ITEM 1. BUSINESS
General
Pioneer Natural Resources Company ("Pioneer", or the "Company"), a Delaware corporation, was formed by the merger of Parker & Parsley Petroleum Company ("Parker & Parsley") and MESA Inc. ("Mesa") during August 1997. The Company subsequently acquired the Canadian and Argentine oil and gas business of Chauvco Resources Ltd. ("Chauvco"), a publicly traded, independent oil and gas company based in Calgary, Canada, during December 1997. Pioneer is an oil and gas exploration and production company with ownership interests in oil and gas properties located in the United States, Argentina, Canada, South Africa and Gabon.
The combined physical assets and management resources of Parker & Parsley, Mesa and Chauvco have created a company with a solid foundation of complementary assets and industry expertise. This foundation is anchored by the Spraberry oil field located in West Texas, the Hugoton gas field located in Southwest Kansas and the West Panhandle gas field located in the Texas Panhandle. The Spraberry, Hugoton and West Panhandle fields provide consistent and dependable production, cash flow and ongoing development opportunities for the Company. Complementing these areas are the exploration and development opportunities and oil and gas production contributed by Pioneer's assets in the
United States Gulf Coast area, Argentina and Canada. These assets create a portfolio of resources and opportunities that are well balanced between oil, natural gas liquids and natural gas; and, between long- lived, dependable production and exploration and development opportunities. Additionally, the Company has a team of dedicated employees that represent the professional disciplines and sciences that will allow Pioneer to maximize the long-term profitability and net asset values inherent in its physical assets.
Both the merger with Mesa and the acquisition of Chauvco were accounted for as purchases by the Company (formerly Parker & Parsley). As a result, the historical financial, reserve and other statistical information for the Company are those of Parker & Parsley prior to August 1997. The Company's financial, reserve and other statistical information present the addition of Mesa's and Chauvco's assets and liabilities as acquisitions in August and December 1997, respectively.
The Company provides administrative, financial and management support to United States and foreign subsidiaries that explore for, develop and produce oil, NGL and natural gas reserves. Drilling and production operations are principally located domestically in Texas, Kansas, Oklahoma, Louisiana, New Mexico and offshore Gulf of Mexico, and internationally in Argentina, Canada and South Africa.
The Company's executive offices are located at 1400 Williams Square West, 5205 N. O'Connor Blvd., Irving, Texas 75039; the Company's telephone number is (972) 444-9001. The Company maintains other offices in Midland, Texas; Buenos Aires, Argentina; Calgary, Canada; and Capetown, South Africa. At December 31, 1999, the Company had 817 employees, 298 of whom were employed in field and plant operations.
Mission and Strategies
The Company's mission is to provide shareholders with superior investment returns through strategies that maximize Pioneer's long-term profitability and net asset values. The strategies employed to achieve this mission are anchored by the Company's long-lived Spraberry oil field and Hugoton and West Panhandle gas fields' reserves and production. Underlying these fields are approximately 70 percent of the Company's proved oil and gas reserves which have a remaining production life in excess of 40 years. The stable base of oil and gas production from these fields generate operating cash flows that allow Pioneer the financial flexibility to selectively reinvest capital in these areas to: (a) develop and increase production from existing properties through low-risk development drilling activities, (b) leverage cost containment opportunities to achieve operating and technical efficiencies, and (c) pursue strategic acquisitions in the Company's core areas that will complement the Company's existing asset base and provide additional growth opportunities. The Company is also provided the financial flexibility to use portions of its operating cash flows to: (a) selectively expand into new geographic areas that feature producing properties and provide exploration/exploitation opportunities, (b) invest in the personnel and technology necessary to increase the Company's exploration opportunities, and (c) enhance liquidity; allowing the Company to take advantage of future exploration, development and acquisition opportunities. The Company is committed to continuing to enhance shareholder investment returns through adherence to these strategies.
Business Activities
The Company is an independent oil and gas exploration and development company. Its purpose is to competitively and profitably explore for, develop and produce proved oil, NGL and natural gas reserves. In so doing, the Company sells homogenous oil, NGL and natural gas units which, except for geographic and relatively minor qualitative differentials, cannot be significantly differentiated from units offered for sale by the Company's competitors. Competitive advantage is gained in the oil and gas exploration and development industry through superior capital investment decisions, technological innovation and managing costs.
Petroleum Industry. The petroleum industry has been characterized by volatile oil, NGL and natural gas commodity prices and relatively stable supplier costs during the three years ended December 31, 1999. During 1997 and 1998, weather patterns, regional economic recessions and political matters combined to cause worldwide crude oil supplies to exceed demand. As a result, crude oil prices declined substantially from the price levels of 1996. Also during 1997 and 1998, but to a lesser extent, market prices for natural gas declined. During the first quarter of 1999, the Organization of Petroleum
Exporting Companies and certain other crude oil exporting nations announced reductions in their planned export volumes. Those announcements, together with the enactment of the announced reductions in export volumes, have had a positive impact on world crude oil prices. No assurances can be given that the reductions in export volumes or the positive trend in oil and gas commodity prices can be sustained for an extended period of time. However, the improvements in the commodity price environment have enhanced the Company's financial flexibility, as compared to what existed at the end of 1998. The Company intends to monitor closely the business environment and to continue its efforts to reduce debt and create financial flexibility.
The Company. The Company intends to continue to reduce its outstanding indebtedness in order to provide sufficient financial flexibility for future exploration, development and acquisition opportunities. While the Company has recently incurred higher levels of debt to take advantage of strategic opportunities, management's objective is to maintain a flexible capital structure and to strengthen the Company's financial position through debt management.
As with any organization, the Company has experienced various debt levels in recent years as it has responded to strategic opportunities. During 1996 and 1995, the Company took deliberate actions to reduce its debt levels and to extend its debt maturities in order to improve its financial flexibility and enable it to take advantage of future strategic opportunities. The Company was able to reduce its debt levels during 1996 and 1995 through the application of proceeds from the disposition of assets that the Company had identified as non-core. In 1997, the Company's debt level increased as a result of the assumption of the debt of Mesa and Chauvco. In 1998, severe commodity price declines reduced cash flows from operating activities, causing the Company to utilize debt to finance capital investments. As a result of the increases in debt, and reductions in shareholders' equity primarily resulting from 1998 and 1997 non-cash asset impairment provisions (see Notes L and N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"), the Company's debt as a percentage of total capitalization increased to 73 percent and 56 percent at December 31, 1998 and 1997, respectively.
During 1998, the Company formulated and implemented measures to increase its financial flexibility and to safeguard its net asset values. Those measures included the enactment of an operating strategy focused on the enhancement of core assets and the divestiture of non-core assets, the enactment of cost containment measures and the reduction of outstanding indebtedness.
The Company's core assets are anchored by its United States investments in the long-lived Spraberry oil field and the Hugoton and West Panhandle gas fields (see "Mission and Strategies", above). As a result of the strategic superiority of the Company's core assets, Pioneer was able to reduce its capital expenditures to $179.7 million during 1999 in support of its debt reduction efforts. The Company's budgeted 2000 capital expenditures are $250 million (see "Drilling Activities" and "Exploratory Activities", below).
During 1999, the Company realized $420.5 million of net proceeds from the divestiture of non-core assets and completed the asset divestiture phase of the financial measures formulated in 1998. Net cash proceeds of $390.5 million associated with the 1999 asset divestitures were used to reduce outstanding indebtedness (see "Asset Divestitures" and Note K of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data").
During 1998, the Company implemented cost containment measures intended to reduce future production and administrative costs. Those measures included the centralization in Irving, Texas of certain operational and administrative functions previously based in Midland, Texas; the closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus Christi, Texas, and Houston, Texas; and, the elimination of approximately 350 employee positions. Associated with these measures, the Company recognized reorganization charges of $8.5 million and $33.2 million during 1999 and 1998, and realized reductions in per BOE production costs from $3.56 in 1998 to $3.12 in 1999 and reductions in per BOE administrative costs from $1.16 in 1998 to $.79 in 1999.
The strategic measures formulated and implemented as of December 31, 1998 have allowed the Company to reduce its outstanding indebtedness from $2.2 billion at December 31, 1998 to $1.7 billion at December 31, 1999 and realize reductions in total costs and expenses from $959.6 million during 1998 (before impairment of oil and gas properties and reorganization expense) to $706.8 million during 1999. The Company's debt as a percentage of total capitalization
declined to 69 percent at December 31, 1999. During 2000, the Company intends to improve its ratio of debt to total capitalization by limiting the Company's capital expenditure budget to $250 million and using the excess funds generated by operating activities to further reduce debt. The accomplishment of this objective in 2000 will be dependent on, among other things, commodity price levels and other factors that impact the Company's net cash provided by operating activities.
Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGL and gas through development drilling, production enhancement activities and acquisitions of producing properties. Average daily oil, NGL and gas production have each increased every year since 1991, with the exception of 1999 and 1996, when average daily production declined due to property dispositions. Comparing 1994 to 1999, average daily oil and NGL production has increased 103 percent and average daily gas production has increased 99 percent, while production costs per BOE have declined 38 percent. Production, price and cost information with respect to the Company's properties for each of 1999, 1998 and 1997 is set forth under "Item 2.
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and gas reserves at December 31, 1999, including PV 10 Value, are based on proved reserves as determined by the Company's engineers.
Numerous uncertainties exist in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company's control. This Report
contains estimates of the Company's proved oil and gas reserves and the related future net revenues, which are based on various assumptions, including those prescribed by the SEC. Actual future production, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates and could materially affect the estimated quantities and related PV 10 Value of proved reserves set forth in this Report. In addition, the Company's reserves may be subject to downward or upward revisions based on production performance, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, estimates of the PV 10 Value of proved reserves should not be construed as estimates of the current market value of the Company's proved reserves.
PV 10 Value is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. It requires the use of oil and gas prices prevailing as of the date of computation. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas because of seasonal price fluctuations or other varying market conditions. PV 10 Values as of any date are not necessarily indicative of future results of operations. Accordingly, estimates included herein of future net revenues may be materially different from the net revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas reserves during 1999 to any federal authority or agency, other than the SEC.
Proved Reserves
The Company's proved reserves totaled 605.5 million BOE at December 31, 1999, 676.8 million BOE at December 31, 1998 and 761.6 million BOE at December 31, 1997, representing $2.9 billion, $1.6 billion and $3.1 billion, respectively, of PV 10 Value. The divestiture of oil and gas properties, partially offset by upward revisions of reserve quantities as a result of increases in commodity prices, was the primary reason for the decrease in reserves during 1999. Downward revisions of reserve quantities as a result of the decline in commodity prices was the primary reason for the decrease in reserves and PV 10 Value during 1998.
On a BOE basis, 81 percent of the Company's total proved reserves at December 31, 1999 are proved developed reserves. Based on reserve information as of December 31, 1999, and using the Company's reserve report production information for 2000, the reserve-to-production ratio associated with the Company's proved reserves is 13.2 years on a BOE basis. The following table provides information regarding the Company's proved reserves by geographic area as of and for the year ended December 31, 1999.
(a) The 1999 average daily production is calculated using a 365-day year and without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the year.
Reserve Replacement
During 1999 and 1998, the Company's proved reserves declined 71.4 million BOE and 84.8 million BOE, respectively. Proved reserve reductions during 1999 were comprised of 111.4 million BOE's from asset divestitures and 51.1 million
BOE's of current year production.The Company added 91.1 million BOE of proved reserves during 1999 from revisions of previous estimates (74.4 million BOE), purchases of minerals-in-place (7.3 million BOE) and new discoveries and extensions (9.4 million BOE). During 1998, the Company's decline in proved reserves included 62.9 million BOE from production, 31.2 million BOE from revisions of previous estimates and 2.5 million BOE from asset divestitures. Discoveries and extensions of 11.8 million BOE partially offset these reductions. Reserve revisions result from several factors including changes in existing estimates of quantities available for production and changes in estimates of quantities which are economical to produce under current pricing conditions. The positive impact of revisions in 1999 primarily resulted from improved commodity prices as compared to December 31, 1998 prices. The downward revisions in 1998 relate primarily to the decline in commodity prices during 1998. The Company's reserves as of December 31, 1999 and 1998 were estimated using NYMEX oil prices of $25.60 and $12.00 per Bbl, respectively, and NYMEX gas prices of $2.33 and $2.00 per Mcf, respectively, resulting in realized prices of $24.33 and $10.09 per Bbl of oil, respectively; $17.59 and $6.81 per Bbl of NGLs, respectively; and $1.83 and $1.64 per Mcf of gas. As prices increase or decrease in future periods, reserves will be revised upward or downward for quantities which become economical or uneconomical to produce under the new price assumptions.
During 1999, the Company replaced 178 percent of its annual production (262 percent for oil and NGL's and 99 percent for gas), on a BOE basis. The Company's 1999 reserve replacement was primarily impacted by the increase in commodity prices. On a BOE basis, the Company's 1998 reserve replacement rate was negative due to severe declines in commodity prices. The Company's 1997 reserve replacement rate was 1,450 percent (1,375 percent for oil and NGL's and 1,528 percent for gas). For the three-year period ended December 31, 1999, the Company's average reserve replacement rate was 391 percent, as compared to average replacement rates of 465 percent and 769 percent for the three year periods ended December 31, 1998 and 1997, respectively. During 1997, the Company's reserve replacement rate was primarily reflective of its acquisition activities.
Finding Cost
The Company's acquisition and finding cost per BOE for 1999 and 1997 were $2.21 and $8.23 per BOE, respectively. During 1998, the Company's acquisition and finding costs were negative. The negative rate in 1998 was a result of downward reserve revisions related to the decline in commodity prices during 1998. The rate in 1997 was primarily impacted by the fair value associated with Mesa's and Chauvco's long-lived, low production cost reserves. The average acquisition and finding cost for the three-year period from 1997 to 1999 was $8.36 per BOE, representing a three percent decline from the 1998 three-year average rate of $8.65.
Description of Properties
As of December 31, 1999, the Company has operations in the United States, Argentina and Canada, and exploration opportunities in Africa.
Domestic. The Company's domestic operations are located in the Permian Basin, Mid-Continent and Gulf Coast regions of the United States. Approximately 70 percent of the Company's domestic proved reserves are located in the Spraberry, Hugoton and West Panhandle fields. These mature fields generate substantial operating cash flow and have a portfolio of low risk infill drilling opportunities. The cash flows generated from these fields provide funding for the Company's other development and exploration activities both domestically and internationally. During 1999, the Company expended $81.7 million in domestic exploration and development activities and has budgeted approximately $135 million of domestic expenditures for 2000.
Spraberry field. The Spraberry field was discovered in 1949 and encompasses eight counties in West Texas. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average Btu content of 1,400 Btu per Mcf. The oil and gas is produced from three formations, the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet. The center of the Spraberry field was unitized in the late 1950's and early 1960's by the major oil companies; however, until the late 1980's there was very limited development activity in the field. Since 1989, the Company has focused acquisition and development drilling activities in the unitized portion of the Spraberry field due to the dormant condition of the properties and the high net revenue interests available. The Company believes
the area offers excellent opportunities to enhance oil and gas reserves because of the hundreds of undeveloped infill drilling locations and the ability to reduce operating expenses through economies of scale. The Company initiated an aggressive optimization and automation cost cutting program in 1998 that continued into 1999, which has reduced operating expenses by 15 percent on a per BOE basis. Average lifting costs for 1999, 1998 and 1997 were $1.70, $1.95 and $2.01 per BOE, respectively. This cost reduction program will be continued in the future.
During 1999, the Company placed on production 137 wells, drilled one developmental dry hole and, at December 31, 1999, had 23 wells in progress. The Company plans to drill approximately 75 wells in 2000.
Hugoton field. The Hugoton field in Southwest Kansas is one of the largest producing gas fields in the continental United States. The gas is a relatively dry gas produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The Company's Hugoton properties represent approximately 13 percent of the proved reserves in the field and are located on approximately 257,000 gross acres (237,000 net acres), covering approximately 400 square miles. The Company has working interest in approximately 1,200 wells in the Hugoton field, almost 1,000 of which it operates, and partial royalty interests in approximately 500 of those wells. The Company owns substantially all of the gathering and processing facilities, primarily the Satanta plant, that service its production from the Hugoton field. Such ownership allows the Company to control the production, gathering, processing and sale of its gas and associated NGLs.
Production in the Hugoton field is subject to allowables set by state regulators, but the Company's Hugoton operated properties are capable of producing approximately 150 MMcf of wet gas per day (i.e., gas production at the wellhead before processing and before reduction for royalties). The Company estimates that it and other major producers in the Hugoton field produced at or near capacity in 1999. During 1999, the Company completed eight development wells in the Hugoton field and, at December 31, 1999, had two development wells in progress. The Company plans to drill approximately 35 development wells in 2000.
The Company is considering plans to submit an application to the Kansas Corporation Commission to allow infill drilling into the Council Grove Formation. The Company believes that such infill drilling could increase production from its Hugoton properties. There can be no assurance that the application will be approved or as to the timing of receipt of such approval if such approval is obtained.
West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas where initial production commenced in 1918. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company's natural gas in the West Panhandle field has an average Btu content of 1,300 Btu per Mcf and is produced from approximately 600 wells on more than 241,000 gross (185,000 net) acres covering over 375 square miles. The Company's wellhead gas produced from the West Panhandle field contains a high quantity of NGLs, yielding relatively greater NGL volumes than realized from many other natural gas fields. The Company operates the wells and production equipment and Colorado Interstate Gas Company (a subsidiary of Coastal Corporation) owns and operates the gathering system.
The production from the West Panhandle field is processed through the Company-owned Fain natural gas processing plant. In February 1997, the Company initiated a project to add nitrogen rejection capabilities at the Fain plant. This project, which was completed in mid-1998, allows the Company to recover a greater percentage of the helium in the processed gas; increase NGL recoveries; and upgrade residue quality improving marketing flexibility.
During 1999, the Company placed 35 new wells on production and has another 17 wells in progress at December 31, 1999. The Company plans to drill approximately 45 wells in 2000.
Other domestic properties. In the Gulf Coast area, the Company is focused on reserve and production growth through a balanced portfolio of development and exploration activities. To accomplish this, the Company has devoted most of its domestic exploration efforts to this area, as well as its investment in and utilization of 3-D seismic technology. During 1999, the Company expended $39.2 million to drill nine development and ten exploratory wells in the Gulf Coast area. The most significant of these wells was the Company's first deep-water Gulf of Mexico venture at Mississippi Canyon Block 305, the Aconcagua prospect, which was drilled to a depth of 14,000 feet. Associated therewith, the Company
announced a significant discovery during the first quarter of 1999, encountering a hydrocarbon- bearing section of over 200 gross feet. The Company has a 25 percent working interest in the block. An appraisal well on the Aconcagua prospect was spud during February 2000. The Company spudded its second deep-water well during the second quarter of 1999 at Garden Banks 515, which was unsuccessful. During the fourth quarter of 1999, the Company spud its third deep-water exploratory well on the Devil's Tower prospect in Mississippi Canyon block 773. The Company announced a discovery on the Devil's Tower prospect during February 2000. The well was drilled to a total depth of 15,625 feet and encountered a significant number of hydrocarbon-bearing sands. The Company has a 15.8 percent working interest in the discovery. An appraisal well is scheduled to be spud on the Devil's Tower prospect during the second quarter of 2000. In addition to the appraisal wells on the Aconcagua and Devil's Tower prospects, the Company plans to drill four to six Gulf Coast area exploratory wells during 2000.
International. The Company's international operations are located in the Tierra del Fuego and Neuquen Basin areas of Argentina; and the Chinchaga, Martin Creek and Rycroft/Spirit River areas of Canada. Additionally, the Company has entered into agreements to explore for oil and gas reserves in the African nations of South Africa and Gabon. Approximately 16 percent and five percent of the Company's proved reserves are located in Argentina and Canada, respectively.
Argentina. The Company's Argentine properties are primarily located in the Austral and Neuquen basins. The Company's share of Argentine production during 1999 averaged 22.8 MBOE's per day, or approximately 16 percent of the Company's equivalent production. The production concession in the Austral basin is located in Tierra del Fuego, which is the extreme southern portion of Argentina, approximately 1,500 miles south of Buenos Aires. Crude oil, natural gas and NGLs are produced from six separate fields in which the Company has a 35 percent working interest. Production increases are anticipated from the area through exploitation and exploration and improving the oil and gas processing facilities and infrastructure on the island. Currently, production is being sent to the mainland through oil tankers and gas pipelines and exported to Chile through pipelines.
The Company's operated production in Argentina is concentrated in the Neuquen Basin which is located about 925 miles southwest of Buenos Aires and just to the east of the Andes Mountains. Crude oil and natural gas are produced from the Loma Negra/NI Block, the Dadin Block, the Al Norte de la Dorsal Block and the Neuquen del Medio Block in which the Company has 100 percent working interests. During the fourth quarter of 1999, the Company acquired 100 percent working interests in certain producing properties located in the core areas of Al Sur de la Dorsal and Estacion Fernandez Oro. Both properties have significant exploitation and exploration potential and infrastructure synergies with the Company's current operations.
During 1999, the Company expended $75.1 million on Argentine exploration and development activities and drilled 22 development wells and 33 exploratory wells in Argentina. The Company plans to spend approximately $55 million on oil and gas development and exploration opportunities in Argentina during 2000.
Canada. The Company's Canadian producing properties are located primarily in Alberta and British Columbia, Canada. Production during 1999 averaged 13.5 MBOE's per day, or approximately 10 percent of the Company's equivalent production. In the third quarter of 1999, the Company completed the process of divesting 68 non-core Canadian oil and gas properties to focus efforts on its core assets in northeast British Columbia and northwest Alberta. The core Canadian assets are geographically concentrated, predominantly shallow gas and more than 90 percent operated by the Company in the following areas: Chinchaga, Martin Creek and Rycroft/Spirit River. Following the property divestitures, fourth quarter production averaged 7.6 MBOE's per day from the core properties.
Production from the Chinchaga areas is relatively dry gas from formation depths averaging 3,400 feet. In the Martin Creek area, production is relatively dry gas from various reservoirs ranging from 3,700 feet to 4,300 feet. The Rycroft/Spirit River area produces primarily oil and consists of four unitized waterfloods producing from reservoir depths ranging from 4,400 feet to 5,000 feet. In 1999, recompletion activity in this area resulted in increased gas production from shallow reservoirs ranging from 4,000 feet to 4,300 feet.
During 1999, the Company expended $18.9 million on Canadian exploration and development activities and drilled 34 development wells and one successful exploratory well primarily in the Chinchaga and Martin Creek areas. The Company
plans to drill approximately 26 development wells and one exploratory well during 2000. The Company expects to participate in an additional nine wells operated by other companies in the same areas. The Company plans to spend $35 million on oil and gas development and exploration opportunities in Canada during 2000.
Africa. The Company has entered into agreements to explore in the African nations of South Africa and Gabon. The South African agreements covers over 13 million acres along the southern coast of South Africa, generally in water depths less than 650 feet. During 1998, five wells were drilled by the Company in South Africa, of which two discovered reserves. During 1999, the Company performed and analyzed seismic studies necessary for the analysis, ranking and timing of prospects in South Africa and Gabon. In doing so, the Company incurred $3.7 million of seismic costs in South Africa and Gabon during 1999. During 2000, the Company plans to spend approximately $25 million on exploration opportunities in South Africa and Gabon. The Company expects to spud an appraisal well in the Sable field of South Africa during March 2000.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the Company as of and for each of the years ended December 31, 1999, 1998 and 1997. Because of normal production declines, increased or decreased drilling activities and the effects of past and future acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.
Production, Price and Cost Data. The following table sets forth production, price and cost data with respect to the Company's properties for the years ended December 31, 1999, 1998 and 1997.
(a) These amounts represent the Company's historical results from operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years.
Productive Wells. The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 1999, 1998 and 1997.
(a) Productive wells consist of producing wells and wells capable of production, including shut-in wells. One or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well. As of December 31, 1999, the Company owned interests in 24 wells containing multiple completions.
Leasehold Acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 1999.
LEASEHOLD ACREAGE
Drilling Activities. The following table sets forth the number of gross and net productive and dry wells in which the Company had an interest that were drilled and completed during the years ended December 31, 1999, 1998, and 1997. This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry wells.
DRILLING ACTIVITIES
Gross Wells Net Wells ------------------------ ------------------------ Year Ended December 31, Year Ended December 31, ------------------------ ------------------------ 1999 1998 1997 1999 1998 1997 ------ ------ ------ ------ ------ ------ United States: Productive wells: Development............ 199 385 483 131.3 285.9 341.2 Exploratory............ 7 18 38 4.6 13.4 23.8 Dry holes: Development............ 1 13 18 .8 8.8 8.8 Exploratory............ 7 5 46 2.7 3.0 30.3 ------ ----- ----- ------ ------ ------ 214 421 585 139.4 311.1 404.1 ------ ----- ----- ------ ------ ------ Argentina: Productive wells: Development............ 19 41 4 16.6 39.1 .6 Exploratory............ 25 11 1 24.1 10.6 .1 Dry holes: Development............ 3 5 - 3.0 5.0 - Exploratory............ 8 11 1 6.5 9.7 .1 ------ ----- ----- ------ ------ ------ 55 68 6 50.2 64.4 .8 ------ ----- ----- ------ ------ ------ Canada: Productive wells: Development............ 34 54 - 18.8 37.1 - Exploratory............ - 10 - - 7.2 - Dry holes: Development............ - 6 - - 5.4 - Exploratory............ 1 4 - .3 3.0 - ------ ----- ----- ------ ------ ------ 35 74 - 19.1 52.7 - ------ ----- ----- ------ ------ ------ Other foreign: Productive wells: Development............ - - - - - - Exploratory............ - 2 - - .7 - Dry holes: Development............ - - - - - - Exploratory............ - 3 1 - 1.7 .4 ------ ----- ----- ------ ------ ------ - 5 1 - 2.4 .4 ------ ----- ----- ------ ------ ------ Total................ 304 568 592 208.7 430.6 405.3 ====== ===== ===== ====== ====== ======
Success ratio(a)......... 93% 92% 89% 94% 92% 90% - ---------------
(a) Represents those wells that were successfully completed as productive wells.
The following table sets forth information about the Company's wells that were in progress at December 31, 1999.
Gross Wells Net Wells ----------- --------- United States: Development.................... 45 26.9 Exploratory.................... 1 .1 ------ ------ 46 27.0 ------ ------ Argentina: Development.................... 2 2.0 Exploratory.................... 4 3.6 ------ ------ 6 5.6 ------ ------ Canada: Development.................... 3 2.6 Exploratory.................... - - ------ ------ 3 2.6 ------ ------ Total....................... 55 35.2 ====== ======
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described under "Legal actions" in Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data". The Company is also party to other litigation incidental to its business. The claims for damages from such other legal actions are not in excess of 10 percent of the Company's current assets and the Company believes none of these actions to be material.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matters to a vote of security holders during the fourth quarter of 1999.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed and traded on the New York Stock Exchange and the Toronto Stock Exchange under the symbol "PXD". The following table sets forth, for the periods indicated, the high and low sales prices for the Company's common stock, as reported in the New York Stock Exchange composite transactions, and the amount of dividends paid.
Dividends High Low Paid per share --------- --------- --------------
Fourth quarter.................... $11 1/2 $ 7 5/8 - Third quarter..................... $12 13/16 $ 9 3/8 - Second quarter.................... $13 3/16 $ 7 1/16 - First quarter..................... $ 9 3/4 $ 5 -
Fourth quarter.................... $16 $ 7 3/4 - Third quarter..................... $24 11/16 $13 1/4 $.05 Second quarter.................... $25 15/16 $21 3/8 - First quarter..................... $30 $20 5/8 $.05
On February 28, 2000, the last reported sales price of the Company's common stock, as reported in the New York Stock Exchange composite transactions, was $7-11/16 per share.
As of February 28, 2000, the Company's common stock was held by approximately 33,100 holders of record.
The Company's Board of Directors elected to discontinue cash dividends in 1999 and future years.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data for the Company should be read in conjunction with "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
1999 Performance
The Company's performance during 1999 was highlighted by significant improvements in oil, NGL and natural gas commodity prices; by its successful execution of operating measures focused on the enhancement of core assets and the divestiture of non-core assets, the continuation of cost containment measures implemented during 1998 and the reduction of outstanding indebtedness, and, by favorable test results from the Company's deep-water Gulf of Mexico exploration drilling program.
During 1999, the Company reduced its capital expended on oil and gas property additions to $179.7 million, as compared to 1998 and 1997 oil and gas property expenditures of $507.3 million and $428.6 million, respectively (see "Capital Commitments, Capital Resources and Liquidity", below). The Company also realized $420.5 million of proceeds from the divestiture of non-core United States and Canadian oil and gas properties, gas plants and other assets during 1999 (see "Asset Divestitures", below and Note K of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"). The net cash proceeds from the asset divestitures were used, together with net cash provided from operating activities, to reduce outstanding indebtedness by $429.3 million during 1999 (see "Liquidity", below and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data").
The Company reported a net loss of $22.5 million ($.22 per share) for the year ended December 31, 1999, as compared to net losses of $746.4 million ($7.46 per share) and $890.7 million ($17.14 per share) for the years ended December 31, 1998 and 1997, respectively. In comparison to 1998, the Company's 1999 results were positively impacted by improved commodity prices, a $79.2 million increase in interest and other income, the results of cost containment measures, reductions in outstanding indebtedness and significant reductions in provisions for the impairment of oil and gas properties; and, were negatively impacted by declines in production volumes due to asset divestitures, net losses recognized on asset divestitures and non-cash mark-to-market charges recognized on non-hedge derivative contracts.
Commodity prices and production volumes. During 1999, crude oil, NGL and natural gas prices increased substantially from their depressed 1998 levels. The average prices realized by the Company during 1999, including the effects of oil and gas price hedges, were $15.36 per Bbl of oil, $11.64 per Bbl of NGL's and $1.90 per Mcf of natural gas; as compared to average realized prices for oil, NGL's and natural gas of $13.08 per Bbl, $8.90 per Bbl and $1.82 per Mcf, respectively, during 1998; and, $18.51 per Bbl, $12.59 per Bbl and $2.20 per Mcf, respectively, during 1997. The effects of price volatility on the Company's results of operations and net cash generated by operating activities during 1999 and 1998 were mitigated by the results of oil and gas price hedges and changes in production volumes. Primarily as a result of asset divestitures, the Company's 1999 total production of oil, NGL and natural gas declined to 51,101 MBOE, as compared to total production of 62,875 MBOE and 35,363 MBOE, during 1998 and 1997, respectively.
Asset divestitures. During 1999, 1998 and 1997, the Company's asset divestitures generated net proceeds to the Company of $420.5 million, $21.9 million and $115.7 million, respectively, which resulted in 1999 and 1998 net losses of $24.2 million and $445 thousand, respectively, and a 1997 net gain of $5.0 million. The Company's 1999 asset divestitures were comprised of non-core United States and Canadian oil and gas properties, gas plants and other assets. The net cash proceeds from the 1999 asset divestitures were used to reduce the Company's outstanding indebtedness, while the net cash proceeds from the 1998 and 1997 asset divestitures were used to provide funding for a portion of the Company's capital expenditures. See Note K of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Results of Operations", below, for additional information regarding the Company's asset divestitures.
Cost containment. During 1999 and 1998, the Company executed a number of cost containment measures. Such measures included the centralization of certain operating and administrative functions in Irving, Texas that were previously based in Midland, Texas, the closings of its regional offices in Oklahoma City, Oklahoma, Corpus Christi, Texas and Houston, Texas; the termination of 350
employees, including several officer positions; and reductions in salaries among senior officers. Those initiatives increased operational and administrative efficiencies by reducing production costs and general and administrative costs per BOE during 1999 to $3.12 and $.79, respectively, from $3.56 and $1.16, respectively, during 1998. The Company intends to sustain these initiatives during 2000 and the foreseeable future. See Note M of Notes to Consolidated Financial Statement included in "Item 8. Financial Statements and Supplementary Data" for specific discussions and disclosures regarding the Company's reorganization provisions.
Net cash provided by operating activities. Net cash provided by operating activities was $255.2 million for the year ended December 31, 1999, as compared to $314.1 million for the year ended December 31, 1998 and $228.2 million for the year ended December 31, 1997. The decrease in net cash provided by operating activities during 1999 as compared to 1998 is primarily attributable to declines in production volumes, increases in operating receivables and repayments of operating payables, partially offset by increases in oil, NGL and natural gas commodity prices and reductions in operating costs. During 1998, additional cash flow was generated due to the increased production realized from the acquired Mesa and Chauvco properties, offset partially by declining commodity prices and increased costs and expenses.
Total debt and book capitalization. Total debt was reduced to $1.7 billion as of December 31, 1999, as compared to total debt of $2.2 billion and $1.9 billion, respectively, at December 31, 1998 and 1997. The Company strives to maintain its outstanding indebtedness at a moderate level in order to provide sufficient financial flexibility to react to future opportunities. The Company's total book capitalization at December 31, 1999 was $2.5 billion, consisting of total debt of $1.7 billion and stockholders' equity of $.8 billion. Consequently, the Company's debt to total capitalization decreased to 69 percent at December 31, 1999 from 73 percent at December 31, 1998.
Exploration and drilling results. During 1999, the Company completed drilling 304 gross wells (209 net wells), of which 284 gross wells (195 net wells) were successfully placed on production, representing a 93 percent success rate. See "Item 2. Properties" for information regarding the Company's reserve replacement, finding costs, property descriptions and drilling activities.
The Company's 1999 exploratory drilling was focused in the United States Gulf of Mexico, Argentina and Canada. The Company completed drilling 48 gross exploratory wells (38 net wells) during 1999, of which 32 gross exploratory wells (29 net wells) successfully discovered proved oil, NGL and gas reserves, representing a 67 percent success rate. The Company's most significant discovery during 1999 was its first deep-water Gulf of Mexico venture at Mississippi Canyon Block 305, the Aconcagua prospect, that was drilled to a total depth of 14,000 feet and encountered a hydrocarbon-bearing section of over 200 gross feet. The Company has a 25 percent working interest in the block. An appraisal well on the Aconcagua prospect was spud during February 2000. The Company spudded its second deep-water Gulf of Mexico well during the second quarter of 1999, which was unsuccessful. During the fourth quarter of 1999, the Company spud its third deep-water exploratory well on the Devil's Tower prospect in Mississippi Canyon block 773. The Company announced a discovery on the Devil's Tower prospect during February 2000. The well was drilled to a total depth of 15,625 feet and encountered a significant number of hydrocarbon-bearing sands. The Company has a 15.8 percent working interest in the discovery. An appraisal well is scheduled to be spud on the Devil's Tower prospect during the second quarter of 2000. In addition to the appraisal wells on the Aconcagua and Devil's Tower prospects, the Company plans to drill four to six Gulf Coast area exploratory wells during 2000.
The Company also plans to drill exploratory wells in Argentina, Canada and South Africa during 2000. During 1999, the Company drilled 33 gross exploratory wells (31 net wells) in Argentina, with a 76 percent success rate. In South Africa, the Company has scheduled three exploratory wells to be spud during 2000, of which one is an appraisal well on the Company's Sable oil discovery.
See "Results of Operations", below, for more in-depth discussions of the Company's oil and gas producing activities, including discussions pertaining to oil and gas production volumes, prices, hedging activities, costs and expenses, capital commitments, capital resources and liquidity.
2000 Outlook
Commodity prices. The Company's results of operations and financial condition in 2000 are expected to be significantly affected by the rising trend in commodity prices that has occurred as a result of decreases in oil and gas supplies relative to demand for those commodities. The most significant of those factors has been the decrease in crude oil exports during 1999 by members of the Organization of Petroleum Exporting Countries ("OPEC") and other crude oil exporting nations. During 2000, the favorable commodity price environment presently impacting the oil and gas industry may continue; however the Company is continuing its debt reduction and cost containment measures to protect its net asset values from a return to a less favorable commodity price environment. If OPEC and the other crude oil exporting nations were to increase crude oil supplies relative to demand, crude oil prices could again begin to decline, which could have a significant negative impact on the Company's results of operations and net cash provided or used by operating activities, and could result in additional impairment of the carrying values of the Company's oil and gas properties and deferred tax assets.
Capital expenditures. During 2000, the Company plans to limit capital expended for oil and gas property additions to approximately $250 million, of which approximately $50 million has been budgeted for exploration expenditures and $200 million has been budgeted for exploitation projects. Pioneer's long-lived reserves and dependable production in the Hugoton and West Panhandle gas fields and Spraberry oil field allow the Company the flexibility necessary to make significant changes in its capital allocation plans without significantly impacting near term production volumes. The Company's 2000 exploitation budget is allocated approximately 55 percent to the United States, 25 percent to Argentina and 20 percent to Canada. Exploration drilling will be concentrated in the Gulf of Mexico, the onshore Gulf Coast area, Argentina and South Africa. The Company has budgeted exploratory expenditures of approximately $25 million each for the United States Gulf Coast area and international areas during 2000. During 2000, the Company will continue to use the excess of cash provided by operating activities over capital expenditures for oil and gas producing activities to reduce outstanding indebtedness.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $644.6 million in 1999, $711.5 million in 1998 and $536.8 million in 1997, representing a nine percent decrease from 1998 to 1999 and a 33 percent increase from 1997 to 1998. The revenue decrease from 1998 to 1999 is reflective of a 19 percent decrease in BOE production, partially offset by price increases of 17 percent, 31 percent and four percent, respectively, for oil, NGL and natural gas. The revenue increase from 1997 to 1998 is reflective of a 78 percent increase in BOE production, offset by a 29 percent, 29 percent and 17 percent decline in prices for oil, NGLs and gas, respectively, from 1997 to 1998.
Year Ended December 31, ------------------------------ 1999 1998 1997 -------- -------- --------
Total production: Oil (MBbls)................................ 15,454 21,554 13,618 NGLs (MBbls)............................... 9,237 10,669 4,267 Gas (MMcf)................................. 158,457 183,913 104,868 Total (MBOE)............................... 51,101 62,875 35,363 Average daily production: Oil (Bbls)................................. 42,339 59,052 37,309 NGLs (Bbls)................................ 25,308 29,231 11,691 Gas (Mcf).................................. 434,130 503,872 287,309 Average prices: Oil (per Bbl).............................. $ 15.36 $ 13.08 $ 18.51 NGL (per Bbl).............................. $ 11.64 $ 8.90 $ 12.59 Gas (per Mcf).............................. $ 1.90 $ 1.82 $ 2.20 Percentage annual price increase (decrease): Oil........................................ 17 (29) (7) NGL........................................ 31 (29) N/A Gas........................................ 4 (17) (3)
On a BOE basis, production declined by 19 percent for the year ended December 31, 1999, as compared to the same period in 1998. The decline in production was primarily attributable to asset divestitures, but also reflects
the deferral of oil well completions at the end of 1998 and beginning of 1999 until oil prices recovered, and normal well production declines. Excluding the production associated with 1999 and 1998 asset divestitures, production declined by nine percent during the year ended December 31, 1999, as compared to the same period in 1998.
Production volumes for 1998 increased by 78 percent from 35,363 MBOE to 62,875 MBOE. This increase was primarily reflective of a full year of production realized from the properties acquired from Mesa and Chauvco, but also was impacted favorably by the Company's exploration and exploitation projects. The properties acquired from Mesa and Chauvco contributed 97 percent of the production growth from 1997 to 1998. Excluding the production associated with the Mesa and Chauvco properties and other properties sold during 1998 and 1997, production increased nine percent during 1998, as compared to 1997, on a BOE basis.
Hedging activities
The oil and gas prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company's hedging activities. The Company utilizes commodity derivative contracts (swaps, futures and options) in order to (i) reduce the effect of the volatility of price changes on the commodities the Company produces and sells, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) lock in prices to protect the economics related to certain capital projects.
Crude oil. All material purchase contracts governing the Company's oil production are tied directly or indirectly to NYMEX prices. The average oil price per Bbl that the Company reports includes the effects of oil quality, gathering and transportation costs and the net effect of the oil hedges. The Company's average realized prices for physical oil sales (excluding hedge results) for the years ended December 31, 1999, 1998 and 1997 were $16.23 per Bbl, $11.93 per Bbl and $19.09 per Bbl, respectively. During the year ended December 31, 1999, the Company recorded a $13.4 million net decrease to oil revenues as a result of its oil price hedges. The Company recorded a net increase to oil revenues of $24.8 million and a net decrease to oil revenues of $7.9 million for the years ended December 31, 1998 and 1997, respectively, as a result of its oil price hedges.
Natural gas liquids. During 1999 and 1998, the Company did not enter into natural gas liquids price hedge contracts. During 1997, the Company employed a policy of hedging natural gas liquids based on actual product prices in order to mitigate some of the volatility associated with NYMEX pricing. The Company's average realized prices for physical natural gas liquids sales (excluding hedge results) for the years ended December 31, 1999, 1998 and 1997 were $11.64 per Bbl, $8.90 per Bbl and $12.61 per Bbl, respectively. During 1997, the Company recorded a net decrease to natural gas liquids revenue of $77,600 as a result of natural gas liquids hedges.
Natural gas. The Company employs a policy of hedging gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices. The average gas price per Mcf that the Company reports includes the effects of Btu content, gathering and transportation costs, gas processing and shrinkage and the net effect of the gas hedges. The Company's average realized prices for physical gas sales (excluding hedge results) for the years ended December 31, 1999, 1998 and 1997 were $1.84 per Mcf, $1.80 per Mcf and $2.41 per Mcf, respectively. For the year ended December 31, 1999, the Company recorded a net increase to gas revenues of $9.4 million as a result of its gas price hedges. The Company recorded a net increase to gas revenues of $3.6 million and a net decrease of $21.9 million for the years ended December 31, 1998 and 1997, respectively, as a result of its gas price hedges.
See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information concerning the Company's open hedge positions at December 31, 1999 and the related prices to be realized.
Interest and other revenue. The Company recorded interest and other income totaling $89.7 million, $10.5 million and $4.3 during 1999, 1998 and 1997, respectively. The significant increase in interest and other income during 1999 is primarily attributable to non-recurring option fees and excise tax refunds recognized by the Company during 1999. In December 1998, the Company announced the sale of an exclusive and irrevocable option to a third party to purchase certain oil and gas properties and other assets of the Company. In consideration for the option, the third party paid an option fee of $41.3 million to the Company, consisting of $29.3 million of cash and the third party's common stock that was then valued at $12.0 million. The third party's
option lapsed by its terms during the first quarter of 1999. During the second quarter of 1999, the Company entered into a purchase and sale agreement with the third party that was not completed as specified by the terms of the agreement and, as a result thereof, the Company received liquidated damages of additional shares of the third party's common stock valued at $.5 million. During 1999, the Company recognized other revenue of $41.8 million as a result of the transactions with the third party. The Company also received a $30.2 million refund of excise taxes during 1999. Due to the uncertainty surrounding the collectability of this refund, the Company was not carrying it as an asset. Accordingly, the Company recognized the tax refund as other revenue during 1999.
Gain (loss) on disposition of assets. During 1998, the Company announced measures to increase its financial flexibility and to safeguard net asset values. Those measures included the enactment of an operating strategy focused on the enhancement of core assets and the divestiture of non-core assets, continuation of cost containment measures and the reduction of outstanding indebtedness. During 1999, the Company completed the asset divestiture phase of the measures referred to above. As a result, the Company realized net divestment proceeds from asset divestitures of $420.5 million during 1999 and recorded an associated net loss on disposition of assets of $24.2 million. The net cash proceeds from the 1999 asset divestitures were used to reduce outstanding indebtedness (see Note K of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data").
Production costs. Total production costs per BOE decreased in 1999 and 1998 by approximately 12 percent and 13 percent, respectively. The primary component of production costs, lease operating expense, declined by 13 percent in 1999 and remained constant in 1998. Workover costs declined by 20 percent and 52 percent, respectively, in 1999 and 1998. These costs represent the majority of the oil and gas property operating expenses over which the Company has control and the costs on which the Company has focused its reduction efforts. Production taxes, which are correlated with volumes and prices, declined three percent in 1999 and 51 percent in 1998, reflecting the declines in volumes during 1999 and commodity prices during 1998. The operating margins from the Company's gas plants (i.e., third party processing revenues less processing costs and expenses) are included in oil and gas production costs, specifically lease operating expense, which resulted in decreases in lease operating expense per BOE during 1999 and 1997 of $.11 and $.07, respectively, and an increase in lease operating expense per BOE of $.05 during 1998. The reductions in lease operating expense during the years ended December 31, 1999 and 1998 are primarily due to the cost containment measures initiated by the Company during 1998, and to the divestment of high operating cost properties during 1999 (see "1999 Performance", above, and Note K of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data").
Year Ended December 31, --------------------------- 1999 1998 1997 ------- ------- ------- (per BOE)
Lease operating expense................... $ 2.63 $ 3.04 $ 3.02 Production taxes.......................... .39 .40 .81 Workover costs............................ .10 .12 .25 ------ ------ ------ Total production costs.................. $ 3.12 $ 3.56 $ 4.08 ====== ====== ======
Depletion expense. Depletion expense per BOE decreased 17 percent during 1999 (to $4.27 in 1999 from $5.13 in 1998) and 11 percent in 1998 (from $5.78 in 1997). The decrease in 1999 depletion expense per BOE is primarily attributable to the impact on proved reserves of improving commodity price outlooks and to the impairment of the per BOE carrying values of the Company's proved oil and gas properties during the years ended December 31, 1998 and 1997. The decrease in 1998 depletion expense per BOE was primarily due to the 1997 impairment of the per BOE carrying values of the Company's proved oil and gas properties (see "Impairment of Oil and Gas Properties" below).
Impairment of oil and gas properties. The Company reviews its oil and gas producing properties for impairment whenever events or circumstances indicate a decline in the recoverability of the carrying value of the Company's assets may have occurred. Declining commodity prices in 1998 and 1997, the Company's outlook for future commodity prices and 1998 performance issues relative to certain oil and gas properties, prompted impairment reviews. As a result of these reviews, the Company recognized non-cash charges of $312.2 million and $1.4 billion in 1998 and 1997, respectively, related to its proved oil and gas properties.
The Company periodically assesses its unproved properties to determine whether they have been impaired. An unproved property may be impaired if the Company does not intend to drill the prospect as a result of downward revisions to potential reserves, if the results of exploration or the Company's outlook for future commodity prices indicate that the potential reserves are not sufficient to generate net cash flows to recover the investment required by the project, or if the Company intends to sell the property for less than its carrying value. The Company has assessed its unproved oil and gas properties for impairment and, during the years ended December 31, 1999 and 1998, recognized non-cash impairment charges of $17.9 million and $147.3 million, respectively, to reduce the carrying value of its unproved oil and gas properties.
Neither the longevity nor the extent of the current trend of increasing commodity prices can be assessed with any degree of certainty. A resumption of the 1998 trend towards declining commodity prices, or other relevant factors, could result in further impairment provisions to the carrying value of the Company's proved and unproved properties, which could have a material adverse effect on the Company's financial condition and results of operations. See Notes B and L of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information and disclosures regarding the Company's accounting policies and attributes pertaining to asset impairments.
Exploration and abandonments/geological and geophysical costs. Exploration and abandonments/geological and geophysical costs totaled $66.0 million, $121.9 million and $77.2 million for the years ended December 31, 1999, 1998 and 1997, respectively. The following table sets forth the components of the Company's 1999, 1998 and 1997 exploration and abandonments/geological and geophysical costs: Year Ended December 31, ------------------------------- 1999 1998 1997 -------- --------- -------- (in thousands) Exploratory dry holes: United States............................. $ 15,591 $ 15,737 $ 27,183 Argentina................................. 3,441 4,426 252 Canada.................................... 978 1,949 - Other foreign............................. (275) 9,486 5,442 Geological and geophysical costs: United States............................. 17,207 42,755 37,987 Argentina................................. 3,399 9,999 1,570 Canada.................................... 315 14,244 - Other foreign............................. 7,498 3,851 - Leasehold abandonments and other........... 17,820 19,411 4,726 ------- -------- ------- $ 65,974 $ 121,858 $ 77,160 ======= ======== =======
Approximately 31 percent of the Company's 1999 exploration/exploitation capital was spent on exploratory projects as compared to 30 percent in 1998 and 28 percent in 1997. The decrease in 1999 exploratory costs is primarily attributable to the Company's curtailed 1999 capital program, as evidenced by reductions in all categories of exploration, abandonments, geological and geophysical costs as compared to 1998. The increase in 1998 exploratory costs was primarily due to the initial expenditures made to explore the Argentine and Canadian properties acquired from Chauvco and the Company's exploration program in South Africa. The Company currently anticipates that its 2000 exploration efforts will be concentrated in the Gulf of Mexico, onshore Gulf Coast area, Argentina and South Africa.
Interest and administrative expenses. Interest and general and administrative expenses were $170.3 million and $40.2 million, respectively, during 1999, as compared to $164.3 million and $73.0 million, respectively, during 1998, and $77.5 million and $48.8 million, respectively, during 1997. On a per BOE basis, interest and general and administrative expenses were $3.33 and $.79, respectively, during 1999, as compared to $2.61 and $1.16, respectively, during 1998, and $2.19 and $1.38, respectively, during 1997. The increase in interest expense during 1999 is due to the higher debt levels carried over from 1998. Interest expense is expected to decline in 2000 from the expense levels incurred during 1999 and 1998. The decline in administrative expense during 1999, and the anticipated decline in interest expense during 2000, are a direct result of the financial measures enacted to contain costs and reduce outstanding indebtedness. The increases in total interest and administrative expenses during 1998 were due to the Company having incurred a full year of interest on the debt
incurred as a result of the Mesa and Chauvco acquisitions and to fund the capital expenditures of 1998, and to administer the larger Company infrastructure immediately after the Mesa and Chauvco acquisitions and before the effects of the reorganization measures enacted in 1998 could be realized. On a per BOE basis, interest expense increased in 1999, after having declined in 1998, primarily due to production variances associated with the 1999 asset divestitures and to the postponement of oil well completions at the end of 1998 due to low oil commodity prices. The decline in per BOE administrative expense is due to the reorganization measures initiated by the Company during 1998. Those reorganization measures included the centralization in Irving, Texas of certain operational and administrative functions previously based in Midland, Texas; the closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus Christi, Texas, and Houston, Texas; the elimination of approximately 350 employee positions; and, other initiatives. As a direct result of those measures, the Company recognized reorganization charges of $8.5 million and $33.2 million, respectively, during 1999 and 1998 (see Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding reorganization costs paid during 1999 and 1998, and unpaid reorganization costs as of December 31, 1999 and 1998).
Other expenses. Other expenses were $34.7 million during 1999, as compared to $39.6 million during 1998 and $7.1 million during 1997. Other expenses recognized during 1999 were primarily attributable to fluctuations in mark-to- market provisions on derivative financial instruments. Mark-to-market provisions in 1999 included $21.2 million associated with non-hedge commodity derivatives and $11.9 million associated with four million shares of common stock of a closely held, non-affiliated, public entity, the investment in which the Company divested during the second quarter of 1999; partially offset by $5.9 million of mark-to-market income recognized on a series of forward foreign exchange swap agreements and income of $.2 million associated with the Company's Btu swap agreements. Other expense for 1998 included, and increased primarily as a result of, $20.5 million of mark-to-market adjustments of non- hedge foreign currency and Btu swap agreements; a $9.6 million write-off of deferred compensation arising from change of control features in the Company's incentive plans; $4.4 million of other expenses associated with the Company's operations in Argentina and Canada; and, $2.3 million of bad debt expense. Other expense for 1997 included a $5.2 million mark-to-market charge associated with the Btu swap agreements. See "Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about financial instruments to which the Company is a party as of December 31, 1999 and 1998, and from which the Company may incur future gains or losses from changes in market interest rates, foreign exchange rates, commodity prices or common and preferred stock prices. Although certain derivative contracts that the Company is a party to do not qualify as hedges, the Company does not enter into derivative or other financial instruments for trading purposes.
Quantitative Disclosures
Interest rate sensitivity. The following tables provide information, in United States dollar equivalent amounts, about the Company's derivative financial instruments and other financial instruments that the Company was a party to as of December 31, 1999 and 1998, which are sensitive to changes in interest rates. For debt obligations, the tables present maturities by expected maturity dates together with the weighted average interest rates expected to be paid on the debt, given current contractual terms and market conditions. For fixed rate debt, the weighted average interest rate represents the contractual fixed rates that the Company is obligated to periodically pay on the debt; for variable rate debt, the average interest rate represents the average rates being paid on the debt projected forward proportionate to the forward yield curve for United States treasury securities. As of December 31, 1998, the Company was a party to a series of interest rate swap agreements whereby the Company paid a variable rate on a $150 million notional amount and received a fixed annual rate of 6.62 percent of the notional amount. The fair value of the swap agreements to the Company represented an asset of $1.046 million as of December 31, 1998. The swap agreements were accounted for as hedges by the Company until their maturity during May and June 1999. The Company was also a party to a non- hedge interest rate cap as of December 31, 1998. Under the terms of the cap agreement, the Company paid the counterparties a .28 percent annual rate on an $80 million notional amount, so long as the Canadian bankers' acceptance reference rate did not exceed 8.00 percent per year. The fair value of the interest rate cap represented a liability of the Company of $80 thousand on December 31, 1998. The interest rate cap matured in August 1999.
Pioneer Natural Resources Company
Interest Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1999
Pioneer Natural Resources Company Interest Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1998
(1) Excludes $23.0 million and $38.5 million of debt instruments for which fair values were not practicable to derive as of December 31, 1999 and 1998, respectively.
Foreign exchange rate sensitivity. The following tables provide information, in United States dollar equivalent amounts, about the Company's derivative financial instruments that the Company was a party to as of December 31, 1999 and 1998 and that are sensitive to changes in foreign exchange rates. The tables provide information regarding the notional amounts of the Company's Canadian dollar denominated foreign currency swap derivative contracts, including rates paid and received by the Company and forward currency exchange rates. See "Interest rate sensitivity", above, for information regarding the Company's Canadian dollar denominated interest rate cap that matured during August 1999.
Pioneer Natural Resources Company Foreign Exchange Rate Sensitivity Derivative And Other Financial Instruments As of December 31, 1999
Pioneer Natural Resources Company Foreign Exchange Rate Sensitivity Derivative And Other Financial Instruments As of December 31, 1998
(1) The foreign exchange rate swaps mature in October and December 2000.
Commodity price sensitivity. The following tables provide information, in United States dollar equivalent amounts, about the Company's derivative financial instruments that the Company was a party to as of December 31, 1999 and 1998 and that are sensitive to changes in crude oil and natural gas commodity prices. The tables segregate hedge derivative contracts from those that do not qualify as hedges.
Commodity hedge instruments. The Company hedges commodity price risk with swap contracts, put contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Put contracts provide a fixed floor price on a notional amount of sales volumes while allowing full price participation if the relevant index price closes above the floor price. Collar contracts provide a floor price for the Company on a notional amount of sales volumes while allowing some additional price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price below which the Company's realized price will exceed variable market prices by the long put-to-short put price differential.
Commodity non-hedge instruments. The Company has entered into BTU swap contracts and optional call contracts that do not qualify for hedge accounting. Under the terms of the BTU swap contracts, the Company receives 10 percent of the NYMEX oil price and pays the NYMEX gas price on a 13,036 notional MMBtu daily gas volume. As of December 31, 1998, this derivative instrument was the only financial instrument that the Company was a party to that was sensitive to changes in crude oil prices. The relevant information is included in the Company's natural gas price sensitivity table as of December 31, 1998.
The terms of the optional call contracts provide the counterparties with the option to elect to call either notional crude oil volumes or natural gas volumes at specific index prices. Accordingly, these derivative instruments are presented in both the accompanying crude oil and natural gas tables.
See Notes B, C and H of Notes to Consolidated Financial Statements included in "Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of Pioneer Natural Resources Company: Independent Auditors' Reports......................................... 41 Consolidated Balance Sheets as of December 31, 1999 and 1998.......... 42 Consolidated Statements of Operations and Comprehensive Loss for the Years Ended December 31, 1999, 1998 and 1997.................. 43 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1999, 1998 and 1997................................... 44 Consolidated Statements of Cash Flows for the Years Ended December 31, 1999, 1998, and 1997............................................... 45 Notes to Consolidated Financial Statements............................ 46 Unaudited Supplementary Information................................... 76
INDEPENDENT AUDITORS' REPORTS
The Board of Directors and Shareholders Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of operations and comprehensive loss, stockholders' equity, and cash flows for the years ended December 31, 1999 and 1998. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company and subsidiaries at December 31, 1999 and 1998, and the consolidated results of its operations and its cash flows for the years ended December 31, 1999 and 1998 in conformity with accounting principles generally accepted in the United States.
Ernst & Young LLP
Dallas, Texas January 24, 2000
The Board of Directors and Stockholders Pioneer Natural Resources Company:
We have audited the consolidated statements of operations and comprehensive loss, stockholders' equity, and cash flows of Pioneer Natural Resources Company and subsidiaries for the year ended December 31, 1997. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provided a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Pioneer Natural Resources Company and subsidiaries for the year ended December 31, 1997, in conformity with generally accepted accounting principles.
KPMG LLP
Midland, Texas February 13, 1998
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
ASSETS
The accompanying notes are an integral part of these consolidated financial statements.
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS (in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (in thousands, except dividends per share)
The accompanying notes are an integral part of these consolidated financial statements.
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company (the "Company") is a Delaware Corporation whose common stock is listed and traded on the New York Stock Exchange and the Toronto Stock Exchange. The Company was formed by the merger of Parker & Parsley Petroleum Company ("Parker & Parsley") and MESA Inc. ("Mesa") in August 1997. The Company subsequently acquired the Canadian and Argentine oil and gas business of Chauvco Resources Ltd. ("Chauvco"), a publicly traded independent oil and gas company based in Calgary, Canada , during December 1997. The Company is an oil and gas exploration and production company with ownership interests in oil and gas properties located principally in the Mid Continent, Southwestern and onshore and offshore Gulf Coast regions of the United States and in Argentina, Canada and South Africa.
In accordance with the provisions of Accounting Principles Board Opinion No. 16, "Business Combinations" ("APB 16"), both the merger with Mesa and the acquisition of Chauvco were accounted for as purchases by the Company (formerly Parker & Parsley). As a result, the historical financial statements for the Company are those of Parker & Parsley prior to August 1997.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries since their acquisition or formation, and the Company's interest in the affiliated oil and gas partnerships for which it serves as general partner through certain of its wholly-owned subsidiaries. Investments in less than majority-owned subsidiaries where the Company has the ability to exercise significant influence over the investee's operations are accounted for by the equity method. The Company proportionately consolidates less than 100 percent-owned oil and gas partnerships in accordance with industry practice. The Company owns less than a 20 percent interest in the oil and gas partnerships that it proportionately consolidates. All material intercompany balances and transactions have been eliminated.
The Company determines the appropriate classification of investments in non-affiliated equity securities at the time of purchase and re-evaluates such determinations at each balance sheet date.
Investments in non-affiliated equity securities that have a readily determinable fair value are classified as "trading securities" if management's current intent is to hold them for only a short period of time; otherwise, they are accounted for as "available-for-sale" securities. The carrying value of trading securities and available-for-sale securities are adjusted to fair value as of each balance sheet date. Unrealized holding gains and losses are recognized for trading securities in interest and other revenue, in the case of unrealized holding gains, or other expense, in the case of unrealized holding losses, during the periods in which changes in fair value occur. Unrealized holding gains and losses would be recognized for available-for-sale securities as credits or charges to stockholders' equity during the periods in which changes in fair value occur, and would also be included as items of other comprehensive income (loss). The Company did not have any investments in available-for-sale securities during the years ended December 31, 1999, 1998 or 1997.
Investments in non-affiliated equity securities that do not have a readily determinable fair value are measured in the accompanying Consolidated Balance Sheet as of December 31, 1999 at the lower of their original cost less associated cash dividends received, or the net realizable value of the investment.
Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated 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, the
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Cash equivalents. Cash and cash equivalents include cash on hand and depository accounts held by banks.
Inventories. Inventories consist of lease and well equipment which are carried at the lower of cost or market, on a first-in first-out basis.
Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs are expensed. The Company capitalizes interest on expenditures for significant development projects until such time as operations commence.
The Company accounts for its natural gas processing facilities activities as part of its oil and gas properties for financial reporting purposes. All revenues and expenses derived from third party gas volumes processed through the Company's natural gas processing facilities have been reported as components of oil and gas production costs. The capitalized costs of natural gas processing facilities are included in proved oil and gas properties and are depleted using the unit-of-production method.
Capitalized costs relating to proved properties are depleted using the unit-of-production method based on proved reserves as determined by the Company's engineers. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined.
Generally, capitalized costs of individual properties sold or abandoned are charged to accumulated depletion, depreciation and amortization with the proceeds from the sales of individual properties credited to property costs; no gain or loss is recognized until the entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the property costs are significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
If significant, the Company accrues the estimated future costs to plug and abandon wells under the unit-of- production method. The charge, if any, is reflected in the accompanying Consolidated Statements of Operations and Comprehensive Loss as abandonment expense while the liability is reflected in the accompanying Consolidated Balance Sheets as other liabilities. Plugging and abandonment liabilities assumed in a business combination accounted for as a purchase are recorded at fair value. At December 31, 1999 and 1998, the Company has recognized plugging and abandonment liabilities of $44.2 million and $44.5 million, respectively.
In accordance with Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", the Company reviews its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment by comparing their cost to their estimated value on a project-by-project basis. The estimated value is affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. If the quantity of potential reserves determined by such evaluations are not sufficient to fully
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
recover the cost invested in each project, the Company will recognize a loss at the time of impairment by providing an impairment allowance. The remaining unproved oil and gas properties are aggregated and an overall impairment allowance is provided based on the Company's historical experience.
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. The Company believes that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on the Company's financial position or results of operations.
Revenue recognition. The Company uses the entitlements method of accounting for crude oil, natural gas liquids ("NGL") and natural gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying Consolidated Balance Sheets. As of December 31, 1999 and 1998, entitlement liabilities totaled $15.5 million and $20.6 million, respectively, and entitlement assets totaled $33.0 million and $38.2 million, respectively.
Stock-based compensation. The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). Accordingly, the Company has only adopted the disclosure provisions of Statement of Financial Accounting Standards No.123, "Accounting for Stock-Based Compensation" ("SFAS 123"). See Note F for the pro forma disclosures of compensation expense determined under the fair-value provisions of SFAS 123.
Hedging. The following criteria must be met in order for the Company to account for a financial instrument as a hedge of an existing asset, liability or forecasted transaction: an asset, liability or forecasted transaction must exist that exposes the Company to price, interest rate or foreign exchange rate risk that is not offset in another asset or liability; the hedging contract must reduce that price, interest rate or foreign exchange rate risk; and, the instrument must be designated as a hedge at the inception of the contract and throughout the hedge period. In order to qualify as a hedge, there must be clear correlation between changes in the fair value of the financial instrument and the fair value of the hedged asset, liability or forecasted transaction, such that changes in the market value of the financial instrument will be offset by the effect of price, interest rate or foreign exchange rate changes on the exposed items.
Gains or losses realized from financial instruments that qualify as hedges are deferred as assets or liabilities until the underlying hedged asset, liability or transaction monetizes, matures or is otherwise recognized under generally accepted accounting principles. When recognized, hedge gains and losses are classified as components of the commodity prices, interest or foreign exchange rates that the financial instruments hedge. Derivative financial instruments that do not qualify as hedges are marked-to-market and recorded as assets or liabilities. Changes in the fair values of such instruments are recognized as other income or other expense during the periods in which their fair values change. See Note H for a description of the specific types of derivative transactions in which the Company participates.
Foreign currency translation. The financial statements of subsidiary entities whose functional currency is not the United States dollar are translated to United States dollars as follows: all assets and liabilities at year-end exchange rates; revenues, costs and expenses at average exchange rates. Gains and losses from translating non-United States dollar denominated balances are recorded directly in stockholders' equity. Foreign currency transaction gains and losses are included in net loss.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
The exchange rates used in the preparation of these consolidated financial statements appear below:
Reclassifications. Certain reclassifications have been made to the 1998 and 1997 amounts to conform to the 1999 presentation.
NOTE C. Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values of the Company's financial instruments as of December 31, 1999 and 1998:
Cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
Investments in non-affiliated entities. During 1999, the Company received 2,307.693 shares of Prize Energy Corp. ("Prize") six percent convertible preferred stock ("Prize Preferred"), having a liquidation preference and estimated fair value of $30.0 million on the date acquired, in partial consideration for oil and gas properties, gas plants and other assets sold to Prize (see Note K for information specific to the assets sold to, and the investment in, Prize). As of December 31, 1999, Prize was a closely held, non-public entity. As such, the fair value of the Prize Preferred was not readily determinable. During 1999, the Company earned dividends of 69.23 additional shares of Prize Preferred.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
On February 9, 2000, Prize announced a merger with Vista Energy Resources Inc., whereby the common stock of the merged Prize entity began to publicly trade on the American Stock Exchange. Associated therewith, the Company's Prize Preferred was exchanged for 3,984,197 shares of Prize Series A 6% Convertible Preferred Stock ("Prize Senior A Preferred") having a liquidation preference and stated value of $7.81 per share, plus cumulative dividends accrued and unpaid. Each share of Prize Series A Preferred is convertible, at the option of the holder, into one share of Prize common stock. Under certain circumstances, Prize may redeem the Prize Series A Preferred at the stated value per share, unless the Company exercises its conversion rights. The fair value of the Prize Series A Preferred is not readily determinable.
As of December 31, 1998, the Company owned three million shares of common stock of a closely held, non- affiliated, public entity having a fair value of $12.0 million. The three million shares of common stock were received by the Company as partial consideration for the sale of an exclusive and irrevocable option to purchase certain oil and gas properties and other assets of the Company. During 1999, the Company's investment in the entity was increased to four million shares of common stock as a result of liquidation damages received by the Company from the non- affiliated entity (see Note K for information pertaining to the Company's transactions with the entity). This investment was classified by the Company as an investment in trading securities. As a result of declines in the fair value of this investment, other expenses in the accompanying Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 1999 and 1998, include non-cash mark-to-market charges of $11.9 million and $.8 million, respectively. The Company sold its investment in the common stock during 1999.
Long-term debt. The carrying amount of borrowings outstanding under the Company's line of credit (see Note D for definitions and descriptions of each) approximates fair value because these instruments bear interest at rates tied to current market rates. The fair values of each of the senior note issuances were based on quoted market prices for each of these issues.
It was not practicable to estimate the fair value of certain of the long-term debt obligations because quoted market prices are not available and the Company does not have a current borrowing rate which could be used as a comparable rate for the stated maturities of the obligations.
Interest rate swaps, interest rate cap agreements, foreign currency swap contracts and commodity price swap and option contracts. The fair value of interest rate swaps, interest rate cap agreements, foreign currency contracts and commodity price swap and option contracts are estimated from quotes provided by the counterparties to these instruments and represent the estimated amounts that the Company would expect to receive or pay to terminate the agreements. See Note H for a description of each of these instruments, including whether the derivative contract qualifies for hedge accounting treatment or is considered a speculative derivative instrument.
NOTE D. Long-term Debt December 31, ----------------------- 1999 1998 ---------- ---------- (in thousands)
Lines of credit..................................... $ 825,000 $1,249,984 8-7/8% senior notes due 2005........................ 150,000 150,000 8-1/4% senior notes due 2007 (net of discount)...... 149,482 149,414 6-1/2% senior notes due 2008 (net of discount)...... 348,550 348,418 7-1/5% senior notes due 2028 (net of discount)...... 249,909 249,908 Other............................................... 22,995 27,541 --------- --------- 1,745,936 2,175,265 Less current maturities............................. 828 306,521 --------- --------- $1,745,108 $1,868,744 ========= =========
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
Maturities of long-term debt at December 31, 1999 are as follows (in thousands):
2000............................................ $ 828 2001............................................ $ - 2002............................................ $825,000 2003............................................ $ 518 2004............................................ $ 571 Thereafter...................................... $919,019
Lines of credit. As of December 31, 1999, the Company has a credit facility (the "Credit Facility") with a syndicate of banks (the "Banks") with commitments aggregating $939.6 million and outstanding borrowings of $825 million. Advances under the Credit Facility are required to be paid no later than August 7, 2002.
Advances on the Credit Facility bear interest at the option of the Company, based on (a) the prime rate of NationsBank of Texas, N.A. (8.50 percent at December 31, 1999), (b) a Eurodollar rate (substantially equal to the London Interbank Offered Rate ("LIBOR")) adjusted for the reserve requirement as determined by the Board of Governors of the Federal Reserve System with respect to transactions in Eurocurrency liabilities ("LIBOR Rate"), or (c) a competitive bid rate as quoted by the lending banks electing to participate pursuant to a request by the Company. The interest rate on LIBOR Rate advances includes an interest rate margin component that is determined by a grid that is based on the Company's senior unsecured long-term public debt rating. As of December 31, 1999, the future maximum interest rate margin on LIBOR Rate advances is 187.5 basis points.
The Credit Facility contains various debt convenants, the most restrictive being the maintenance of a ratio of outstanding Company debt to earnings before interest, depletion, depreciation, amortization, income tax, exploration and abandonment and other non-cash expenses ("EBITDAX") not to exceed 4.25 to one through March 31, 2000, and 3.5 to one thereafter. Other restrictive compliance requirements include limits on the incurrence of additional indebtedness and certain types of liens and restrictions as to merger, sale or transfer of assets and transactions without the Banks' consent. The Company's obligations under the Credit Facility are also guaranteed by Pioneer Natural Resources USA, Inc. ("Pioneer USA") and certain other United States subsidiaries, and are secured by a pledge of a portion of the capital stock of certain non-United States subsidiaries.
During the first quarter of 1999, the Company and the Banks executed amendments to the Credit Facility that provided for the consolidation of the Company's $276 million Canadian subsidiary term loan with and into the Credit Facility. The amendments also provided for a $410 million reduction in loan commitments by December 31, 1999, an increase in the maximum interest rate margin on LIBOR Rate advances to 250 basis points including commitment utilization fees and the debt covenants outlined above. The Company met each of the requirements of the amended Credit Facility during 1999.
Senior notes. The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. In addition, the Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes issuances are structurally subordinated to all obligations of its subsidiaries. Pioneer USA has fully and unconditionally guaranteed the senior note issuances. Interest on the Company's senior notes is payable semi-annually.
Extraordinary items. On December 18, 1997, the Company completed a cash tender offer for two senior subordinated note issuances (the "Subordinated Notes") assumed as part of the merger with Mesa. During 1997, the Company redeemed approximately 91 percent of the 11-5/8% senior subordinated discount notes due 2006 and approximately 98 percent of the 10-5/8% senior subordinated notes due 2006 (the "10-5/8% Notes") for a purchase price of $829.90 and
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
$1,171.40, respectively, per $1,000 tendered plus any interest accrued on the 10-5/8% Notes (the "Tender Offer"). As a result, the Company paid $574.5 million for the principal amount tendered on the Subordinated Notes, including related fees, and $15.7 million of accrued interest on the 10-5/8% Notes. As a result of the Tender Offer, the Company recognized an extraordinary loss on early extinguishment of debt of $11.9 million (net of a related tax benefit of $6.4 million) during the fourth quarter of 1997. The Company financed the purchase price of the Subordinated Notes tendered in the offer with borrowings under its Credit Facility Agreements.
In addition to the extraordinary loss resulting from the Tender Offer, the accompanying Consolidated Statement of Operations and Comprehensive Loss for the year ended December 31, 1997 includes a $1.5 million (net of a related tax benefit of $800 thousand) non-cash charge for an extraordinary loss on the early extinguishment of debt resulting from the merger of Parker & Parsley and Mesa. This extraordinary loss relates to capitalized issuance fees associated with Parker & Parsley's previously existing bank credit facility which was replaced by the Credit Facility .
Interest expense. The following amounts have been charged to interest expense for the years ended December 31, 1999, 1998 and 1997:
NOTE E. Related Party Transactions
Activities with affiliated partnerships. The Company, through its wholly-owned subsidiaries, has in the past sponsored certain affiliated partnerships, including 35 public and nine private drilling partnerships and three public income partnerships, all of which were formed primarily for the purpose of drilling and completing wells or acquiring producing properties. In accordance with the terms of the partnership agreements and the related tax partnership agreements of the affiliated partnerships, the Company participated in the activities of the sponsored partnerships on a promoted basis. In 1992, the Company discontinued sponsoring public and private oil and gas development drilling and income partnerships.
During each of 1994, 1993 and 1992, the Company formed a Direct Investment Partnership for the purpose of permitting selected key employees to invest directly, on an unpromoted basis, in wells that the Company drills. The partners in the Direct Investment Partnerships formed in 1994, 1993 and 1992 pay and receive approximately .337 percent, 1.5375 percent and 1.865 percent, respectively, of the costs and revenues attributable to the Company's interest in the wells that such Direct Investment Partnership participates. The Company discontinued the formation of Direct Investment Partnerships in 1995.
The Company, through a wholly-owned subsidiary, serves as operator of properties in which it and its affiliated partnerships have an interest. Accordingly, the Company receives producing well overhead, drilling well overhead and other fees related to the operation of the properties. The affiliated partnerships also reimburse the Company for their allocated share of general and administrative charges.
The activities with affiliated partnerships are summarized for the following related party transactions for the years ended December 31, 1999, 1998 and 1997:
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
Prize divestiture. As further disclosed in Note K, the Company sold certain oil and gas properties, gas plants and other assets to Prize during 1999. Associated with these transactions, the Company received $245.0 million of proceeds, including the 2,307.693 shares of Prize Preferred valued at $30.0 million. The board of directors of Prize is comprised of six directors, which include Mr. Philip P. Smith, the Chief Executive Officer; Mr. Kenneth A. Hersh; Mr. Lon C. Kile; two members of the Company's executive management committee; and, a member who is unrelated to the Company. Messrs. Smith and Hersh were members of the Board of Directors of the Company and resigned their positions with the Company during the second quarter of 1999. Additionally, Mr. Lon C. Kile resigned his position as Executive Vice President of the Company to accept the position of President and Chief Operating Officer of Prize. The sale of the assets to Prize was initiated through an auction process which, upon receipt of Prize's initial offer, was placed under the supervision of a special independent committee (comprised of outside directors unrelated to Prize) of the Company's Board of Directors. The independent committee reviewed and considered all offers presented to the Company for the purchase of the assets acquired by Prize. The Prize offer was approved by the special independent committee as being the best offer presented (see Notes C and K for information pertaining to the divestiture of assets to Prize and the Company's investment in Prize).
Consulting fee. Effective January 1, 1999, the Company entered into an amended and restated agreement with Rainwater, Inc., whereby the Company will pay Rainwater, Inc. $300,000 per year and reimburse Rainwater, Inc. for certain expenses in consideration for certain consulting and financial analysis services provided to the Company by Rainwater, Inc. and its representatives. The term of this agreement expires on December 31, 2003. During 1999, 1998 and 1997, consulting and financial analysis services provided to the Company totaled $325,000, $400,000 and $100,000; respectively, plus expenses. Richard E. Rainwater, who serves on the Company's Board of Directors, is the sole shareholder of Rainwater, Inc.
NOTE F. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. Effective August 8, 1997, the Compensation Committee of the Board of Directors approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary. The Company will then provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first 10 percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan.
In December 1998, the Company received notification that an investment fund group had acquired beneficial ownership of greater than 20 percent of the Company's common stock. Pursuant to the then existing provisions within the Company's deferred compensation retirement plan, if a third party acquired 20 percent or more of the Company's common stock certain change of control provisions contained within the plan were triggered. Accordingly, in December 1998, the Compensation Committee of the Board of Directors determined that a change of control had occurred, effective September 30, 1998, under the deferred compensation retirement plan. Consequently, all of the contributions to the deferred compensation retirement plan from August 1997 to December 15, 1998 were immediately vested and distributed.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) Plan (the "401(k) Plan") is a defined contribution pension plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount of not less than two percent nor more than 12 percent of their annual salary into the 401(k) Plan. Each participant's account is credited with the participant's contributions and an allocation of the 401(k) Plan's earnings. Participants are immediately fully vested in their account balances.
Matching plan. The Pioneer Natural Resources USA, Inc. Matching Plan (the "Matching Plan") is a money purchase pension plan which accumulates benefits to participants. All regular full-time and part-time employees of Pioneer USA become eligible to participate in the Matching Plan concurrent with their eligibility to participate in the 401(k) Plan. All Matching Plan contributions are made in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's basic compensation (the "Matching Contribution"). Each participant's account is credited with their Matching Contribution and an allocation of Matching Plan earnings. Participants proportionately vest in their account balances over a four year period, at the end of which they are fully vested in their account balances. During the years ended December 31, 1999, 1998 and 1997, the Company recognized compensation expense of $508 thousand, $742 thousand and $497 thousand, respectively, as a result of Matching Contributions.
Long-term incentive plan. In August 1997, the Company's stockholders approved a new long-term incentive plan (the "Long-Term Incentive Plan"), which provides for the granting of incentive awards in the form of stock options, stock appreciation rights, performance units and restricted stock to directors, officers and employees of the Company. The Long-Term Incentive Plan provides for the issuance of a maximum number of shares of common stock equal to 10 percent of the total number of shares of common stock equivalents outstanding minus the total number of shares of common stock subject to outstanding awards on the date of calculation under any stock-based plan for the directors, officers or employees of the Company.
Pursuant to the provisions within the Company's Long-Term Incentive Plan, if a third party acquires 40 percent or more of the Company's common stock, certain change of control provisions contained within the plan are triggered. In December 1998, the Compensation Committee of the Board of Directors determined that a change of control had occurred, effective September 30, 1998, under the Long-Term Incentive Plan. Consequently, all awards granted under the Long-Term Incentive Plan since its inception in August 1997 through September 30, 1998 were immediately vested and any restrictions were canceled.
The following table calculates the number of shares or options available for grant under the Company's Long- Term Incentive Plan as of December 31, 1999 and 1998:
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
Restricted stock awards
Non-employee directors. On May 20, 1999, the Company's Long-Term Incentive Plan was amended to eliminate the automatic award of restricted stock to non-employee directors in payment of their annual retainer fees. The effect of the amendment was to provide the Compensation Committee of the Board of Directors with the authority to determine what awards, if any, non-employee directors will receive and what the terms of those awards will be and, alternatively, to award stock options to non-employee directors in payment of their annual retainer fees. During 1999, the Company awarded stock options to the non-employee directors in payment of their annual retainer fees. The options awarded were determined by dividing the annual retainer fees by the value of one option on the last business day of the month in which the fee was paid. The option values were determined using the Black-Scholes method (see "Stock Option Awards", below). Prior to this amendment, on the last business day of the month in which the annual meeting of the stockholders of the Company was held, each non-employee director automatically received an award of common stock equal to 50 percent of their annual retainer fee. These awards were made in lieu of an amount of cash equal to 50 percent of the annual retainer fee. In May 1998 and August 1997, the Company issued an aggregate 17,306 shares and 5,939 shares, respectively, to non-employee directors pursuant to this arrangement.The shares of common stock awarded pursuant to the Long-Term Incentive Plan are subject to transfer restrictions that lapse on the first anniversary of the date of the award.
Officers and key employees. The Company, at its sole discretion, may pay annual bonuses awarded to selected officers and key employees either 100 percent in cash or partially in cash and partially in the form of restricted stock awards under the Long-Term Incentive Plan. The Company has established target bonus levels for each officer and key employee. Based upon Company and individual performance during the year, each officer or key employee has the potential to earn more or less than their target bonus level. The bonus awards are determined in the quarter following the Company's December 31 year-end. During 1997, the Company awarded restricted stock pursuant to this program. The 1997 awards were limited to one-half of each officer's or key employee's target bonus level, and the remainder of the officer's or key employee's annual bonus was paid in cash. The number of shares of restricted stock that were awarded pursuant to the annual bonus program were based on the closing sales price of the Company's common stock on the day immediately preceding the date of the award. Ownership of the restricted stock awarded vested one year after the date it was issued, subject to transfer restrictions that lapsed on one-third of the shares on each of the first, second and third anniversaries of the date of grant. Each recipient of restricted stock also received an amount of cash equal to the estimated federal income taxes payable as a result of the receipt of such award. On February 9, 1998, the Company awarded an aggregate of 81,300 shares of restricted stock at a price of $22.375 pursuant to the 1997 annual bonus program. The Company elected not to award any restricted stock in conjunction with the 1999 or 1998 annual bonus programs.
During 1998 and 1997, the Company made other Long-Term Incentive Plan awards of 38,480 and 470,975 shares, respectively, to certain officers and key employees. The shares awarded are subject to vesting period and transfer restrictions.
Stock Option Awards
The Company has a program of awarding semi-annual stock options to its officers and employees and annual stock options to its directors, as part of their annual compensation. This program provides for annual awards at an exercise price based upon the closing sales price of the Company's common stock on the day prior to the date of grant. The awards vest over an 18 month or three year schedule and provide a five year exercise period from each vesting date. The Company granted 1,985,193; 2,146,553 and 1,716,625 options under the Long-Term Incentive Plan during 1999, 1998 and 1997, respectively.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
Other stock based plans. Prior to the merger with Mesa, both Parker & Parsley and Mesa had long-term incentive plans (Parker & Parsley Long-Term Incentive Plan, 1991 Stock Option Plan of Mesa and the 1996 Incentive Plan of Mesa) in place that allowed Parker & Parsley and Mesa to grant incentive awards similar to the provisions of the Long-Term Incentive Plan. Upon consummation of the merger between Parker & Parsley and Mesa, all awards under these plans were assumed by the Company with the provision that no additional awards be granted under these plans.
The information presented in the remainder of this footnote represents the awards granted under the Long-Term Incentive Plan since its approval in August 1997, the awards granted in 1997 under the Parker & Parsley Long-Term Incentive Plan, and the assumption in August 1997 of the outstanding option awards granted under the 1991 Stock Option Plan of Mesa and the 1996 Incentive Plan of Mesa.
Restricted stock awards. The following table reflects the outstanding restricted stock awards and activity related thereto for 1999, 1998 and 1997:
Stock option awards. The Company applies APB 25 and related interpretations in accounting for its stock option awards. Accordingly, no compensation expense has been recognized for its stock option awards. If compensation expense for the stock option awards had been determined consistent with SFAS 123, the Company's net losses and net losses per share would have been adjusted to the pro forma amounts indicated below:
For the Year Ended December 31, --------------------------------- 1999 1998 1997 --------- --------- --------- (in thousands, except per share amounts)
Net loss................................ $(25,269) $(775,349) $(893,729) Basic and diluted net loss per share.... $ (.25) $ (7.75) $ (17.20)
Under SFAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black- Scholes option pricing model with the following weighted average assumptions used for grants in 1999, 1998 and 1997:
For the Year Ended December 31, --------------------------- 1999 1998 1997 ------- ------- ------- Risk-free interest rate.................... 6.59% 5.45% 5.72% Expected life.............................. 6 years 6 years 7 years Expected volatility........................ 48% 36% 36% Expected dividend yield.................... - .56% .30%
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
A summary of the Company's stock option plans as of December 31, 1999, 1998 and 1997, and changes during the years ended on those dates, are presented below:
The following table summarizes information about the Company's stock options outstanding at December 31, 1999:
During 1999, the Company recognized $.2 million of costs related to its incentive plans in other expense. The Company recognized $3.9 million and $3.3 million in general and administrative compensation expense related to its Incentive Plans during 1998 and 1997, respectively. During 1998, the Company also recognized $9.6 million in other expense related to restricted stock awards that were immediately vested as a result of the Long-Term Incentive Plan change in control provisions and $3.1 million of reorganization costs related to its Incentive Plans.
NOTE G. Commitments and Contingencies
Severance agreements. The Company has entered into severance agreements with its officers, subsidiary company officers and certain key employees. Salaries and bonuses for the Company's officers are set independent of this agreement by the Compensation Committee for the parent company officers and the Management Committee for subsidiary company officers and key employees. These committees can grant increases or reductions to base salary at their discretion. The current annual salaries for the parent company officers, the subsidiary company officers and key employees covered under such agreements total approximately $8.2 million.
Either the Company or the officer/key employee may terminate the officer's or key employee's employment under the severance agreement at any time. The Company must pay the officer or key employee an amount equal to one year's base salary if employment is terminated because of death, disability, or normal retirement. The Company must pay the officer or key employee an amount
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
equal to one year's base salary and continue health insurance for the officer or key employee and his or her immediate family for one year if the Company terminates employment without cause or if the officer or key employee terminates employment with good reason, which occurs when reductions in the officer's or key employee's base annual salary exceed specified limits or if, in the case of officers, the officer is demoted to an officer position junior to their current officer position or to a non-officer position. If within one year after a change in control of the Company, the Company terminates the officer or key employee without cause or if the officer or key employee terminates employment with good reason, the Company must pay parent company officers an amount equal to 2.99 times the sum of the officer's base salary plus target bonus for the year and subsidiary company officers and key employees an amount equal to two times the officer's or key employee's base salary and continue health insurance for the officer or key employee and his immediate family for one year. If the officer or key employee terminates employment with the Company without good reason between six months and one year after a change in control, or at any time within one year after a change in control if the officer or key employee is required to move, then the Company must pay the officer or key employee one year's base salary and continue health insurance for the officer or key employee and his or her immediate family for one year. Officers and key employees are also entitled to additional payments for certain tax liabilities that may apply to severance payments following a change in control.
Indemnifications. The Company has indemnified its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Legal actions. The Company is party to various legal actions incidental to its business, including, but not limited to, the proceedings described below. The majority of these lawsuits primarily involve claims for damages arising from oil and gas leases and ownership interest disputes. The Company believes that the ultimate disposition of these legal actions will not have a material adverse effect on the Company's consolidated financial position, liquidity, capital resources or future results of operations. The Company will continue to evaluate its litigation matters on a quarter-by- quarter basis and will adjust the litigation reserve as appropriate to reflect the then current status of its litigation.
Masterson. In February 1992, the current lessors of an oil and gas lease (the "Gas Lease") dated April 30, 1955, between R.B. Masterson et al., as lessor, and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in Federal District Court in Amarillo, Texas, claiming that CIG had underpaid royalties due under the Gas Lease. Under the agreements with CIG, the Company, as successor to Mesa, has an entitlement to gas produced from the Gas Lease. In August 1992, CIG filed a third-party complaint against the Company for any such royalty underpayment which may be allocable to the Company. Plaintiffs alleged that the underpayment was the result of CIG's use of an improper gas sales price upon which to calculate royalties and that the proper price should have been determined pursuant to a "favored-nations" clause in a July 1, 1967, amendment to the Gas Lease. The plaintiffs also sought a declaration by the court as to the proper price to be used for calculating future royalties.
The plaintiffs alleged royalty underpayments of approximately $500 million (including interest at 10 percent) dating from July 1, 1967. In March 1995, the court made certain pretrial rulings that eliminated approximately $400 million of the plaintiff's claims (which related to periods prior to October 1, 1989), but which also reduced a number of the Company's defenses. The Company and CIG filed stipulations with the court whereby the Company would have been liable for between 50 percent and 60 percent, depending on the time period covered, of an adverse judgment against CIG or post-February 1988 underpayments of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury returned its verdict. Among its findings, the jury determined that CIG had underpaid royalties for the period after September 30, 1989, in the amount of approximately $140,000. Although the plaintiffs argued that the "favored-nations" clause entitled them to be paid for all of their gas at the highest price voluntarily paid by CIG to any other lessor, the jury determined that the plaintiffs were estopped from claiming that the "favored-nations"
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
clause provides for other than a pricing-scheme to pricing- scheme comparison. In light of this determination, and the plaintiff's stipulation that a pricing-scheme to pricing-scheme comparison would not result in any "trigger prices" or damages, defendants asked the court for a judgment that plaintiffs take nothing. The court, on June 7, 1995, entered final judgment that plaintiffs recover no monetary damages. The plaintiffs filed a motion for new trial on June 22, 1995. The court, on July 18, 1997, denied plaintiffs' motion. The plaintiffs have appealed to the Fifth Circuit Court of Appeals, where oral arguments were heard in December 1998. The Court's decision regarding this litigation could be announced at any time.
On June 7, 1996, the plaintiffs filed a separate suit against CIG and the Company in state court in Amarillo, Texas, similarly claiming underpayment of royalties under the "favored-nations" clause, but based upon the above- described pricing-scheme to pricing-scheme comparison on a well-by-well monthly basis. The plaintiffs also claim underpayment of royalties since June 7, 1995, under the "favored-nations" clause based upon either the pricing-scheme to pricing-scheme method or their previously alleged higher price method. The Company believes it has several defenses to this action and intends to contest it vigorously. The Company has not yet determined the amount of damages, if any, that would be payable if such action was determined adversely to the Company.
The federal court in the above-referenced first suit issued an order on July 29, 1996, which stayed the state suit pending the plaintiffs' resolution of the first suit.
Based on the jury verdict and final judgment, the Company does not currently expect the ultimate resolution of either of these lawsuits to have a material adverse effect on its financial position or results of operations.
Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows a "severance, production or similar" tax to be included as an add-on, over and above the maximum lawful price for natural gas. Based on a Federal Energy Regulatory Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, Mesa collected the Kansas ad valorem tax in addition to the otherwise maximum lawful price. The FERC's ruling was appealed to the United States Court of Appeals for the District of Columbia ("D.C. Circuit"), which held in June 1988 that the FERC failed to provide a reasoned basis for its findings and remanded the case to the FERC for further consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling, but limiting the effect of its decision to Kansas ad valorem taxes for sales made on or after June 28, 1988. The FERC clarified the effective date of its decision by an order dated May 18, 1994. The order clarified that the effective date applies to tax bills rendered after June 28, 1988, not sales made on or after that date. Numerous parties filed appeals on the FERC's action in the D.C. Circuit. Various natural gas producers challenged the FERC's orders on two grounds: (1) that the Kansas ad valorem tax, properly understood, does qualify for reimbursement under the NGPA; and (2) the FERC's ruling should, in any event, have been applied prospectively. Other parties challenged the FERC's orders on the grounds that the FERC's ruling should have been applied retroactively to December 1, 1978, the date of the enactment of the NGPA and producers should have been required to pay refunds accordingly.
The D.C. Circuit issued its decision on August 2, 1996, which holds that producers must make refunds of all Kansas ad valorem tax collected with respect to production since October 4, 1983 as opposed to June 28, 1988. Petitions for rehearing were denied on November 6, 1996. Various natural gas producers subsequently filed a petition for writ of certiori with the United States Supreme Court seeking to limit the scope of the potential refunds to tax bills rendered on or after June 28, 1988 (the effective date originally selected by the FERC). Williams Natural Gas Company filed a cross-petition for certiori seeking to impose refund liability back to December 1, 1978. Both petitions were denied on May 12, 1997.
The Company and other producers filed petitions for adjustment with the FERC on June 24, 1997. The Company is seeking waiver or set-off from FERC with respect to that portion of the refund associated with (i) non- recoupable royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the higher prices collected, and (iii)
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
interest for all periods. On September 10, 1997, FERC denied this request, and on October 10, 1997, the Company and other producers filed a request for rehearing. Pipelines were given until November 10, 1997 to file claims on refunds sought from producers and refunds totaling approximately $30 million were made against the Company. The Company is unable at this time to predict the final outcome of this matter or the amount, if any, that will ultimately be refunded. As of December 31, 1999 and 1998, the Company had set aside $31.3 million and $29.7 million, respectively, including accrued interest, in an escrow account and had corresponding obligations for this litigation recorded in other current liabilities in the accompanying Consolidated Balance Sheets. In addition, during 1998, the Company paid $1.4 million to a pipeline in settlement of the pipeline's share of the total initial obligation.
Lease agreements. The Company leases equipment and office facilities under noncancellable operating leases on which rental expense for the years ended December 31, 1999, 1998 and 1997 was approximately $6.9 million, $8.9 million and $3.7 million, respectively. Future minimum lease commitments under noncancellable operating leases at December 31, 1999 are as follows (in thousands):
2000......................................... $ 6,765 2001......................................... $ 5,684 2002......................................... $ 4,517 2003......................................... $ 4,070 2004......................................... $ 3,549 Thereafter................................... $ 3,388
NOTE H. Derivative Financial Instruments
The Company uses derivative financial instruments to manage interest rate, foreign exchange rate and commodity price risks. The Company is exposed to credit losses in the event of nonperformance by the counterparties. The Company anticipates, however, that such counterparties will be able to fully satisfy their obligations under the contracts. The Company does not obtain collateral or other security to support financial instruments subject to credit risk but monitors the credit standing of the counterparties.
The Company is a party to certain derivative financial instruments that do not qualify for hedge accounting treatment. Such instruments are marked-to-market at the end of each reporting period during their respective lives. The associated effects on the Company's results of operations in future periods could be significant. Those instruments not qualifying for hedge accounting are designated under the heading "Mark-to-Market Derivatives" below.
Hedge Derivatives
Interest rate swap agreements. During 1996, the Company entered into a series of interest rate swap agreements for an aggregate amount of $150 million with four counterparties. These agreements, which had a term of three years, effectively converted a portion of the Company's fixed-rate borrowings into floating-rate obligations. The weighted average fixed rate received by the Company over the term of these agreements was 6.62 percent, while the weighted average variable rate paid by the Company for the years ended December 31, 1999, 1998 and 1997 was 5.16 percent, 5.75 percent and 5.78 percent, respectively. The interest rate swap agreements expired in May and June, 1999. The Company was also party to an interest rate swap agreement for an aggregate amount of $250 million with one counterparty. This agreement, which expired in August 1998, effectively converted a portion of the Company's floating- rate borrowings into fixed-rate obligations. The effect of this agreement was to provide the Company with an interest rate of 6.23 percent on $250 million in nominal principal amount for the term of the agreement. The accompanying Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 1999, 1998 and 1997 include a reduction in interest expense of $849 thousand, $356 thousand and $847 thousand, respectively, associated with these rate swap agreements.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
During 1997, the Company entered into two agreements with a counterparty that obligated the Company to sell United States Treasury securities at a designated point in the future. The face amount of the United States Treasury securities was $300 million at interest rates ranging from 6.05 percent to 6.33 percent. These agreements effectively converted a portion of the Company's floating-rate borrowings into fixed-rate obligations. In January 1998, the Company terminated these agreements at a cost of $16.8 million. This amount is being amortized over the life of the Company's Credit Facility.
Commodity hedges. The Company utilizes various swap and option contracts to (i) reduce the effect of the volatility of price changes on the commodities the Company produces and sells, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) lock in prices to protect the economics related to certain capital projects.
Crude Oil. All material sales contracts governing the Company's oil production have been tied directly or indirectly to the New York Mercantile Exchange ("NYMEX") prices.
The following table sets forth the Company's outstanding oil hedge contracts as of December 31, 1999. During the first quarter of 2000, the Company terminated June 2000 through December 2000 swap contracts for notional volumes of 9,000 Bbls per day and the 2001 collar contracts (and associated sold puts) for notional volumes of 8,000 Bbls per day, at a total cost of $16.1 million. Including these costs, the Company has deferred oil hedge losses of $14.3 million and $3.7 million that will be recognized during 2000 and 2001, respectively.
- -------------
* Concurrent with the Company's purchase of the year 2000 collar contracts, the Company sold year 2000 put contracts to the counterparties for average notional contract volumes of 6,997 Bbls per day at a weighted average index price of $14.29 per Bbl. Consequently, if the weighted average year 2000 index price falls below $14.29 per Bbl, the Company will receive the weighted average index price for the notional contract volumes, plus $3.18 per Bbl. The counterparties have the contractual right to extend contracts for notional volumes of 5,000 Bbls per day through year 2001 at weighted average per Bbl strike prices of $17.00 - $20.09 for the collar contracts and $14.00 for the put contracts.
** Concurrent with the Company's purchase of the year 2001 collar contracts, the Company sold 2001 put contracts to the counterparties for equal notional contract volumes at a weighted average index price of $15.44 per Bbl. Consequently, if the weighted average year 2001 index price falls below $15.44 per Bbl, the Company will receive the weighted average index price for the notional contract volumes, plus $3.00 per Bbl.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
The Company reports average oil prices per Bbl including the effects of oil quality, gathering and transportation costs and the net effect of the oil hedges. The following table sets forth the Company's oil prices, both realized (excluding hedge results) and reported, and the net effects of settlements of oil price hedges to revenue: Year Ended December 31, --------------------------- 1999 1998 1997 ------- ------- ------- Average price reported per Bbl.................. $ 15.36 $ 13.08 $ 18.51 Average price realized per Bbl.................. $ 16.23 $ 11.93 $ 19.09 Addition (reduction) to revenue (in millions)... $ (13.4) $ 24.8 $ (7.9)
Natural Gas Liquids. During the years ended December 31, 1999 and 1998, the Company did not enter into any natural gas liquids hedge contracts. The Company reported and realized an average natural gas liquids price of $11.64 per Bbl during the year ended December 31, 1999. During the year ended December 31, 1998, the Company reported an average natural gas liquids price of $8.90 per Bbl. During the year ended December 31, 1997, the Company reported average natural gas liquids prices of $12.59 per Bbl while realizing an average price for physical sales (excluding hedging results) of $12.61 per Bbl and recorded a net decrease to natural gas liquids revenue of $77,600.
Natural Gas. The Company employs a policy of hedging a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices.
The following table sets forth the Company's outstanding gas hedge contracts as of December 31, 1999. Prices included herein represent the Company's weighted average index price per MMBtu. During the first quarter of 2000, the Company terminated Collar Contracts (and associated sold puts) for notional volumes of 45,000 MMBtu per day for the nine months ended December 31, 2000, and 60,000 MMBtu per day for the year 2001, at a cost of $4.6 million. Including this cost, the Company has deferred gas hedge losses of $4.1 million and $2.5 million that will be recognized during 2000 and 2001, respectively. In addition to the hedge contracts shown below, certain counterparties have the contractual right to sell year 2001, 2002, and 2003 swap contracts to the Company for notional contract volumes of 49,223; 12,500; and 10,000 Mcf per day, respectively, at weighted average strike prices of $2.21; $2.52; and $2.58 per MMBtu, respectively.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
- -------------
* Concurrent with the Company's purchase of the year 2000 collar contracts, the Company sold year 2000 put contracts to the counterparties for an equal volume at a weighted average index price of $1.78 per MMBtu. Consequently, if the weighted average year 2000 index price falls below $1.78 per MMBtu, the Company will receive the weighted average index price for the notional contract volumes, plus approximately $.29 per MMBtu. 54,482 MMBtu per day of the year 2000 collar contracts and associated put contracts are extendable for one year at the option of the counterparties at weighted average per MMBtu prices of $2.09-$2.71 for the collar contracts and $1.80 for the put contracts.
** Concurrent with the Company's purchase of the year 2001 collar contracts, the Company sold year 2001 put contracts to the counterparties for an equal volume at a weighted average index price of $1.95 per MMBtu. Consequently, if the weighted average year 2001 index price falls below $1.95 per MMBtu, the Company will receive the weighted average index price for the notional contract volumes, plus approximately $.30 per MMBtu. The year 2001 collar contracts and associated put contracts are extendable for one year at the option of the counterparties for notional contract volumes of 60,000 MMBtu per day at weighted average per MMBtu prices of $2.25-$2.64 for the collar contracts and $1.95 for the put contracts.
The Company reports average gas prices per Mcf including the effects of Btu content, gathering and transportation costs, gas processing and shrinkage and the net effect of the gas hedges. The following table sets forth the Company's gas prices, both realized (excluding hedge results) and reported, and the net effects of settlements of gas price hedges to revenue:
Year Ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------
Average price reported per Mcf................... $ 1.90 $ 1.82 $ 2.20 Average price realized per Mcf................... $ 1.84 $ 1.80 $ 2.41 Addition/(reduction) to revenue (in millions).... $ 9.4 $ 3.6 $(21.9)
Mark-to-Market Derivatives
As of December 31, 1999 and 1998, the Company has recognized other current liabilities in the accompanying Consolidated Balance Sheets of $15.9 million and $3.4 million, respectively, associated with non-hedge mark-to-market derivatives. The following descriptions provide information pertaining to non-hedge mark-to-market derivatives that the Company was a party to as of December 31, 1999 and 1998. See Note C. "Disclosures About Fair Value of Financial Instruments" for information regarding the Company's determination of the fair values of derivative financial instruments.
Interest rate cap. At December 31, 1998, the Company was party to an interest rate cap agreement with a counterparty which capped the Canadian dollar banker's acceptance rate at 8.00 percent on a notional amount of $80 million Canadian dollars. The agreement expired in August 1999. Under the agreement, the Company paid the counterparty a fixed amount in Canadian dollars on a quarterly basis.
Foreign currency agreements. The Company has a series of forward foreign exchange swap agreements to exchange Canadian dollars for United States dollars at future dates for a fixed amount of the first currency. As of December 31, 1999 and 1998, the United States dollar equivalent of foreign currency exchange swap agreements approximated $72 million and $144 million, respectively. These contracts originated with the Company's acquisition of Chauvco in December 1997. As these contracts do not qualify as hedges, the Company recorded non-cash mark-to- market adjustments to decrease the associated contract liabilities by $5.9 million during 1999 and to increase the associated liabilities by $14.7 million during 1998. These contracts will continue to be marked-to-market until they mature at various dates in the fourth quarter of 2000. The related effects on the Company's results of operations in future periods could be significant.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
BTU swap agreements. During 1996, Mesa entered into BTU swap agreements covering 13,036 MMBtu per day from January 1, 1997 through December 31, 2004. Under the terms of these agreements, the Company received a premium of $.52 per MMBtu over market natural gas prices from January 1, 1997 through December 31, 1998. Additionally, the Company receives 10 percent of the NYMEX oil price for the volumes covered for a six-year period ending December 31, 2004. As these derivative contracts do not qualify as hedges, the Company recorded non-cash mark-to-market adjustments to reduce the carrying value of the BTU swap liability by $.2 million during 1999 and, during 1998 and 1997, to increase the BTU swap liability by $5.8 million and $5.2 million, respectively. These contracts will continue to be marked-to-market at the end of each reporting period during their respective lives. The related effects on the Company's results of operations in future periods could be significant.
Other non-hedge commodity derivatives. During 1999, the Company sold call options that provide the counterparties an option to exercise call provisions on 10,000 barrels per day of oil, at a strike price of $20.00 per barrel, for a twenty-one month period that began on April 1, 1999 and ends on December 31, 2000, or to exercise call provisions over that same time period on 100,000 MMBtu per day of natural gas, at a weighted average strike price of $2.75 per MMBtu. These contracts do not qualify for hedge accounting treatment. Other expenses in the accompanying Consolidated Statement of Operations and Comprehensive Loss for the year ended December 31, 1999 includes $21.2 million of non-cash mark-to-market charges associated with these call options.
NOTE I. Sales to Major Customers
The Company's share of oil and gas production is sold to various purchasers. The Company is of the opinion that the loss of any one purchaser would not have an adverse effect on the ability of the Company to sell its oil and gas production.
The following customers individually accounted for 10 percent or more of the consolidated oil, NGL and gas revenues of the Company during the years ended December 31, 1999, 1998 or 1997:
Percentage of Consolidated Customer Oil, NGL and Gas Revenues -------- --------------------------- 1999 1998 1997 ------ ------ ----- Williams Energy Services................... 11 10 - Genesis Crude Oil, L.P..................... 2 10 23 Mobil Oil Corporation...................... 7 7 16 Western Gas Resources...................... 1 5 10 Producers Energy Marketing, LLC (a)........ - 3 11 - -------------
(a) Producers Energy Marketing, LLC ("ProEnergy") is a natural gas marketing company in which the Company owned a noncontrolling member interest of approximately 10 percent during 1997. Effective January 1, 1998, the Company withdrew as a member of ProEnergy.
At December 31, 1999, the amounts receivable from Williams Energy Services, Genesis Crude Oil, L.P., Mobil Oil Corporation and Western Gas Resources were $15.4 million, $.1 million, $6.0 million and $.1 million, respectively, which are included in the caption "Accounts receivable - trade" in the accompanying Consolidated Balance Sheet.
NOTE J. Other Revenue
During December 1998, the Company announced the sale to a third party of an exclusive and irrevocable option to purchase certain oil and gas properties and other assets of the Company. In consideration for the option, the third
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
party paid a fee of $41.3 million to the Company, consisting of $29.3 million of cash and the third party's common stock that was then valued at $12.0 million. The third party's option lapsed by its terms during the first quarter of 1999. During the second quarter of 1999, the Company entered into a purchase and sale agreement with the third party that was not completed as specified by the terms of the agreement and, as a result thereof, the Company received liquidated damages of additional shares of the third party's common stock valued at $.5 million. During 1999, the Company recognized other revenue of $41. 8 million associated with the transactions described above.
During 1999, the Company received an excise tax refund of $30.2 million. Due to uncertainties surrounding the collectability of this refund, the Company did not recognize it as an asset until it was realized. Accordingly, the Company recognized the tax refund as other revenue during 1999.
NOTE K. Asset Divestitures
During 1999, the Company completed the divestiture of certain assets for net divestment proceeds of $420.5 million (of which $390.5 million were cash proceeds) and recorded an associated net loss on disposition of assets of $24.2 million. The net cash proceeds from the 1999 asset divestitures were used to reduce outstanding indebtedness.
Prize divestiture. On June 29, 1999, the Company completed a sale of certain United States oil and gas producing properties, gas plants and other assets to Prize. The oil and gas producing assets sold to Prize include properties located in the Gulf Coast, Mid Continent and Permian Basin areas of the Company's United States region.
In accordance with the terms of the purchase and sale agreement (the "Prize Divestiture"), the Company received net sales proceeds of $245.0 million, comprised of $215.0 million of cash and 2,307.693 shares of six percent convertible preferred stock having a liquidation preference and fair value of $30.0 million. The convertible preferred stock provides for six percent annual dividend payments, payable quarterly in additional equity shares of Prize through 2001. Subsequent to 2001, Prize has the option of paying the quarterly dividends on the convertible preferred stock in equity shares or cash. Each share of the convertible preferred stock may, at the option of the Company, be converted into one share of Prize common stock, subject to certain anti-dilution adjustments. The Company recognized a loss of $46.4 million from the Prize Divestiture during 1999.
Other United States divestitures. In addition to the Prize Divestiture, the Company completed the divestitures of non-strategic United States oil and gas properties located in the South Texas Gulf Coast, West Texas Permian Basin and North Dakota areas, an East Texas gas facility and certain other assets for net cash proceeds of $116.2 million during 1999. Associated with these divestitures, the Company recorded net gains on divestitures of assets of $31.0 million during 1999.
Canadian divestitures. During 1999, the Company completed the divestitures of certain non-strategic Canadian oil and gas properties, gas plants and other related assets. In accordance with the terms of the Canadian divestitures, the Company received net cash proceeds of $59.3 million, and recognized a net loss of $8.8 million.
NOTE L. Impairment of Long-Lived Assets
Based upon the decline in oil prices that began in the fourth quarter of 1997 and continued through the first quarter of 1999, the Company's outlook for future commodity prices and the Company's assessment of performance issues relative to certain of its oil and gas properties, the Company estimated the expected future cash flows of its oil and gas properties as of December 31, 1998 and 1997, and compared such estimated future cash flows to the respective carrying amounts of the oil and gas properties to determine if the carrying amounts were likely to be recoverable. For those proved oil and gas properties for which the carrying amount exceeded the estimated future cash flows, an impairment was determined to exist; therefore, the Company adjusted the carrying
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
amount of those proved oil and gas properties to their fair value as determined by discounting their expected future cash flows at a discount rate commensurate with the risks involved in the industry. As a result, the Company recognized non-cash impairment provisions of $312.2 million and $1.4 billion related to its proved oil and gas properties during 1998 and 1997, respectively.
Based on the Company's 1999 and 1998 assessments of its unproved properties, the Company recognized non- cash unproved property impairment provisions of $17.9 million and $147.3 million, respectively, during 1999 and 1998.
See Note O for disclosure of these impairment charges by geographic operating segment.
NOTE M. Reorganization
During 1998, the Company announced its plans to sell certain non-strategic oil and gas fields, its intentions to reorganize its operations by combining its six domestic operating regions, and other cost reduction initiatives intended to allow the Company to realize greater operational and administrative efficiences. Specific cost reduction initiatives included the relocation of most of the Company's administrative services from Midland, Texas to Irving, Texas; the closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus Christi, Texas and Houston, Texas; the termination of 350 employees, including several officer positions; and, further centralization of the Company's organization structure. The consolidation of administrative services to Irving and the closing of the Corpus Christi, Texas office were completed in 1998. The Company completed the closings of the Houston, Texas and Oklahoma City, Oklahoma offices during 1999 and further centralized certain operational functions in Irving, Texas. The unpaid employee termination costs as of December 31, 1998 related to employees who were notified of their pending termination prior to December 31, 1998, but were still employed with the Company as of December 31, 1998. The unpaid office closing amounts as of December 31, 1999 and 1998, primarily relate to lease commitments on the office buildings in Oklahoma City, Oklahoma, Corpus Christi, Texas, and Houston, Texas. As a result of the reorganization initiatives, the Company has recognized reorganization charges of $8.5 million and $33.2 million during 1999 and 1998, respectively.
The following table provides a description of the components of the reorganization charges and unpaid portions of the charges as of December 31, 1999 and 1998:
Unpaid Total Portion as of Charges Payments December 31, -------- -------- ------------- (in thousands) 1999: Employee terminations........... $ 3,125 $ 7,805 $ - Relocation...................... 4,998 4,768 230 Office closings................. 340 2,233 1,637 Other........................... 71 71 - ------- ------- ------- $ 8,534 $ 14,877 $ 1,867 ======= ======= ======= 1998: Employee terminations........... $ 22,525 $ 17,845 $ 4,680 Relocation...................... 6,677 6,677 - Office closings................. 3,873 343 3,530 Other........................... 124 124 - ------- ------- ------- $ 33,199 $ 24,989 $ 8,210 ======= ======= =======
NOTE N. Income Taxes
The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state and foreign taxing authorities. Current and estimated tax payments of $800,000; $300,000 and $2.7 million were made in 1999, 1998 and 1997, respectively. In addition, the Company received income tax refunds of $1.4 million and $3.3 million in 1999 and 1998, respectively. During 1999, 1998 and 1997, the Company's income tax provision (benefit) and amounts separately allocated were as follows:
Income tax provision (benefit) attributable to income (loss) before extraordinary item consists of the following:
Year Ended December 31, --------------------------------- 1999 1998 1997 --------- --------- --------- (in thousands) Current: U.S. federal............... $ - $ (3,300) $ 900 State and local............ 400 300 100 Foreign.................... (1,000) - - -------- -------- -------- (600) (3,000) 1,000 -------- -------- -------- Deferred: U.S. federal............... 14,700 123,500 (470,000) State and local............ - (300) (28,500) Foreign.................... (14,700) (104,600) (2,800) -------- -------- -------- - 18,600 (501,300) -------- -------- -------- Total........................ $ (600) $ 15,600 $(500,300) ======== ======== ========
Income (loss) before income taxes and extraordinary item consists of the following: Year Ended December 31, ----------------------------------- 1999 1998 1997 --------- --------- ----------- (in thousands) Income (loss) before income taxes and extraordinary item: U.S. federal........................ $ (23,594) $(393,602) $(1,369,582) Foreign............................. 534 (337,224) (7,981) -------- -------- --------- $ (23,060) $(730,826) $(1,377,563) ======== ======== ==========
Reconciliations of the United States federal statutory rate to the Company's effective rate for income (loss) before extraordinary item are as follows:
1999 1998 1997 ------- ------- -------
U.S. federal statutory tax rate.............. (35.0) (35.0) (35.0) Valuation allowance.......................... 102.0 37.1 - Rate differential on foreign operations...... (68.1) (.5) - Other........................................ (1.3) .5 (1.3) ------- ------ ------- Consolidated effective tax rate.............. (2.4) 2.1 (36.3) ======= ====== =======
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows: December 31, --------------------- 1999 1998 --------- --------- (in thousands) Deferred tax assets: Net operating loss carryforwards................... $ 334,173 $ 291,678 Alternative minimum tax credit carryforwards....... 1,565 1,565 Other.............................................. 78,994 73,260 -------- -------- Total deferred tax assets........................ 414,732 366,503 Valuation allowance................................ (319,900) (271,100) -------- -------- Net deferred tax assets.......................... 94,832 95,403 -------- -------- Deferred tax liabilities: Oil and gas properties, principally due to differences in basis and depletion and the deduction of intangible drilling costs for tax purposes..................................... 38,025 44,058 Other.............................................. 11,107 11,645 -------- -------- Total deferred tax liabilities................... 49,132 55,703 -------- -------- Net deferred tax asset........................... $ 45,700 $ 39,700 ======== ========
Realization of deferred tax assets associated with net operating loss carryforwards ("NOLs") and other credit carryforwards is dependent upon generating sufficient taxable income prior to their expiration. The Company believes that there is a risk that certain of these NOLs and other credit carryforwards may expire unused and, accordingly, has established a valuation allowance of $319.9 million against them. Although realization is not assured for the remaining deferred tax asset, the Company believes it is more likely than not that they will be realized through future taxable earnings or alternative tax planning strategies. However, the net deferred tax assets could be reduced further if the Company's estimate of taxable income in future periods is significantly reduced or alternative tax planning strategies are no longer viable.
Certain subsidiaries that are consolidated for financial reporting purposes are not eligible to be included in the Company's consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. At December 31, 1999, the Company had NOLs for United States, Argentine, Canadian, and South African income tax purposes of $831.4 million, $24.1 million, $69.6 million and $10.5 million, respectively, which are available to offset future regular taxable income in each respective tax jurisdiction, if any. Additionally, at December 31, 1999, the Company has alternative minimum tax net operating loss carryforwards ("AMT NOLs") in the United States of $748.1 million, which are available to reduce future alternative minimum taxable income, if any. These carryforwards expire as follows:
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
The NOLs and AMT NOLs from certain of the United States subsidiaries are subject to various utilization limitations. In total, approximately $34.3 million of the NOLs and $14.8 million of the AMT NOLs are limited in use to specific United States subsidiaries. Section 382 of the Internal Revenue Code provides another limitation to $466.7 million of the Company's United States NOLs and $379.5 million of its AMT NOLS. The Company believes the utilization of $246.7 million of the NOLs and $159.5 million of the AMT NOLs subject to the Section 382 limitation are limited in each taxable year to approximately $104.2 million and the remaining $220 million of the NOLs and AMT NOLs subject to the Section 382 limitation are limited in each taxable year to approximately $20 million.
NOTE O. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the oil and gas exploration and production industry; however, the Company is organizationally structured along geographic operating segments, or regions. Since the merger with Mesa and the acquisition of Chauvco, the Company has had reportable operations in the United States, Argentina and Canada. During 1997, the Company had only minor operations outside the United States.
The following table provides the geographic operating segment data required by Statement of Financial Accounting Standards No. 131, "Disclosure about Segments of an Enterprise and Related Information" ("SFAS 131"), as well as results of operations of oil and gas producing activities required by Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities" ("SFAS 69"). Geographic operating segment income tax benefits (provisions) have been determined based on statutory rates existing in the various tax jurisdictions where the Company has oil and gas producing activities. The "Headquarters and other" table column includes revenues, expenses, additions to properties, plants and equipment, and assets that do not represent revenues, expenses, additions to properties, plants and equipment, or assets of oil and gas producing activities, and that are not routinely included in the earnings measures or attributes internally reported to management on a geographic operating segment basis.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
NOTE P. Loss Per Share
Basic net income (loss) per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. The computation of diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the entity. For 1999, 1998 and 1997, the computation of diluted net loss per share was antidilutive; therefore, the amounts reported for basic and diluted net loss per share were the same.
NOTE Q. Pioneer USA
Pioneer USA is a wholly-owned subsidiary of the Company that has fully and unconditionally guaranteed certain debt securities of the Company (see Note D above). The Company has not prepared financial statements and related disclosures for Pioneer USA under separate cover because management of the Company has determined that such information is not material to investors. In accordance with practices accepted by the United States Securities and Exchange Commission (the "SEC"), the Company has prepared Consolidating Condensed Financial Statements in order to quantify the assets of Pioneer USA as a subsidiary guarantor. The following Consolidating Condensed Balance Sheets as of December 31, 1999 and 1998, and Consolidating Statements of Operations and Comprehensive Loss and Consolidating Condensed Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 present financial information for Pioneer Natural Resources Company as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for Pioneer USA on a stand-alone basis (carrying any investment in non-guarantor subsidiaries under the equity method), financial information for the non- guarantor subsidiaries of the Company on a consolidated basis, the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis, and the financial information for the Company on a consolidated basis. Pioneer USA is not restricted from making distributions to the Company.
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED BALANCE SHEET As of December 31, 1999 (in thousands) ASSETS
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS For the Year Ended December 31, 1999 (in thousands)
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS For the Year Ended December 31, 1997 (in thousands)
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Year Ended December 31, 1999 (in thousands)
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 1999, 1998 and 1997
Capitalized Costs - ----------------- December 31, ----------------------- 1999 1998 ---------- ---------- (in thousands) il and Gas Properties: Proved.............................................. $2,997,335 $3,621,630 Unproved............................................ 257,583 342,589 --------- -------- 3,254,918 3,964,219 Less accumulated depletion.......................... (751,956) (930,111) --------- -------- Net capitalized costs for oil and gas properties.... $2,502,962 $3,034,108 ========= =========
- ---------------
(a) Includes 1998 Chauvco purchase price adjustments of $59.9 million for Argentina and $(99.4) million for Canada. (b) Primarily comprised of South Africa and Gabon geological and geophysical costs. (c) Primarily relates to the drilling of five wells in South Africa. (d) Primarily relates to an unsuccessful well in Guatemala.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 1999, 1998 and 1997
Results of Operations
Information about the Company's results of operations for oil and gas producing activities is presented in Note O to the accompanying Notes to Consolidated Financial Statements.
Reserve Quantity Information
The estimates of the Company's proved oil and gas reserves, which are located principally in the United States, Argentina and Canada are prepared by the Company's engineers. Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. The reserve estimates for 1999, 1998 and 1997 utilize respective oil prices of $24.33, $10.09 and $16.89 per Bbl (reflecting adjustments for oil quality and gathering and transportation costs); respective NGL prices of $17.59, $6.81 and $12.79 per Bbl; and, respective gas prices of $1.83, $1.64 and $2.06 per Mcf (reflecting adjustments for Btu content, gathering and transportation costs and gas processing and shrinkage).
Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 1999, 1998 and 1997
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing discounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 1999, 1998 and 1997
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION Years Ended December 31, 1999, 1998 and 1997
Selected Quarterly Financial Results
Quarter ------------------------------------------ First Second Third Fourth -------- -------- -------- --------- (in thousands, except per share data) Operating revenues............. $147,151 $174,231 $159,855 $ 163,409 Total revenues................. $193,191 $134,744 $213,165 $ 169,035 Costs and expenses............. $195,292 $209,860 $166,137 $ 161,906 Net income (loss).............. $ (2,501) $(74,616) $ 46,428 $ 8,229 Net income (loss) per share.... $ (.02) $ (.74) $ .46 $ .08 Operating revenues............. $197,369 $183,647 $173,462 $ 157,014 Total revenues................. $198,557 $185,107 $178,869 $ 158,966 Costs and expenses............. $238,801 $235,616 $247,071 $ 730,837 Net loss ...................... $(26,844) $(32,809) $(43,902) $(642,871) Net loss per share............. $ (.27) $ (.33) $ (.44) $ (6.41)
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 2000 and is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 2000 and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 2000 and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in response to this item is set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held on May 18, 2000 and is incorporated herein by reference.
PART IV.
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Listing of Financial Statements and Exhibits
Financial Statements
The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and Supplementary Data":
Independent Auditors' Reports Consolidated Balance Sheets as of December 31, 1999 and 1998 Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 1999, 1998 and 1997 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1999, 1998 and 1997 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 Notes to Consolidated Financial Statements Unaudited Supplementary Information
All other statements and schedules for which provision is made in the applicable accounting regulations of the SEC have been omitted because they are not required under related instructions or are inapplicable, or the information is shown in the financial statements and related notes.
Exhibits -------- Exhibit Number Description - ------- -----------
2.1 - Amended and Restated Agreement and Plan of Merger, dated as of April 6, 1997, by and among MESA Inc. ("Mesa"), Mesa Operating Co. ("MOC"), MXP Reincorporation Corp. and Parker & Parsley Petroleum Company ("Parker & Parsley") (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.1 - Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333- 26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.3 - Certificate of Designations of Special Preferred Voting Stock (incorporated by reference to Exhibit 3.3 of the Company's Registration Statement on Form S-3, Registration No. 333-42315, filed with the SEC on December 17, 1997).
3.4 - Terms and Conditions of Exchangeable Shares (incorporated by reference to Annex F to the Definitive Joint Management Information Circular and Proxy Statement of the Company and Chauvco Resources Ltd. ("Chauvco"), File No. 001-13245, filed with the SEC on November 17, 1997).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
4.2 - Form of Certificate of Special Preferred Voting Stock (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
4.3 - Form of Certificate of Exchangeable Shares (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
9.1 - Voting and Exchange Trust Agreement, dated as of December 18, 1997, among the Company, Pioneer Natural Resources (Canada) Ltd. ("Pioneer Canada") and Montreal Trust Company of Canada, as Trustee (incorporated by reference to Exhibit 2.4 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
9.2 - Amended and Restated Shareholders Agreement, dated as of September 3, 1997, by and between the Company and Guy J. Turcotte (incorporated by reference to Exhibit 2.6 to the Company's Registration Statement on Form S-3, Registration No. 333-42315, filed with the SEC on December 15, 1997).
9.3 - Shareholders Agreement, dated as of September 3, 1997, by and among the Company, Trimac Corporation and Gendis Inc. (incorporated by reference to Exhibit 2.4 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on October 2, 1997).
10.1 - Indenture, dated July 2, 1996, among Pioneer USA (formerly MOC), as Issuer, the Company, as Guarantor, and Harris Trust and Savings Bank, as Trustee, relating to the 11-5/8% Senior Subordinated Discount Notes Due 2006 (incorporated by reference to Exhibit 4.17 to Mesa's Quarterly Report on Form 10-Q for the period ended June 30, 1996).
Exhibit Number Description - ------- -----------
10.2 - First Supplemental Indenture, dated as of April 15, 1997, among Pioneer USA (formerly MOC), as Issuer, Mesa, the subsidiary guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.3 - Second Supplemental Indenture, dated as of August 7, 1997, among Pioneer USA (formerly MOC), as Issuer, Mesa, the subsidiary guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.4 - Third Supplemental Indenture, dated as of December 18, 1997, among Pioneer USA, the Subsidiary Guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.12 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997, among Pioneer USA (formerly MOC), a Delaware corporation, the Company, a Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.13 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.6 - Fifth Supplemental Indenture, dated as of December 30, 1997, among Pioneer NewSub1, Inc. (as successor to Pioneer USA), a Texas corporation, the Company, a Delaware corporation, Pioneer DebtCo., Inc., a Texas corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.14 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.7 - Sixth Supplemental Indenture, dated as of December 30, 1997, among Pioneer DebtCo. Inc.(as successor to Pioneer NewSub1, Inc.), a Texas corporation, the Company, a Delaware corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.1 (incorporated by reference to Exhibit 10.15 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.8 - Indenture, dated July 2, 1996, among Pioneer USA (formerly MOC), as Issuer, the Company (Mesa's successor), as Guarantor, and Harris Trust and Savings Bank, as Trustee, relating to the 10-5/8% Senior Subordinated Notes Due 2006 (incorporated by reference to Exhibit 4.18 to Mesa's Quarterly Report on Form 10-Q for the period ended June 30, 1996).
10.9 - First Supplemental Indenture, dated as of April 15, 1997, among Pioneer USA (formerly MOC), as Issuer, Mesa, the Subsidiary Guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.10- Second Supplemental Indenture, dated as of August 7, 1997, among Pioneer USA (formerly MOC), as Issuer, Mesa, the Subsidiary Guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
Exhibit Number Description - ------- -----------
10.11- Third Supplemental Indenture, dated as of December 18, 1997, among Pioneer USA, the Subsidiary Guarantors named therein, the Company, and Harris Trust and Savings Bank, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.12- Fourth Supplemental Indenture, dated as of December 30, 1997, among Pioneer USA, a Delaware corporation, the Company, a Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.13- Fifth Supplemental Indenture, dated as of December 30, 1997, among Pioneer NewSub 1, Inc.(as successor to Pioneer USA), a Texas corporation, the Company, a Delaware corporation, Pioneer DebtCo, Inc, a Texas corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.14- Sixth Supplemental Indenture, dated as of December 30, 1997, among Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc.), a Texas corporation, the Company, a Delaware corporation, and Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with respect to the indenture identified above as Exhibit 10.8 (incorporated by reference to Exhibit 10.9 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.15- Indenture, dated April 12, 1995, between Pioneer USA (successor to Parker & Parsley), and The Chase Manhattan Bank (National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Parker & Parsley's Current Report on Form 8-K, dated April 12, 1995, File No. 001-10695).
10.16- First Supplemental Indenture, dated as of August 7, 1997, among Parker & Parsley, The Chase Manhattan Bank, as Trustee, and Pioneer USA, with respect to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.17- Second Supplemental Indenture, dated as of December 30, 1997, among Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 10.17 to the Company's Current Report on Form 8-K, File No. 001- 13245, filed with the SEC on January 2, 1998).
10.18- Third Supplemental Indenture, dated as of December 30, 1997, among Pioneer New Sub1, Inc.(as successor to Pioneer USA), a Texas corporation, Pioneer DebtCo, Inc., a Texas corporation, and The Chase Manhattan Bank, a New York banking association, as Trustee, with respect to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 10.18 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.19- Fourth Supplemental Indenture, dated as of December 30, 1997, among Pioneer DebtCo, Inc. (assuccessor to Pioneer NewSub1, Inc., as successor to Pioneer USA), a Texas corporation, the Company, a Delaware corporation, Pioneer USA, a Delaware corporation, and The Chase Manhattan Bank, a New York banking association, as trustee, with respect to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 10.19 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
Exhibit Number Description - ------- -----------
10.20- Guarantee, dated as of December 30, 1997, by Pioneer USA relating to the $150,000,000 in aggregate principal amount of 8-7/8% Senior Notes due 2005 and $150,000,000 in aggregate principal amount of 8-1/4% Senior Notes due 2007 issued under the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 10.20 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.21- Form of 8-7/8% Senior Notes Due 2005, dated as of April 12, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated April 12, 1995, establishing the terms of the 8- 7/8% Senior Notes Due 2005 pursuant to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 4.2 to Parker & Parsley's Quarterly Report on Form 10-Q for the period ended June 30, 1995, File No. 001-10695).
10.22- Form of 8-1/4% Senior Notes due 2007, dated as of August 22, 1995, in the aggregate principal amount of $150,000,000, together with Officers' Certificate dated August 22, 1995, establishing the terms of the 8-1/4% Senior Notes due 2007 pursuant to the indenture identified above as Exhibit 10.15 (incorporated by reference to Exhibit 1.2 to Parker & Parsley's Current Report on Form 8-K, dated August 17, 1995, File No. 001-10695).
10.23- Indenture, dated January 13, 1998, between the Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998).
10.24- First Supplemental Indenture, dated as of January 13, 1998, among the Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank of New York, as Trustee, with respect to the indenture identified above as Exhibit 10.23 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998).
10.25- Form of 6.50% Senior Notes Due 2008 of the Company (incorporated by reference to Exhibit 99.3 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998).
10.26- Form of 7.20% Senior Notes Due 2028 of the Company (incorporated by reference to Exhibit 99.4 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14, 1998).
10.27- Guarantee (2008 Notes), dated as of January 13, 1998, entered into by Pioneer USA (incorporated by reference to Exhibit 99.5 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001- 13245, filed with the SEC on January 14, 1998).
10.28- Guarantee (2028 Notes), dated as of January 13, 1998, entered into by Pioneer USA (incorporated by reference to Exhibit 99.6 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 001- 13245, filed with the SEC on January 14, 1998).
10.29- Amended and Restated Credit Facility Agreement (Primary Facility), dated as of December 18, 1997, between the Company, as Borrower, and NationsBank of Texas, N.A., as Administrative Agent, CIBC Inc., as Documentation Agent, Morgan Guaranty Trust Company of New York, as Documentation Agent, and The Chase Manhattan Bank, as Syndication Agent; and the other Co-Agents and lenders named therein (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
Exhibit Number Description - ------- -----------
10.30 - First Amendment to Amended and Restated Credit Facility Agreement (Primary Facility), dated as of June 29, 1998, by and among the Company, as Borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc., as Documentation Agent, Morgan Guaranty Trust Company of New York, as Documentation Agent, The Chase Manhattan Bank, as Syndication Agent, and the Co-Agents and other Lenders signatory thereto (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245).
10.31 - Amended and Restated Credit Facility Agreement (364 Day Facility), dated as of December 18, 1997, between the Company, as Borrower, and NationsBank of Texas, N.A., as Administrative Agent, CIBC Inc., as Documentation Agent, Morgan Guaranty Trust Company of New York, as Documentation Agent, and The Chase Manhattan Bank, as Syndication Agent; and the other Co-Agents and lenders named therein (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.32 - First Amendment to Amended and Restated Credit Facility Agreement (364 Day Facility), dated as of June 29, 1998, by and among the Company, as Borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc., as Documentation Agent, Morgan Guaranty Trust Company of New York, as Documentation Agent, The Chase Manhattan Bank, as Syndication Agent, and the Co-Agents and other Lenders signatory thereto (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245).
10.33 - Credit Agreement, dated as of December 18, 1997, among Chauvco, Canadian Imperial Bank of Commerce, as Agent, and the other Lenders named therein (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.34 - First Amending Agreement, dated June 29, 1998, among Pioneer Natural Resources Canada Inc. (formerly Chauvco), Canadian Imperial Bank of Commerce, and the Lenders thereto, with respect to the Credit Agreement identified above as Exhibit 10.33 (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245).
10.35 - Note, dated December 22, 1997, between the Company, as Borrower, and NationsBank of Texas, N.A., as Lender (incorporated by reference to Exhibit 10.21 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.36H- 1991 Stock Option Plan of Mesa (incorporated by reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for the period ended December 31, 1991).
10.37H- 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit 10.28 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
10.38H- Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991 (incorporated by reference to Exhibit 4.1 to Parker & Parsley's Registration Statement on Form S-8, Registration No. 33-38971).
10.39H- First Amendment to the Parker & Parsley Long-Term Incentive Plan, dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.40H- The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087).
Exhibit Number Description - ------- -----------
10.41H- The Company's Employee Stock Purchase Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35165).
10.42 - Amendment No. 1 to the Company's Employee Stock Purchase Plan, dated December 9, 1998 (incorporated by reference to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-13245).
10.43H- The Company's Deferred Compensation Retirement Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333- 39153).
10.44H- Pioneer USA 401(k) Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-39249).
10.45H- Pioneer USA Matching Plan (incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997, File No. 001-13245).
10.46H- Omnibus Amendment to Nonstatutory Stock Option Agreements, included as part of the Parker & Parsley Long-Term Incentive Plan, dated as of November 16, 1995, between Parker & Parsley and Named Executive Officers identified on Schedule 1 setting forth additional details relating to the Parker & Parsley Long-Term Incentive Plan (incorporated by reference to Parker & Parsley's Annual Report on Form 10-K for the year ended December 31, 1995, File No. 001-10695).
10.47H- Mesa Management Severance Plan, dated April 4, 1997, including a Schedule of Participants on Schedule A for the purpose of defining the payment of certain benefits upon the termination of the officer's employment under certain circumstances (incorporated by reference to Exhibit 10.29 to the Company's Registration Statement on Form S-4, dated June 27, 1997, Registration No. 333-26951).
10.48H- Severance Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements between the Company and each of the other named executive officers identified on Schedule I for the purpose of defining the payment of certain benefits upon the termination of the officer's employment under certain circumstances (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.49H- Indemnification Agreement, dated as of August 8, 1997, between the Company and Scott D. Sheffield, together with a schedule identifying substantially identical agreements the Company and each of the Company's other directors and named executive officers identified on Schedule I (incorporated by reference to Exhibit 10.8 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1997, File No. 001-13245).
10.50 - Purchase and Sale Agreement, dated as of October 22, 1997, between Cometra Energy, L.P., and Pioneer USA (incorporated by reference to Exhibit 10.22 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.51 - Combination Agreement, dated September 3, 1997, between the Company and Chauvco (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on October 2, 1997).
10.52 - Plan of Arrangement, as amended, under Section 186 of the Business Corporations Act (Alberta) (incorporated by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K, File No. 001- 13245, filed with the SEC on January 2, 1998).
Exhibit Number Description - ------- -----------
10.53 - Support Agreement, dated as of December 18, 1997, between the Company and Pioneer Canada (incorporated by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K, File No. 001- 13245, filed with the SEC on January 2, 1998).
10.54 - Stock Purchase Agreement, dated April 26, 1996, between Mesa and DNR (incorporated by reference to Exhibit No. 10 to Mesa's Current Report on Form 8-K filed with the SEC on April 29, 1996).
10.55 - "B" Contract Production Allocation Agreement, dated July 29, 1991, and effective as of January 1, 1991, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (incorporated by reference to Exhibit 10(r) to Mesa's Annual Report on Form 10-K for the period ended December 31, 1991).
10.56 - Amendment to "B" Contract Production Allocation Agreement effective as of January 1, 1993, between Colorado Interstate Gas Company and Mesa Operating Limited Partnership (incorporated by reference to Exhibit 10.24 to Mesa's Registration Statement on Form S-1, Registration No. 33-51909).
10.57 - Amarillo Supply Agreement between Mesa Operating Limited Partnership, Seller, and Energas Company, a division of Atmos Energy Corporation, Buyer, dated effective January 2, 1993 (incorporated by reference to Exhibit 10.14 to Mesa's Annual Report on Form 10-K for the period ended December 31, 1995).
10.58H- Agreement of Partnership of P&P Employees 89-B Conv., L.P. (formerly P&P Employees 89-B GP), dated October 31, 1989, among Parker & Parsley, Ltd. and the Investor Partners (as defined therein, which includes individuals who are directors and executive officers of Parker & Parsley), together with a schedule identifying substantially identical documents and setting forth the material details in which those documents differ from the foregoing document (incorporated by reference to Exhibit 10.50 to Parker & Parsley's Registration Statement on Form S-4, dated December 31, 1990, Registration No. 33-38436).
10.59H- Amendment to Agreement of Partnership of P&P Employees 89-B GP, dated May 31, 1990, among Parker & Parsley, Ltd. and the Investor Partners (as defined therein, which includes individuals who are directors and executives officers of Parker & Parsley), together with a schedule identifying substantially identical documents and setting forth the material details in which those documents differ form the foregoing document (incorporated by reference to Exhibit 10.51 to Parker & Parsley's Registration Statement on Form S-4, dated December 31, 1990, Registration No. 33-38436).
10.60H- Schedule identifying additional documents substantially identical to the Amendment to Agreement of Partnership of P&P Employees 89-B GP included as Exhibit 10.59 and setting forth the material details in which those documents differ from that document (incorporated by reference to Exhibit 10.52 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.61H- Agreement of Partnership of P&P Employees 90 Spraberry Private Development GP, dated October 16, 1990, among Parker & Parsley, Ltd., James D. Moring, and the General Partners (as defined therein, which includes individuals who are directors and executive officers of Parker & Parsley), and form of Amendment to Agreement of Partnership of P&P Employees 90 Spraberry Private Development GP, together with a schedule identifying substantially identical documents and setting forth the material details in which those documents differ from the foregoing document (incorporated by reference to Exhibit 10.52 to Parker & Parsley's Registration Statement on Form S-4, dated December 31, 1990, Registration No. 33- 38436).
Exhibit Number Description - ------- -----------
10.62H- Amendment to Agreement of Partnership of Parker & Parsley 90-A GP, dated February 19, 1991, among Parker & Parsley Development Company and the Investor Partners (as defined therein, which includes individuals who are directors and executive officers of Parker & Parsley), together with a schedule identifying substantially identical documents and setting forth the material details in which those documents differ from the foregoing document (incorporated by reference to Exhibit 10.58 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.63H- Agreement of Partnership of P&P Employees 91-A, GP, dated September 30, 1991, among Parker & Parsley Development Company, James D. Moring, and the General Partners (as defined therein, which includes individuals who are directors and executive officers of Parker & Parsley), together with a schedule identifying substantially identical documents and setting forth the material details in which those documents differ from the foregoing document (incorporated by reference to Exhibit 10.61 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.64H- Amendment to Agreement of Partnership of P&P Employees 90 Spraberry Private Development GP, dated April 22, 1991, among the Partners (as defined therein, which includes individuals who are directors and executive officers of Parker & Parsley) (incorporated by reference to Exhibit 10.67 to Parker & Parsley's Registration Statement on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.65 - Share Purchase Agreement, dated February 13, 1998, among the Company, Trimac Corporation and 761795 Alberta Ltd. (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on February 23, 1998).
10.66 - Share Purchase Agreement, dated February 13, 1998, among the Company, 398215 Alberta Ltd. and Guy J. Turcotte (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 001-13245, filed with the SEC on February 23, 1998).
10.67 - Option to Purchase Agreement, dated December 16, 1998, by and among Costilla Energy, Inc. ("Costilla"), Pioneer USA, and Pioneer Resources Producing, L.P. (incorporated by reference to Exhibit 1 to the Company's statement on Schedule 13D relating to the common stock of Costilla, filed with the SEC on December 22, 1998, File No. 0-21411).
10.68 - Purchase and Sale Agreement, dated December 16, 1998, by and among Costilla, Pioneer USA, and Pioneer Resources Producing, L.P. (incorporated by reference to Exhibit 2 to the Company's statement on Schedule 13D relating to the common stock of Costilla, filed with the SEC on December 22, 1998, File No. 0-21411).
10.69 - Purchase and Sale Agreement, dated May 16, 1999, by and between Pioneer USA and Pioneer Resources Producing, L.P., as Seller, and Prize Energy Corp., as Purchaser (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on July 13, 1999).
10.70 - Second Amended and Restated Credit Facility Agreement (Primary Facility) by and among Pioneer Natural Resources Company, as borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc. as Documentation Agent, Morgan Guarantee Trust Company of New York, as Documentation Agent, Chase Bank of Texas, National Association, as Syndication Agent, The Co-Agents and certain other lenders dated as of March 19, 1999 (incorporated by reference to Exhibit 10.69 to the Company's Annual Report on Form 10-K for the period ended December 31, 1998, File No. 1-13245).
Exhibit Number Description - ------- -----------
10.71 - Second Amended and Restated Credit Facility Agreement (364 Day Facility) by and among Pioneer Natural Resources Company, as borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc. as Documentation Agent, Morgan Guarantee Trust Company of New York, as Documentation Agent, Chase Bank of Texas, National Association, as Syndication Agent, The Co-Agents and certain other lenders dated as of March 19, 1999 (incorporated by reference to Exhibit 10.70 to the Company's Annual Report on Form 10-K for the period ended December 31, 1998, File No. 1-13245).
10.72*- First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998.
10.73*- Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999.
10.74*- Amendment No. 2 to the Company's Employee Stock Purchase Plan, dated December 14, 1999.
10.75 - Voting and Shareholders Agreement dated as of February 8, 2000 between Prize Energy Corp. and its stockholders (incorporated by reference to Exhibit 10.1 to the Company's statement on Schedule 13D relating to the common stock of Prize Energy Corp., filed with the SEC on February 18, 2000, File No. 005-54797).
10.76*- Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000.
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of KPMG LLP.
27.1* - Financial Data Schedule
- ---------------
*Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item 14(c).
(b) Reports on Form 8-K
On December 14, 1999, the Company filed a Current Report on Form 8-K to report, under Items 5. and 7., supplemental information to the Current Report on Form 8-K filed with the SECon July 13, 1999. Specifically, the Company's Current Report on Form 8-K dated December 14, 1999 supplemented the information regarding the disposition of assets and related proforma condensed financial statements and supplemental data provided under Items 2. and 7. of the Company's Current Report on Form 8-K filed with the SEC on July 13, 1999.
(c) Exhibits
The exhibits to this Report required to be filed pursuant to Item 14(c) are listed under "Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - Listing of Financial Statements and Exhibits - Exhibits" above and in the "Index to Exhibits" attached hereto.
(d) Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Report or they are inapplicable.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
PIONEER NATURAL RESOURCES COMPANY
Date: February 29, 2000 By: /s/ Scott D. Sheffield ----------------------------- Scott D. Sheffield, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ----
/s/ Scott D. Sheffield Chairman of the Board, President February 29, 2000 - --------------------------- and Chief Executive Officer Scott D. Sheffield (principal executive officer)
/s/ Timothy L. Dove Executive Vice President and February 29, 2000 - --------------------------- Chief Financial Officer Timothy L. Dove
/s/ Rich Dealy Vice President and Chief February 29, 2000 - --------------------------- Accounting Officer Rich Dealy
/s/ James R. Baroffio Director February 29, 2000 - --------------------------- James R. Baroffio
/s/ R. Hartwell Gardner Director February 29, 2000 - --------------------------- R. Hartwell Gardner
/s/ James L. Houghton Director February 29, 2000 - --------------------------- James L. Houghton
/s/ Jerry P. Jones Director February 29, 2000 - --------------------------- Jerry P. Jones
/s/ Richard E. Rainwater Director February 29, 2000 - --------------------------- Richard E. Rainwater
/s/ Charles E. Ramsey, Jr. Director February 29, 2000 - --------------------------- Charles E. Ramsey, Jr.
/s/ Robert L. Stillwell Director February 29, 2000 - --------------------------- Robert L. Stillwell