraxas' Annual Report on Form 10-K filed March 31, 1995)
10.18 Form of Indemnity Agreement between Abraxas and each of its directors and officers. (Filed as Exhibit 10.30 to the 1993 S-1 Registration Statement).
*10.19 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as Exhibit 10.23 to the S-3 Registration Statement).
*10.20 Employment Agreement between Abraxas and Chris E. Williford. (Filed as Exhibit 10.24 to the S-3 Registration Statement).
*10.21 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as Exhibit 10.26 to the S-3 Registration Statement).
*10.22 Employment Agreement between Abraxas and Robert W. Carington, Jr. (Filed as Exhibit 10.25 to Abraxas' Annual Report on Form 10-K dated March 31, 1999).
10.23 Registration Rights Agreement dated as of March 26, 1999 by and among Abraxas, Canadian Abraxas, New Cache, Sandia and Jefferies & Company, Inc. (Filed as Exhibit 10.26 to Abraxas' Annual Report on Form 10-K dated March 31, 1999).
10.24 Management Agreement dated November 14, 1996 by and between Canadian Abraxas and Cascade Oil & Gas Ltd. (Filed as Exhibit 10.36 to the Exchange Offer Registration Statement).
10.25 Agreement of Limited Partnership of Abraxas Wamsutter L.P. dated as of November 12, 1999 by and between Wamsutter Holdings, Inc. and TIFD III-X Inc. (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed November 30,1999).
10.26 Registration Rights Agreement dated December 21, 1999, by and among Abraxas, Jefferies & Company, Inc. and Houlihan Lokey Howard & Zukin Capital. (Filed as Exhibit 10.26 to the 2000 S-1 Registration Statement).
10.27 Registration Rights Agreement dated December 21, 1999, by and among Abraxas, Halcyon/Alan B. Slifka Management Company LLC and Franklin Resources, Inc. (Filed as Exhibit 10.27 to the 1999 S-1 Registration Statement).
21.1 Subsidiaries of Abraxas. (Filed herewith).
23.1 Consent of Independent Auditors. (Filed herewith).
23.2 Consent of DeGolyer and MacNaughton. (Filed herewith).
23.3 Consent of McDaniel & Associates Consultants, Ltd. (Filed herewith).
27.1 Financial Data Schedule (Filed herewith).
* Management Compensatory Plan or Agreement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to the signed on its behalf by the undersigned, thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
By: /s/ Robert L.G. Watson By: /s/ Chris Williford -------------------------- ----------------------------- President and Principal Executive Vice President and Executive Officer Principal Financial and Accounting Officer DATED:
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
Signature Name and Title Date - -------------------------- --------------------------------------- --------- /s/ Robert L.G. Watson Chairman of the Board, Robert L.G. Watson President (Principal Executive Officer) and Director 4/5/2000
/s/ Chris Williford Exec. Vice President and Chris Williford Treasurer (Principal Financial and Accounting Officer) 4/5/2000
/s/Craig S. Bartlett, Jr. Director 4/5/2000 Craig S. Bartlett, Jr.
/s/ Franklin A. Burke Director 4/5/2000 Franklin Burke
/s/ Ralph F. Cox Director 4/5/2000 Ralph F. Cox
/s/ Fredrick. M. Pevow, Jr. Director 4/5/2000 Fredrick M. Pevow, Jr.
/s/ James C. Phelps Director 4/5/2000 James C. Phelps
/s/ Joseph A. Wagda Director 4/5/2000 Joseph A. Wagda
Exhibit 22.1
SUBSIDIARIES OF ABRAXAS
Abraxas Petroleum Corporation A Nevada Corporation ("Abraxas")
Canadian Abraxas Petroleum Limited, a Canada corporation ("Canadian Abraxas") and wholly owned subsidiary of Abraxas
Grey Wolf Exploration Inc. an Alberta corporation ("Grey Wolf") Abraxas owns 49% of the capital stock of Grey Wolf
Western Associated Energy Corporation a Texas corporation and wholly owned subsidiary of Abraxas
Sandia Oil & Gas Corporation a Texas corporation ("Sandia") and wholly owned subsidiary of Abraxas
Exhibit 23.1
Consent of Independent Auditors
We consent to the incorporation by reference in the Registration Statements (Form S-8 No. 33-48932) pertaining to Abraxas Petroleum Corporation 1984 Non-Qualified Stock Option Plan; (Form S-8 No. 33-48934) pertaining to Abraxas Petroleum Corporation 1984 Incentive Stock Option Plan; (Form S-8 No. 33-72268) pertaining to the Abraxas Petroleum Corporation 1993 Key Contribution Stock Option Plan; (Form S-8 No. 33-81416) pertaining to the Abraxas Petroleum Corporation Restricted Share Plan for Directors; (Form S-8 No. 33-81418) pertaining to Abraxas Petroleum Corporation 1994 Long Term Incentive Plan; (Form S-8 No. 333-17375) pertaining to the Abraxas Petroleum Corporation Director Stock Option Plan; and (Form S-8 No. 333-17377) pertaining to the Abraxas Petroleum Corporation 401 (K) Profit Sharing Plan of our report dated March 17, 2000,except for Notes 2 and 18, as to which the date is March 31, 2000 with respect to the consolidated financial statements of Abraxas Petroleum Corporation included in this Annual Report (Form 10-K) for the year ended December 31, 1999.
Ernst & Young LLP
San Antonio, Texas March 31, 2000
Exhibit 23.2
Consent of DeGolyer and MacNaughton
We hereby consent to the incorporation in your Annual Report on Form 10-K of the references to DeGolyer and MacNaughton in the "Reserves Information" section on page 21 and to the use by reference of information contained in our Appraisal Report as of December 31, 1999 on Certain Interests owned by Abraxas Petroleum Corporation provided, however, that since the crude oil, condensate, natural gas reserves estimates, as of December 31, 1999, set forth in this Report have been combined with reserve estimates of other petroleum consultants, we are necessarily unable to verify the accuracy of the reserves values contained in the aforementioned Annual Report.
DeGolyer and MacNaughton
Dallas, Texas March 31, 2000
Exhibit 23.3
Consent of McDaniel and Associates Consultants LTD.
We consent to the incorporation in your Annual Report on Form 10-K of the references to McDaniel and Associates Consultants Ltd. in the "Reserves Information" section and to the use by reference of information contained in our Evaluation Report "Canadian Abraxas Petroleum Ltd., Evaluation of Oil & Gas Reserves, As of January 1, 2000", dated March 29, 2000
McDaniel & Associates Consultants LTD
Calgary, Alberta March 29, 2000
NDEX TO FINANCIAL STATEMENTS
Page Abraxas Petroleum Corporation and Subsidiaries
Report of Independent Auditors .............................................F-2 Consolidated Balance Sheets at December 31, 1998 and 1999 ..................F-3 Consolidated Statements of Operations for the years ended December 31, 1997,1998 and 1999 .........................................F-5 Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 1997, 1998 and 1999 .....................F-6 Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1998 and 1999 ........................................F-8 Notes to Consolidated Financial Statements .................................F-10
The Board of Directors and Stockholders Abraxas Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Abraxas Petroleum Corporation and Subsidiaries as of December 31, 1998 and 1999, and the related consolidated statements of operations, stockholders' equity (deficit), 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 auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Abraxas Petroleum Corporation and Subsidiaries at December 31, 1998 and 1999, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
ERNST & YOUNG LLP
San Antonio,Texas
March 17, 2000, except for Notes 2 and 18 as to which the date is March 31,2000
See accompanying notes.
See accompanying notes.
See accompanying notes.
See accompanying notes.
See accompanying notes.
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1997, 1998, and 1999
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an independent energy company engaged in the exploration for and the acquisition, development, and production of crude oil and natural gas primarily along the Texas Gulf Coast, in the Permian Basin of western Texas, and in Canada and the processing of natural gas primarily in Canada. The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Management believes that it is reasonably possible that estimates of proved crude oil and natural gas revenues could significantly change in the future.
Concentration of Credit Risk
Financial instruments which potentially expose the Company to credit risk consist principally of trade receivables, interest rate and crude oil and natural gas price swap agreements. Accounts receivable are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and, generally, requires no collateral from its customers.
Equipment Inventory
Equipment inventory principally consists of casing, tubing, and compression equipment and is carried at the lower of cost or market.
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil and natural gas properties. Under this method, all costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. The Company does not capitalize internal costs. Depreciation, depletion, and amortization ("DD&A") of capitalized crude oil and natural gas properties and estimated future development costs, excluding unevaluated, unproved properties, are based on the unit-of-production method based on proved reserves. Net capitalized costs of crude oil and natural gas properties, less related deferred taxes, are limited, by country, to the lower of unamortized cost or the cost ceiling, defined as the sum of the present value of estimated future net revenues from proved reserves based on unescalated prices discounted at 10 percent, plus the cost of properties not being amortized, if any, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any, less related income taxes. Excess costs are charged to proved property impairment expense. No gain or loss is recognized upon sale or disposition of crude oil and natural gas properties, except in unusual circumstances.
Unevaluated properties not currently being amortized included in oil and gas properties were approximately $10,675,000 and $17,057,000 at December 31, 1998 and 1999, respectively. The properties represented by these costs were undergoing exploration activities or are properties on which the Company intends to commence activities in the future. The Company believes that the unevaluated properties at December 31, 1999 will be substantially evaluated in six to thirty-six months and it will begin to amortize these costs at such time.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost. Depreciation of gas gathering and processing facilities and other property and equipment is provided over the estimated useful lives using the straight-line method. Major renewals and betterments are recorded as additions to the property and equipment accounts. Repairs that do not improve or extend the useful lives of assets are expensed.
Hedging
The Company periodically enters into contracts to hedge the risk of future crude oil and natural gas price fluctuations. Such contracts may either fix or support crude oil and natural gas prices or limit the impact of price fluctuations with respect to the Company's sales of crude oil and natural gas. Gains and losses on such hedging activities are recognized in oil and gas production revenues when hedged production is sold.
Stock-Based Compensation
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," ("Statement 123") encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock.
Foreign Currency Translation
The functional currency for the Company's Canadian operations is the Canadian dollar. The Company translates the functional currency into U.S. dollars based on the current exchange rate at the end of the period for the balance sheet and a weighted average rate for the period on the statement of operations. Translation adjustments are reflected as Accumulated Other Comprehensive Income (Loss) in Stockholders' Equity (Deficit).
Fair Value of Financial Instruments
The Company includes fair value information in the notes to consolidated financial statements when the fair value of its financial instruments is materially different from the book value. The Company assumes the book value of those financial instruments that are classified as current approximates fair value because of the short maturity of these instruments. For noncurrent financial instruments, the Company uses quoted market prices or, to the extent that there are no available quoted market prices, market prices for similar instruments.
Restoration, Removal and Environmental Liabilities
The estimated costs of restoration and removal of major processing facilities are accrued on a straight-line basis over the life of the property. The estimated future costs for known environmental remediation requirements are accrued when it is probable that a liability has been incurred and the amount of remediation costs can be reasonably estimated. These amounts are the undiscounted, future estimated costs under existing regulatory requirements and using existing technology.
Revenue Recognition
The Company recognizes crude oil and natural gas revenue from its interest in producing wells as crude oil and natural gas is sold from those wells net of royalties. Revenue from the processing of natural gas is recognized in the period the service is performed.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over the term of the related debt.
Federal Income Taxes
The Company records income taxes using the liability method. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", which is required to be adopted in years beginning after June 15, 1999. In June 1999, SFAS No. 137 was issued, which delays the required adoption of SFAS No. 133 by one year. The statement permits early adoption as of the beginning of any fiscal quarter after its issuance. The Statement will require the Company to recognize all derivatives on the balance sheet at fair value. Derivatives that are not hedges must be adjusted to fair value through income. If the derivative is a hedge, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities, of firm commitments through earnings or recognized in other comprehensive income until the hedge item is recognized in earnings. The ineffective portion of a derivative's change in fair value will be immediately recognized in earnings. The Company has not yet determined the effect of SFAS No. 133 will be on the earnings and financial position of the Company.
2. Liquidity
The Company's operating results have been adversely affected by low crude oil and natural gas prices in 1998 and early 1999. In addition, the Company has significant semi annual interest payments due on its long term debt.
As a result of these conditions, the Company has issued $63.5 million of debt securities ("First Lien Notes") in March 1999. These securities are secured by substantially all of the Company's crude oil and natural gas properties and natural gas processing facilities and the shares of Grey Wolf owned by the Company and bear interest at 12.875%, payable semi-annually on March 15 and September 15. The Senior Notes will mature in 2003. Proceeds from the Senior Notes were used to pay-off the Company's Credit Facility, pay-off approximately $10 million of debt assumed in connection with the Company's acquisition of New Cache in January 1999 with the remainder being used for general corporate purposes.
In October 1999 the Company entered into a non-recourse Dollar Denominated Production Payment agreement (the "Production Payment") with a third party. The Production Payment has an aggregate total availability of up to $50 million, subject to third party approval. The Production Payment relates to a portion of the production from several natural gas wells in the Edwards Trend, in south Texas. As of December 31, 1999, the Company had received $4.0 million under this agreement. The outstanding balance as of December 31, 1999 is $3.5 million.
In December 1999, Abraxas and Canadian Abraxas completed an exchange offer whereby they exchanged $189 million in 11.5% Second Lien Notes (the "Second Lien Notes"), Abraxas common stock, and contingent value rights for approximately $270 million of the 11.5% Senior Notes (the "Senior Notes"). The Second Lien Notes are senior obligations of Abraxas and Canadian Abraxas and are jointly and severally guaranteed by Sandia Oil and Gas Corporation ("Sandia") and Wamsutter Holdings, Inc. ("Wamsutter"), 100% owned subsidiaries of Abraxas. The Second Lien Notes and the guarantees are secured by a second lien or charge on substantially all of the crude oil and natural gas properties and natural gas processing plants owned by Abraxas, Canadian Abraxas, Sandia and Wamsutter, as well as shares of common stock of Grey Wolf owned by Abraxas and Canadian Abraxas. The exchange offer reduced our long term debt by $76.6 million and annual interest payments by approximately $8.8 million.
In March 2000, the Company sold it's interests in certain crude oil and natural gas properties in Wyoming. Simultaneously, a limited partnership, in which the Company had an economic interest, sold its crude oil and natural gas properties in the same area. The Company realized $34 million in net proceeds from the sale, which will enable the Company to meet its interest obligations throughout 2000.
The Company has implemented a number of measures to conserve its cash resources, including postponement of certain exploration and development projects. However, while these measures will help conserve the Company's cash resources in the near term, they will also limit the Company's ability to replenish its depleting reserves, which could negatively impact the Company's operating cash flow and results of operations in the future.
With 2000 interest obligations funded from proceeds of the above described sale of the Company's partnership interest and certain Wyoming crude oil and natural gas properties, the Company will have sufficient operating cash flows to enable the Company to continue operating in the ordinary course of business.
3. Acquisitions and Divestitures
Pacalta Properties Acquisition
In October 1997, Canadian Abraxas Petroleum Limited (Canadian Abraxas), a wholly owned subsidiary of the Company, and Grey Wolf Exploration, Inc. (Grey Wolf) completed the acquisition of the Canadian assets of Pacalta Resources Ltd. (Pacalta Properties) for approximately $14,000,000 (CDN$20,000,000) and four million Grey Wolf special warrants valued at approximately $1,375,000. Canadian Abraxas acquired an approximate 92% interest in the Pacalta Properties, and Grey Wolf acquired an approximate 8% interest. In July 1998 Grey Wolf acquired the remaining 92% interest in the Pacalta Properties from Canadian Abraxas.
The acquisition was accounted for as a purchase, and the purchase price was allocated to the crude oil and natural gas properties based on the fair values of the properties acquired. The transaction was financed through an advance from the Company with funds which were obtained through borrowings under the Company's Credit Facility.
Wyoming Properties Divestiture
In November 1998, the Company sold its interest in the Wyoming Properties to Abraxas Wamsutter L.P. a Texas limited partnership (the "Partnership") for approximately $58.6 million and a minority equity ownership in the Partnership. A subsidiary of the Company, Wamsutter Holdings, Inc. a Wyoming corporation, (the "General Partner"), will initially own a one percent interest and act as General Partner of the Partnership. After certain payback requirements are satisfied, the Company's interest will increase to 35% initially and could increase to as high as 65%. The Company will also receive a management fee and reimbursement of certain overhead costs from the Partnership.
New Cache Petroleums LTD Acquisition
In January 1999, the Canadian Abraxas completed the acquisition of New Cache Petroleums, LTD, ("New Cache"), for approximately $78 million in cash and the assumption of approximately $10 million in debt. The debt was paid off with a portion of the proceeds from the sale of $63.5 million 12.875% Senior Secured Notes in March 1999.
The acquisition was accounted for as a purchase, and the purchase price was allocated to the crude oil and natural gas properties based on the fair values of the properties acquired. Results of operations for New Cache Properties have been included in the consolidated financial statements since January 1999.
The condensed pro forma financial information presented below summarizes on an unaudited pro forma basis, approximate results of the Company's consolidated results of operations for the year ended December 31, 1998, assuming the acquisition of New Cache Petroleums LTD had occurred on January 1, 1998.
December 31, 1998 (In thousands except per share data) ----------------------- Revenue ................................. $ 77,882 ======================= Net income (loss) ....................... $ (107,607) ======================= Income (loss) per common share .......... $ (17.00) =======================
4. Property and Equipment
The major components of property and equipment, at cost, are as follows:
Estimated Useful Life 1998 1999 ----------------------------------- Years (In thousands)
Land, buildings, and improvements .... 15 $ 309 $ 310 Crude oil and natural gas properties . - 335,207 468,081 Natural gas processing plants ........ 18 36,583 42,863 Equipment and other .................. 7 2,217 3,099 -------- --------- $374,316 $ 514,353 ======== =========
5. Long-Term Debt
Long-term debt consists of the following:
Long-Term Indebtedness
On November 14, 1996, the Company consummated the offering of $215.0 million of it's 11.5% Senior Notes due 2004, Series A, which were exchanged for the Series B Notes in February 1997. On January 27, 1998, the Company completed the sale of $60.0 million of the Series C Notes. The Series B Notes and the Series C Notes were subsequently combined into $275.0 million in principal amount of the Old Notes in June 1998.
Interest on the Old Notes is payable semi-annually in arrears on May 1 and November 1 of each year at the rate of 11.5% per annum. The Old Notes are redeemable, in whole or in part, at the option of the Company, on or after November 1, 2000, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on November 1 of the years set forth below:
Year Percentage
2000................................................. 105.750% 2001................................................. 102.875% 2002 and thereafter.................................. 100.000%
The Old Notes are joint and several obligations of the Company and rank pari passu in right of payment to all existing and future unsubordinated indebtedness of the Company. The Old Notes rank senior in right of payment to all future subordinated indebtedness of the Company. The Old Notes are, however, effectively subordinated to the First Lien Notes to the extent of the value of the collateral securing the First Lien Notes and the Second Lien Notes to the extent of the value of the collateral securing the Second Lien Notes. The Old Notes are unconditionally guaranteed, on a senior basis by Sandia Oil and Gas Corporation ("Sandia"), a wholly owned subsidiary of Abraxas. The guarantee is a general unsecured obligation of Sandia and ranks pari passu in right of payment to all unsubordinated indebtedness of Sandia and senior in right of payment to all subordinated indebtedness of Sandia. The guarantee is effectively subordinated to the First Lien Notes and the Second Lien Notes to the extent of the value of the collateral.
Upon a Change of Control (as defined in the Old Notes indenture), each holder of the Old Notes will have the right to require the Company to repurchase all or a portion of such holder's Old Notes at a redemption price equal to 101% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. In addition, the Company will be obligated to offer to repurchase the Old Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase in the event of certain asset sales.
First Lien Notes. In March 1999, Abraxas consummated the sale of $63.5 million of the First Lien Notes. Interest on the First Lien Notes is payable semi-annually in arrears on March 15 and September 15, commencing September 15, 1999. The First Lien Notes are redeemable, in whole or in part, at the option of Abraxas on or after March 15, 2001, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on March 15 of the years set forth below:
Year Percentage
2001............................................ 103.000% 2002 and thereafter............................. 100.000%
At any time, or from time to time, prior to March 15, 2001, Abraxas may, at its option, use all or a portion of the net cash proceeds of one or more equity offerings to redeem up to 35% of the aggregate original principal amount of the First Lien Notes at a redemption price equal to 112.875% of the aggregate principal amount of the First Lien Notes be redeemed, plus accrued and unpaid interest.
The First lien notes are senior indebtedness of Abraxas secured by a first lien on substantially all of the crude oil and natural gas properties of Abraxas and the shares of Grey Wolf owned by Abraxas. The First Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Canadian Abraxas, Sandia and Wamsutter. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors and the shares of Grey Wolf owned by Canadian Abraxas.
Upon a Change of Control, each holder of the First Lien Notes will have the right to require Abraxas to repurchase such holder's First Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas will be obligated to offer to repurchase the First Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales.
The First Lien Notes indenture contains certain covenants that limit the ability of Abraxas and certain of its subsidiaries, including the guarantors of the First Lien Notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas.
The First Lien Notes indenture provides, among other things, that Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas or any other Restricted Subsidiary except in certain situations as described in the First Lien Notes indenture.
Second Lien Notes. In December 1999, Abraxas and Canadian Abraxas consummated an exchange offer whereby $188,778,000 of the Second Lien Notes were exchanged for $269,699,000 of the Old Notes. An additional $5,000,000 of the Second Lien Notes were issued in payment of fees and expenses. Interest on the Second Lien Notes is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2000. The Second Lien Notes are redeemable, in whole or in part, at the option of Abraxas and Canadian Abraxas on or after December 1, 2000, at the redemption prices set forth below, plus accrued and unpaid interest to the date of redemption, if redeemed during the 12-month period commencing on December 1 of the years set forth below:
Year Percentage ----- ---------- 2000............................................ 105.750% 2001............................................ 102.875% 2002 and thereafter............................. 100.000%
Prior to December 1, 2000, Abraxas and Canadian Abraxas may use all or a portion of the net cash proceeds of one or more equity offerings to redeem up to 50% of the aggregate original principal amount of the Second Lien Notes at a redemption price equal to 111.50% of the principal amount of the Second Lien Notes be redeemed, plus accrued and unpaid interest.
The Second Lien Notes are senior indebtedness of Abraxas and Canadian Abraxas and are secured by a second lien on substantially all of the crude oil and natural gas properties of Abraxas and Canadian Abraxas and the shares of Grey Wolf owned by Abraxas and Canadian Abraxas. The Second Lien Notes are unconditionally guaranteed on a senior basis, jointly and severally, by Sandia and Wamsutter. The guarantees are secured by substantially all of the crude oil and natural gas properties of the guarantors. The Second Lien Notes are, however, effectively subordinated to the First Lien Notes and related guarantees to the extent the value of the collateral securing the Second Lien Notes and related guarantees and the First Lien Notes and related guarantees is insufficient to pay both the Second Lien Notes and the First Lien Notes.
Upon a change of control, each holder of the Second Lien Notes will have the right to require Abraxas and Canadian Abraxas to repurchase such holder's Second Lien Notes at a redemption price equal to 101% of the principal amount thereof plus accrued and unpaid interest to the date of repurchase. In addition, Abraxas and Canadian Abraxas will be obligated to offer to repurchase the Second Lien Notes at 100% of the principal amount thereof plus accrued and unpaid interest to the date of redemption in the event of certain asset sales.
The Second Lien Notes indenture contains certain covenants that limit the ability of Abraxas and Canadian Abraxas and certain of their subsidiaries, including the guarantors of the Second Lien Notes (the "Restricted Subsidiaries") to, among other things, incur additional indebtedness, pay dividends or make certain other restricted payments, consummate certain asset sales, enter into certain transactions with affiliates, incur liens, merge or consolidate with any other person or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the assets of Abraxas or Canadian Abraxas.
The Second Lien Notes indenture provides, among other things, that Abraxas and Canadian Abraxas may not, and may not cause or permit the Restricted Subsidiaries, to, directly or indirectly, create or otherwise cause to permit to exist or become effective any encumbrance or restriction on the ability of such subsidiary to pay dividends or make distributions on or in respect of its capital stock, make loans or advances or pay debts owed to Abraxas, Canadian Abraxas or any other Restricted Subsidiary, guarantee any indebtedness of Abraxas, Canadian Abraxas or any other Restricted Subsidiary or transfer any of its assets to Abraxas, Canadian Abraxas or any other Restricted Subsidiary except in certain situations as described in the Second Lien Notes indenture.
The fair value of the Old Notes, First Lien Notes and Second Lien Notes was approximately $244.4 million as of December 31, 1999. The Company has approximately $1,230,000 of standby letters of credit and a $30,000 performance
bond open at December 31, 1999. Approximately $30,000 of cash is restricted and in escrow related to certain of the letters of credit and bond.
Contingent Value Rights ("CVRs")
As part of the exchange offer consummated by the Company in December 1999, Abraxas issued contingent value rights or CVRs, which may entitle the holders of the notes to receive up to a total of 105,408,978 of Abraxas common stock. On December 20, 2000, or at the election of Abraxas, on May 21, 2001, Abraxas may be required to issue additional shares to the holders of the contingent value rights. The actual number of shares issued will depend on the market price of Abraxas common stock. The CVRs will terminate if the market price of Abraxas common exceeds certain prices for a period of 30 trading days during any 45 day consecutive trading day period prior to the expiration date. The target price on a given date will equal $5.03 plus daily interest at an annual rate of 11.5%. On December 21, 2000, the target price will be $5.64. If the Company elects to extend the target date to May 21, 2001 the target price will be $5.97. If the number of shares ultimately issuable under CVRs is greater than the number of authorized and unissued shares available at the time, the Company will be required to increase the number of shares of Abraxas common stock in order to increase the number of authorized and unissued shares of Abraxas common stock to an amount sufficient to satisfy the number of shares issuable under the CVRs.
Capitalized Interest
During 1997 1998 and 1999 the Company capitalized $966,000, $414,000 and $193,000 of interest expense, respectively.
6. Stockholders' Equity
Common Stock
In 1994, the Board of Directors adopted a Stockholders' Rights Plan and declared a dividend of one Common Stock Purchase Right (Rights) for each share of common stock. The Rights are not initially exercisable. Subject to the Board of Directors' option to extend the period, the Rights will become exercisable and will detach from the common stock ten days after any person has become a beneficial owner of 20% or more of the common stock of the Company or has made a tender offer or exchange offer (other than certain qualifying offers) for 20% or more of the common stock of the Company.
Once the Rights become exercisable, each Right entitles the holder, other than the acquiring person, to purchase for $20 one-half of one share of common stock of the Company having a value of four times the purchase price. The Company may redeem the Rights at any time for $.01 per Right prior to a specified period of time after a tender or exchange offer. The Rights will expire in November 2004, unless earlier exchanged or redeemed.
Treasury Stock
In March 1996, the Board of Directors authorized the purchase in the open market of up to 500,000 shares of the Company's outstanding common stock, the aggregate purchase price not to exceed $3,500,000. During the year ended December 31, 1998, 136,255 shares with an aggregate purchase price of $980,000 were purchased. During the years ended December 31, 1997 and 1999 the Company did not purchase any shares of its common stock for treasury stock.
7. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and key employees under various stock option and incentive plans.
The Company's various stock option plans have authorized the grant of options to management personnel and directors for up to approximately 2.1 million shares of the Company's common stock. All options granted have ten year terms and vest and become fully exercisable over three to four years of continued service at 25% to 33% on each anniversary date. At December 31, 1999 approximately 258,000 options remain available for grant.
Pro forma information regarding net income (loss) and earnings (loss) per share is required by Statement 123, which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to December 31, 1994 under the fair value method of that Statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1997, 1998, and 1999, respectively: risk-free interest rates of 6.25%, 6.25% and 6.25%, respectively; dividend yields of -0-%; volatility factors of the expected market price of the Company's common stock of .529, .667 and .928, respectively; and a weighted-average expected life of the option of six years.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information follows:
A summary of the Company's stock option activity, and related information for the years ended December 31, follows:
Exercise prices for options outstanding as of December 31, 1999 ranged from $0.97 to $2.06 The weighted-average remaining contractual life of those options is approximately 8.5 years.
(1) In March 1998, the Company amended the exercise price to $7.44 per share on all options with an existing exercise price greater than $7.44.
(2) In March 1999, the Company amended the exercise price to $2.06 per share on all options with an existing exercise price greater than $2.06. Certain of these options are not exercisable until the Company's stock price is $4.12 per share for ten days out of a thirty day period.
Stock Awards
In addition to stock options granted under the plans described above, the Long-Term Incentive Plan also provides for the right to receive compensation in cash, awards of common stock, or a combination thereof. In 1997, 1998, and 1999, the Company made direct awards of common stock of 14,748 shares, 18,263 shares and 18,932 shares, respectively, at weighted average fair values of $10.75, $5.13 and $5.09 per share, respectively.
The Company also has adopted the Restricted Share Plan for Directors which provides for awards of common stock to nonemployee directors of the Company who did not, within the year immediately preceding the determination of the director's eligibility, receive any award under any other plan of the Company. In 1997, 1998, and 1999, the Company made direct awards of common stock of 7,735 shares, 4,838 shares and 3,314 shares, respectively, at weighted average fair values of $9.87, $14.75 and $4.38 per share, respectively.
During 1996, the Company's stockholders approved the Abraxas Petroleum Corporation Director Stock Option Plan (Plan), which authorizes the grant of nonstatutory options to acquire an aggregate of 104,000 common shares to those persons who are directors and not officers of the Company. No options were granted during 1997, during 1998 each of the seven eligible directors were granted an option to purchase 2,000 common shares at $7.44 and 3,000 common shares at $5.56. An additional option was granted to an eligible director to purchase 4,000 common shares at $7.44. In March 1999 each of the seven eligible directors were granted an option to purchase 2,000 common shares at $2.06, in November 1999 five of the eligible directors were granted options to purchase 15,000 common shares at $1.41. In December 1999 a new board was appointed in connection with the Company's exchange offer, each of the four new eligible directors were granted options for 75,000 common shares at $0.97.
Stock Warrants
Warrants to purchase 13,500 shares of the Company's common stock at $7.00 per share remain outstanding from previous grants.
At December 31, 1999 the Company has approximately 62,572,000 shares reserved for future issuance for conversion of its stock options, warrants, Contingent Value Rights, and incentive plans for the Company's directors and employees.
8. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company's deferred tax liabilities and assets are as follows:
December 31 ---------------------- 1998 1999 ---------------------- (In thousands) Deferred tax liabilities: U.S. full cost pool ..................... $ -- $ -- Canadian full cost pool ................. 19,753 20,368 State taxes ............................. 67 67 Other ................................... 14 -- -------- -------- Total deferred tax liabilities ............ 19,834 20,435 Deferred tax assets: U.S. full cost pool ..................... 15,803 6,252 Depletion ............................... 1,075 1,075 Net operating losses .................... 15,841 32,155 Other ................................... 117 152 -------- -------- Total deferred tax assets ................. 32,836 39,634 Valuation allowance for deferred tax assets (32,822) (36,134) -------- -------- Net deferred tax assets ................... 14 3,500 -------- -------- Net deferred tax liabilities .............. $ 19,820 $ 16,935 ======== ========
Significant components of the provision (benefit) for income taxes are as follows:
1997 1998 1999 ------------ ----------- --------- Current: Federal ................... $ - $ - $ - State ..................... - - - Foreign ................... 244 231 491 ------------ ----------- --------- $ 244 $ 231 $ 491 ============ =========== ========= Deferred: Federal ................... $ - $ - $ - State ..................... - - - Foreign ................... (4,135) (4,389) (13,116) ------------ ----------- ---------- $(4,135) $(4,389) $ (13,116) ============ =========== ==========
At December 31, 1999, the Company had, subject to the limitation discussed below, $94,573,000 of net operating loss carryforwards for U.S. tax purposes, of which it is estimated a maximum of $7,260,000 may be utilized before it expires, absent the application of Section 382(h) which allows built-in gains to offset carryforwards otherwise limited by Section 382 of the Internal Revenue Code of 1986, as amended, (Section 382). These loss carryforwards will expire from 2002 through 2018 if not utilized. At December 31, 1999, the Company had approximately $10,262,000 of net operating loss carryforwards for Canadian tax purposes of which $274,000 will expire in 2000, $3,542,000 will expire in 2001, $151,000 will expire in 2002 and $6,295,000 will expire in 2003-2005.
As a result of the acquisition of certain partnership interests and crude oil and natural gas properties in 1990 and 1991, an ownership change under Section 382 occurred in December 1991. Accordingly, it is expected that the use of the U.S. net operating loss carryforwards generated prior to December 31, 19991 of $4,909,000 will be limited to approximately $235,000 per year.
During 1992, the Company acquired 100% of the common stock of an unrelated corporation. The use of net operating loss carryforwards of the acquired corporation of $837,000 acquired in the acquisition are limited to approximately $115,000 per year.
As a result of the issuance of additional shares of common stock for acquisitions and sales of common stock, an additional ownership change under Section 382 occurred in October 1993. Accordingly, it is expected that the use of all U.S. net operating loss carryforwards generated through October 1993 (including those subject to the 1991 and 1992 ownership changes discussed above) of $8,875,000 will be limited as described above and in the following paragraph.
An ownership change under Section 382 occurred in December 1999, following the issuance of additional shares, as described in Note 5. It is expected that the annual use of U.S. net operating loss carryforwards subject to this Section 382 limitation will be limited to approximately $363,000, subject to the lower limitations described above. Future changes in ownership may further limit the use of the Company's carryforwards.
The annual Section 382 limitation may be increased during any year, within 5 years of a change in ownership, in which built-in gains that existed on the date of the change in ownership are recognized.
In addition to the Section 382 limitations, uncertainties exist as to the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. Therefore, the Company has established a valuation allowance of $32,822,000 and $36,134,000 for deferred tax assets at December 31, 1998 and 1999, respectively.
The reconciliation of income tax attributable to continuing operations computed at the U.S. federal statutory tax rates to income tax expense is:
December 31 --------------------------------- 1997 1998 1999 --------- --------- ---------- (In thousands) Tax (expense) benefit at U.S. .... statutory rates (34%) .......... $ 3,414 $ 29,958 $ 16,672 (Increase) decrease in deferred tax asset valuation allowance .. (259) (26,907) (3,312) Higher effective rate of foreign operations ..................... (244) (231) (491) Percentage depletion ............. 499 146 -- Other ............................ 481 1,192 (244) ------- -------- -------- $ 3,891 $ 4,158 $ 12,625 ======= ======== ========
9. Related Party Transactions
Accounts receivable from affiliates, officers, and stockholders represent amounts receivable relating to joint interest billings on properties which the Company operates and advances made to officers.
In January 1996, Grey Wolf purchased newly issued shares of Cascade representing 66 2/3% of Cascade's capital stock., in 1997 Grey Wolf merged with Cascade and the name was changed to Grey Wolf Exploration, Inc. ("Grey Wolf"). At December 31, 1999, the Company owns approximately 49% of Grey Wolf. The Company's President as well as certain directors directly own approximately 5% of Grey Wolf. Additionally the Company's President owns options to purchase up to 80,000 shares of Grey Wolf capital stock at an exercise price of CDN$2.00 per share, and certain of the Company's directors own options to purchase in the aggregate up to 100,000 shares of Grey Wolf capital stock at an exercise price of CDN$2.00 per share. Grey Wolf currently has approximately 12,700,000 shares of capital stock outstanding.
Grey Wolf owns a 10% interest in the Canadian Abraxas oil and gas properties and the Canadian Abraxas gas processing plants acquired by Canadian Abraxas in November 1996 from CGGS and a 100% interest in the Pacalta Properties and manages the operations of Canadian Abraxas, pursuant to a management agreement between Canadian Abraxas and Grey Wolf. Under the management agreement, Canadian Abraxas reimburses Grey Wolf for reasonable costs or expenses attributable to Canadian Abraxas and for administrative expenses based upon the percentage that Canadian Abraxas' gross revenue bears to the total gross revenue of Canadian Abraxas and Grey Wolf.
10. Commitments and Contingencies
Operating Leases
During the years ended December 31, 1997, 1998, and 1999, the Company incurred rent expense of approximately $228,000, $292,000 and $396,000, respectively. Future minimum rental payments are as follows at December 31, 1999:
2000 ................................................... $ 393,900 2001 ................................................... 368,000 2002 ................................................... 242,000 2003 ................................................... 228,000 2004 ................................................... 228,000 Thereafter ............................................. 398,000
Contingencies
In May 1995, certain plaintiffs filed a lawsuit against the Company alleging negligence and gross negligence, tortious interference with contract, conversion and waste. In March 1998, a jury found against the Company and on May 22, 1998, final judgment in the amount of $1.3 million was entered. The Company filed an appeal and in March 2000, the Court of Appeals reduced the plaintiff's award to $362,495 plus post-judgment interest of $68,915. The Company is currently reviewing whether to further appeal this decision. The Company has not established a reserve for this matter at December 31, 1999.
Additionally, from time to time, the Company is involved in litigation relating to claims arising out of its operations in the normal course of business. At December 31, 1999, the Company was not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the Company.
11. Earnings per Share
The following table sets forth the computation of basic and diluted earnings per share:
For the year ended December 31, 1999 none of the shares issuable in connection with stock options, warrants or the Contingent Value rights agreement are included in diluted shares. For the year ended December 31, 1998 none of the shares issuable in connection with stock options or warrants are included in diluted shares. For the year ended December 31, 1997, none of the shares issuable in connection with stock options, warrants, or the conversion of preferred stock are included in diluted shares. Inclusion of these shares would be antidilutive due to losses incurred in those years.
12. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during the years ended December 31, 1998 and 1999 are as follows:
During the fourth quarter of 1998, the Company recorded a write-down of its United States proved crude oil and natural gas properties of approximately $61,224,000 under the ceiling limitation. During the fourth quarter of 1999, the Company recorded a write-down of its Canadian proved crude oil and natural gas properties of approximately $19,100,000 ($11,900,000 after tax) under the ceiling limitation.
13. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all eligible employees of the Company. During 1997 and 1998 the Company contributed 7,440 and 10,329 shares, respectively, of its common stock held in the treasury to the Plan and recorded the fair value of $41,850 and $76,847 respectively, as compensation expense. The Company did not contribute to the plan in 1999. The employee contribution limitations are determined by formulas which limit the upper one-third of the plan members from contributing amounts that would cause the plan to be top-heavy. The employee contribution is limited to the lesser of 20% of the employee's annual compensation or $10,000.
14. Summary Financial Information of Canadian Abraxas Petroleum Ltd.
The following is summary financial information of Canadian Abraxas, a wholly owned subsidiary of the Company. Canadian Abraxas is jointly and severally liable for the entire balance of the Series B Notes ($215,000,000), of which $84,612,000 was utilized by Canadian Abraxas in connection with the 1996 acquisition of Canadian Gas Gathering Systems ("CGGS"). The Company has not presented separate financial statements and other disclosures concerning Canadian Abraxas because management has determined that such information is not material to the holders of the Notes.
15. Business Segments
The Company conducts its operations through two geographic segments, the United States and Canada, and is engaged in the acquisition, development and production of crude oil and natural gas and the processing of natural gas in each country. The Company's significant operations are located in the Texas Gulf Coast, the Permian Basin of western Texas and Canada. Identifiable assets are those assets used in the operations of the segment. Corporate assets consist primarily of deferred financing fees and other property and equipment. The Company's revenues are derived primarily from the sale of crude oil, condensate, natural gas liquids and natural gas to marketers and refiners and from processing fees from the custom processing of natural gas. As a general policy, collateral is not required for receivables; however, the credit of the Company's customers is regularly assessed. The Company is not aware of any significant credit risk relating to its customers and has not experienced significant credit losses associated with such receivables.
In 1999 three customers accounted for approximately 58% of oil and natural gas production and approximately 56% of gas processing revenues. five customers accounted for approximately 79% of United States revenue and three customers accounted for approximately 77% of revenue in Canada. In 1998 four customers accounted for approximately 58% of oil and natural gas production revenues and gas processing revenues. In 1997 three customers accounted for approximately 40% of oil and natural gas production revenues and gas processing revenues.
Business segment information about the Company's 1997 operations in different geographic areas is as follows:
Business segment information about the Company's 1998 operations in different geographic areas is as follows:
Business segment information about the Company's 1999 operations in different geographic areas is as follows:
16. Commodity Swap Agreements
The Company enters into commodity swap agreements (Hedge Agreements) to reduce its exposure to price risk in the spot market for crude oil and natural gas. Pursuant to the Hedge Agreements, either the Company or the counterparty thereto is required to make payment to the other at the end of each month.
In November 1996, the Company assumed swap arrangements extending through October 2001 with a counterparty involving various quantities and fixed prices. These swap arrangements provided that the Company make payments to the counterparty to the extent the market prices, determined based on the price for crude oil on the NYMEX and the Inside FERC, Tennessee Gas Pipeline Co. Texas (Zone O) price for natural gas exceeded certain fixed prices and for the counterparty to make payments to us to the extent the market prices were less than such fixed prices. The Company accounted for the related gains or losses (a gain of $204,600 during the first quarter of 1999) in crude oil and natural gas revenue in the period of the hedged production. These swap arrangements terminated in January 1999 and the Company was paid $750,000 by the counterparty for such termination. This amount is included in other income in the accompanying financial statements.
In March 1998, the Company entered into a costless collar hedge agreement with Enron Capital and Trade Resources Corp. for 2,000 Bbls of crude oil per day with a floor price of $14.00 per Bbl and a ceiling price of $22.30 per Bbl for crude oil on the NYMEX. The agreement was effective April 1, 1998 and extended through March 31, 1999. Under the terms of the agreement the
Company was paid when the average monthly price for crude oil on the NYMEX was below the floor price, and the Company paid the counterparty when the average monthly price exceeded the ceiling price. For the year ended December 31, 1999 the Company realized a loss of $1.8 million on this agreement, which is accounted for in crude oil and natural gas revenue. The Company has also entered into a costless collar hedge agreement with Barrett Resources Corporation ("Barrett") for the period November 1999 through October 2000. This agreement consist of a swap for 1,000 Bbls per day with the Company being paid $20.30 and paying NYMEX calendar month average, and 1,000 barrels per day with a floor price of $18.00 per Bbl and a ceiling of $22.00 per Bbl. Additionally, Barrett has a call on either 1,000 Bbls of crude oil or 20,000 MMBtu of natural gas per day at Barrett's option at fixed prices through October 31, 2002.
As of December 31, 1999, the Company has 22.5 MMBtupd hedged through October 31, 2000, 2.5 MMBtupd is hedged at an average NYMEX price less $0.83 (approximately $1.75 per MMBtu as of February 2000) and 20.0 MMBtupd with a ceiling of $2.39 and a floor of $2.07 based on an AECO index. Both of these hedges are with Barrett Resoucres. In connection with the 20.0 MMBtupd Barrett hedge, the Company realized a loss of $2.5 million for the year ended December 31, 1999, which is accounted for in crude oil and natural gas revenue.
The fair market value of these hedge agreements is approximately $(6.5) million as of December 31, 1999.
17. Proved Property Impairment
In 1997, 1998 and 1999 the Company recorded a write-down of its proved crude oil and natural gas properties of approximately $4,600,000; $61,224,000 and $19,100,000 under the ceiling limitation prescribed for companies following the full cost method of accounting for its oil and gas properties. The write-down in 1997 and 1999 were related to the Company's Canadian oil and gas properties, the 1998 write-down was related to the Company's United States oil and gas properties. The write downs in 1997 and 1998 were due primarily to a decrease in spot market prices for the Company's crude oil and natural gas. The write-down in 1999 was due to a downward revision of the Company's proved reserves in Canada. Under full cost accounting rules, the net capitalized costs of oil and gas properties, less related deferred taxes, are limited by country, to the lower of unamortized cost or the cost ceiling as discussed in Note 1. The risk that the Company will be required to write-down the carrying value of its crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. Depending on future prices, further impairment of the Company's crude oil and natural gas properties may be required.
18. Subsequent Event
In March 2000, the Company sold it's interest in certain crude oil and natural gas properties in Wyoming. Simultaneously, a limited partnership of which one of our subsidiaries was the general partner sold its interest in crude oil and natural gas properties in the same area. Our net proceeds from these transactions were approximately $34.0 million subject to post closing adjustments.
19. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's crude oil and natural gas producing activities as required by Financial Accounting Standards 69, "Disclosures about Oil and Gas Producing Activities." Capitalized costs relating to oil and gas producing activities are as follows:
December 31 ---------------------- 1998 1999 --------- --------- (In thousands)
Proved crude oil and natural gas properties $ 324,532 $ 451,024 Unproved properties ....................... 10,675 17,057 --------- --------- Total ................................... 335,207 468,081 Accumulated depreciation, depletion, and amortization, and impairment ............ (161,593) (215,144) --------- --------- Net capitalized costs ................. $ 173,614 $ 252,937 ========= =========
Cost incurred in oil and gas property acquisitions, exploration and development activities are as follows:
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved crude oil and natural gas reserves as of December 31, 1997, 1998, and 1999. The Company's management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by independent petroleum reserve engineers.
(1) Includes 260,200; 475,400 and 269,000 barrels of liquid hydrocarbon reserves owned by Grey Wolf of which approximately 140,200; 244,000 and 138,000 barrels are applicable to the minority interest's share of these reserves at December 31, 1997, 1998 and 1999, respectively.
(2) Includes 7,446, 28,610 and 21,710 MMcf of natural gas reserves owned by Grey Wolf of which 4,012, 14,700 and 11,140 MMcf are applicable to the minority interest's share of these reserves at December 31, 1997,1998 and 1999, respectively.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following disclosures concerning the standardized measure of future cash flows from proved crude oil and natural gas reserves are presented in accordance with Statement of Financial Accounting Standards No. 69. The standardized measure does not purport to represent the fair market value of the Company's proved crude oil and natural gas reserves. An estimate of fair market value would also take into account, among other factors, the recovery of reserves not classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by applying period-end prices at December 31, 1999, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis of the properties. Operating loss carryforwards, tax credits, and permanent differences to the extent estimated to be available in the future were also considered in the future income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
Year Ended December 31 ---------------------------------- 1997 1998 1999 --------- ----------- ---------- (In thousands)
Standardized Measure, beginning of year ............................. $ 329,821 $ 252,079 $ 181,581 Sales and transfers of oil and gas produced, net of production costs ... (50,945) (37,422) (41,086) Net changes in prices and development and production costs from prior year (190,174) (26,858) 63,539 Extensions, discoveries, and improved recovery, less related costs ........ 49,471 36,187 29,346 Purchases of minerals in place ........ 27,586 28,079 90,510 Sales of minerals in place ............ (5,720) (58,099) (18,562) Revision of previous quantity estimates (8,150) (12,514) (46,659) Change in future income tax expense ... 70,858 (17,727) (6,319) Other ................................. (12,389) (9,005) (19,723) Accretion of discount ................. 41,721 26,861 18,158 --------- --------- --------- Standardized Measure, end of year ... $ 252,079 $ 181,581 $ 250,785 ========= ========= =========