-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WVXSgYAwnoYniKrswI/RCFHwP9TUnF+T995mGgCWTuZfaSLpNLtf0VX4l5hxfsWr FLzSB9k5OM6AU9HSmUtZsA== 0000927356-00-000415.txt : 20000315 0000927356-00-000415.hdr.sgml : 20000315 ACCESSION NUMBER: 0000927356-00-000415 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000314 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTERN GAS RESOURCES INC CENTRAL INDEX KEY: 0000856716 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 841127613 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10389 FILM NUMBER: 569373 BUSINESS ADDRESS: STREET 1: 12200 N PECOS ST CITY: DENVER STATE: CO ZIP: 80234-3439 BUSINESS PHONE: 3034525603 MAIL ADDRESS: STREET 1: 12200 NORTH PECOS ST CITY: DENVER STATE: CO ZIP: 80234 10-K 1 FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [X] Annual report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 1999 or [_] Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934 [No Fee Required] for the transition period from _________________ to _________________ Commission file number 1-10389 ------- WESTERN GAS RESOURCES, INC. - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Delaware 84-1127613 - ------------------------------------- ------------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 12200 N. Pecos Street, Denver, Colorado 80234-3439 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) (303) 452-5603 - -------------------------------------------------------------------------------- Registrant's telephone number, including area code No Changes - -------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report)
Title of each class Name of exchange on which registered - ----------------------------- ------------------------------------ Common Stock, $0.10 par value New York Stock Exchange $2.28 Cumulative Preferred Stock, $0.10 par value New York Stock Exchange $2.625 Cumulative Convertible Preferred Stock, $0.10 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No _____ ----- The aggregate market value of voting common stock held by non-affiliates of the registrant on March 1, 2000 was $274,636,297. DOCUMENTS INCORPORATED BY REFERENCE The information required by Part III of this Report (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's proxy statement to be filed pursuant to Regulation 14A with respect to the annual meeting of stockholders scheduled to be held on May 19, 2000. Indicate by check mark if disclosure of delinquent filers to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [_] Western Gas Resources, Inc. Form 10-K Table of Contents
Part Item(s) Page - ---- -------- ---- I. 1 and 2. Business and Properties.............................................. 3 General............................................................ 3 Principal Facilities............................................... 6 Gas Gathering, Processing, Storage and Transmission................ 7 Significant Acquisitions, Projects and Dispositions................ 9 Marketing.......................................................... 11 Producing Properties............................................... 13 Environmental...................................................... 14 Competition........................................................ 15 Regulation......................................................... 15 Employees.......................................................... 16 3. Legal Proceedings.................................................... 16 4. Submission of Matters to a Vote of Security Holders.................. 16 II. 5. Market for Registrant's Common Equity and Related Stockholder Matters 17 6. Selected Financial Data.............................................. 18 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................. 20 8. Financial Statements and Supplementary Data.......................... 30 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................... 62 III. 10. Directors and Executive Officers of the Registrant................... 62 11. Executive Compensation............................................... 62 12. Security Ownership of Certain Beneficial Owners and Management....... 62 13. Certain Relationships and Related Transactions....................... 62 IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 62
2 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES The terms Western, we, us and our as used in this Form 10-K refer to Western Gas Resources, Inc. and its subsidiaries as a consolidated entity, except where it is clear that these terms mean only Western Gas Resources, Inc. General Western gathers, processes, treats, develops and produces, transports and markets natural gas and NGLs. We operate in major gas-producing basins in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. We design, construct, own and operate natural gas gathering systems and processing and treating facilities in order to provide our customers with a broad range of services from the wellhead to the sales delivery point. Our operations are conducted through the following four business segments: .Gathering and Processing--Our operations are in well-established basins such as the Permian, Anadarko, Powder River, Green River and San Juan basins. We connect oil and gas wells to our gathering systems for delivery to our processing or treating plants. At our plants we process natural gas to extract NGLs and we treat natural gas in order to meet pipeline specifications. We provide these services to major oil and gas companies and to various sized independent producers. .Production--We develop and, in limited cases, explore for natural gas, primarily with third-party producers. We participate in exploration and production in order to enhance and support our existing gathering and processing operations. We sell the natural gas that we produce to third parties. Our producing properties are primarily located in the Powder River and Green River basins of Wyoming. .Marketing--We buy and sell natural gas and NGLs in the wholesale market in the United States and in Canada. We provide storage, transportation, scheduling, peaking and other services to our customers. Our customers for these services include utilities, local distribution companies, industrial end-users and other energy marketers. .Transportation--We transport natural gas through our regulated pipelines for producers and energy marketers under fee schedules regulated by state or federal agencies. Historically, we have derived over 95% of our revenues from the sale of gas and NGLs. Our revenues by type of operation are as follows (dollars in thousands):
Year Ended December 31, ---------------------------------------------------------------------------- 1999 % 1998 % 1997 % ---------- ------------ ---------- ------------ ---------- ------------ Sale of gas...................................... $1,501,066 78.6 $1,611,521 76.1 $1,657,479 69.6 Sale of NGLs..................................... 346,819 18.1 449,696 21.3 611,969 25.7 Processing, transportation and storage revenues.. 48,994 2.6 44,743 2.1 40,906 1.7 Sale of electric power........................... - - 20 - 59,477 2.5 Other, net....................................... 13,845 .7 11,108 .5 10,714 5 ---------- ------------ ---------- ------------ ---------- ------------ $1,910,724 100.0 $2,117,088 100.0 $2,380,545 100.0 ========== ========== ========== ========== ========== ============
In order to reduce our overall debt level and provide us with additional liquidity to fund our key growth opportunities, in 1998 we sold our Edgewood processing plant and our interest in the production served by this facility and our Perkins gas gathering and processing facility for an aggregate of $77.8 million. In April 1999, we sold our Katy facility and a portion of the associated natural gas inventory for gross proceeds of $111.7 million and our Giddings facility for gross proceeds of $36.0 million. In June 1999, we sold our MiVida treating facility for gross proceeds of $12.0 million and in December 1999, we sold our Black Lake facility and related reserves for gross proceeds of $7.8 million. As a result of these 1999 sales our total debt was reduced from $504.9 million at December 31, 1998 to $378.3 million at December 31, 1999. 3 Business Strategy Our long-term business plan is to increase our profitability by: (i) optimizing the profitability of existing operations; (ii) entering into additional agreements with third-party producers who dedicate acreage to our gathering and processing operations; and (iii) investing in projects or acquiring assets that complement and extend our core natural gas gathering, processing, production and marketing businesses. Capital expenditures related to existing operations were approximately $81.5 million during 1999. This included approximately $45.8 million related to gathering, processing and pipeline assets and approximately $28.8 million for the acquisition of undeveloped acreage and development of gas reserves in the Powder River basin. Optimize Profitability We continuously seek to improve the profitability of our existing operations by: .increasing natural gas throughput levels through new well connections and expansion of gathering systems. In 1999, we spent approximately $40.5 million on additional well connections and compression and gathering system expansions. We increased throughput levels at our facilities from 895 MMcf/D in 1993 to 1,214 MMcf/D in 1999. .increasing our efficiency through replacing outdated equipment and the consolidation of existing facilities. Replacing and upgrading measurement and compression equipment allows us to minimize maintenance costs, fuel consumption and field operating costs. For example, in 2000 we will begin the replacement of dated compression at our Midkiff facility. This upgrade will result in lower maintenance costs and by decreasing our fuel consumption, will increase the natural gas available for sale. Consolidations allow us to increase the throughput of one facility while reducing the operating costs of the consolidated assets. For example, the acquisition of the remaining 50% interest in the Westana Gathering Company in the first quarter of 2000 will allow us the opportunity to consolidate our operations in Oklahoma and improve our operating efficiencies. .evaluating assets. We routinely review the economic performance of each of our operating facilities to ensure that a targeted rate of return is achieved. If an operating facility is not generating targeted returns we will explore various options, such as consolidation with other Western- owned or third-party-owned facilities, dismantlement, asset swap or outright sale. .controlling operating and overhead expenses. In 1999, largely as a result of asset divestitures, and a subsequent restructuring of our operational and administrative organization, our plant operating and selling and administrative expenses were reduced by approximately $20.0 million as compared to those incurred in 1998. Increase Dedicated Acreage Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather and process natural gas produced on acreage dedicated to us by third parties. We continually seek to obtain production from new wells and newly dedicated acreage in order to replace declines in existing reserves that are dedicated for gathering and processing at our facilities. We have increased our dedicated estimated reserves from 2.3 Tcf at December 31, 1994 to 2.8 Tcf at December 31, 1999. In 1999, including the reserves associated with our joint ventures and partnerships and excluding the reserves associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 142% of throughput. In order to obtain additional dedicated acreage and to secure contracts on favorable terms, we may participate to a limited extent with producers in exploration and production activities. For the same reason, we may also offer to sell an ownership interest in our facilities to selected producers. 4 Expansion of Core Business We will continue to invest in projects that complement and extend our core natural gas gathering, processing, production and marketing businesses. We may also expand our gathering, processing and production operations into new geographic areas. During 1999, the majority of our capital budget was spent in the Powder River basin of Wyoming and in southwest Wyoming. These projects included: .continued development of Powder River basin coal bed methane reserves to increase natural gas production and throughput at our existing gathering and transportation facilities; .completion of the Fort Union gathering pipeline and treater, which will enable us and others to increase gas production in the Powder River basin and connect to major interstate pipelines for transportation; and .continued expansion of our gathering systems and participation in the drilling for additional natural gas reserves in southwest Wyoming. This section, as well as other sections in this Form 10-K, contain forward- looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which can be identified by the use of forward-looking terminology, such as "may," "intend," "will," "expect," "anticipate," "estimate," or "continue" or the negative thereof or other variations thereon or comparable terminology. This Form 10-K contains forward-looking statements regarding the expansion of our gathering operations, our project development schedules, success of our drilling activities, our marketing plans and anticipated volumes through our facilities and from production activities that involve a number of risks and uncertainties, including the composition of gas to be treated and the drilling schedules and success of the producers dedicated to our facilities. In addition to the important factors referred to herein, numerous other factors affecting the gas processing industry generally and in the markets for gas and NGLs in which we operate, could cause actual results to differ materially from our projections in this Form 10-K. See further discussion in "Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements - Note 2 - Summary of Significant Accounting Policies - Use of Estimates and Significant Risks." Our principal offices are located at 12200 North Pecos Street, Denver, Colorado 80234-3439, and our telephone number is (303) 452-5603. Western Gas Resources, Inc. was incorporated in Delaware in 1989. 5 Principal Facilities The following tables provide information concerning our principal facilities at December 31, 1999. We also own and operate several smaller treating, processing and transmission facilities located in the same areas as our other facilities.
Average for the Year Ended December 31, 1999 Gas Gas ----------------------------------------- Gathering Throughput Gas Gas NGL Year Placed System Capacity Throughput Production Production Plant Facilities (1) In Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5) - --------------------------------- ----------- --------- ----------- ----------- ----------- ----------- Texas Bethel Treating (6)............ 1997 86 350 83 79 - Giddings Gathering (14)........ 1979 - - 48 31 66 Gomez Treating................. 1971 385 280 109 101 - Midkiff/Benedum................ 1955 2,140 165 143 92 877 Mitchell Puckett Gathering..... 1972 86 120 115 75 2 MiVida Treating (6)(16)........ 1972 - - 46 44 - Rosita Treating(20)............ 1973 - - 42 - - Louisiana Black Lake (18)................ 1966 - - 11 6 17 Toca (7)(8).................... 1958 - 160 88 83 71 Wyoming Coal Bed Methane Gathering..................... 1990 444 223 122 87 - Fort Union Gas Gathering(17)... 1999 106 450 14 14 - Granger (7)(9)(10)............. 1987 471 235 156 139 285 Hilight Complex (7)............ 1969 626 80 19 14 92 Kitty/Amos Draw (7)............ 1969 313 17 12 8 49 Lincoln Road (10).............. 1988 149 50 24 22 23 Newcastle(7)................... 1981 146 5 2 2 18 Red Desert(7).................. 1979 111 42 17 15 29 Reno Junction (9).............. 1991 - - - - 51 Oklahoma Arkoma......................... 1985 72 8 7 7 - Chaney Dell.................... 1966 2,050 180 60 47 190 Westana (19)................... 1986 845 45 67 57 80 New Mexico San Juan River (6)............. 1955 140 60 26 20 26 Utah Four Corners Gathering......... 1988 104 15 3 4 14 --------- ----------- ----------- ----------- ----------- Total......................... 8,274 2,485 1,214 947 1,890 ========= =========== =========== =========== ===========
Average for the Year Ended December 31, 1999 Interconnect -------------------------- and Pipeline Gas Storage and Year Placed Transmission Capacity Throughput Transmission Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(4) - --------------------------------- ----------- ------------ ----------- ----------- Katy Facility (11) (14).......... 1994 - - 244 MIGC (12)(15).................... 1970 245 130 162 MGTC (13)........................ 1963 252 18 12 ------------ ----------- ----------- Total.......................... 497 148 418 ============ =========== ===========
Footnotes on following page. 6 (1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%); Black Lake (69%); Lincoln Road (72%); Westana Gathering Company (50%); Newcastle (50%) and Fort Union Pipeline (13%). We operate all facilities and all data includes our interests and the interests of other joint interest owners and producers of gas volumes dedicated to the facility. Unless otherwise indicated, all facilities shown in the table are gathering and processing facilities. (2) Gas gathering system miles, interconnect and transmission miles, gas storage capacity and pipeline capacity are as of December 31, 1999. (3) Gas throughput capacity is as of December 31, 1999 and represents capacity in accordance with design specifications unless other constraints exist, including permitting or field compression limits. (4) Aggregate wellhead natural gas volumes collected by a gathering system, aggregate volumes delivered over the header at the Katy Facility or volumes transported by a pipeline. (5) Volumes of gas and NGLs are allocated to a facility when a well is connected to that facility; volumes exclude NGLs fractionated for third parties. (6) Sour gas facility (capable of processing or treating gas containing hydrogen sulfide and/or carbon dioxide). (7) Fractionation facility (capable of fractionating raw NGLs into end-use products). (8) Straddle plant, or a plant located near a transmission pipeline that processes gas dedicated to or gathered by a pipeline company or another third party. (9) NGL production includes conversion of third-party feedstock to iso-butane. (10) We and our joint venture partner at the Lincoln Road facility have agreed to process all gas at our Granger facility so long as there is available capacity at the Granger facility. Accordingly, operations at the Lincoln Road facility have been temporarily suspended since January 1999. (11) Hub and gas storage facility. (12) MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission. (13) MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission. (14) This facility was sold in April 1999. (15) Pipeline capacity represents capacity at the Powder River junction only and does not include northern delivery points. (16) This facility was sold in June 1999. (17) This gathering pipeline and treater became operational during September 1999. (18) This facility and related reserves were under contract for sale at the end of 1999. The transaction closed in January 2000. (19) We acquired the remaining 50% interest in Westana Gathering Company in February 2000. (20) This facility was shut down effective December 31, 1999 and will be dismantled and sold. We expect capital expenditures related to existing operations to be approximately $89.7 million during 2000, consisting of the following: (i) approximately $49.7 million related to gathering, processing and pipeline assets, of which $8.0 million is for maintaining existing facilities and $9.8 million for acquisition of the remaining 50% in the Westana Gathering Company; (ii) approximately $38.0 million related to exploration and production activities; and (iii) approximately $2.0 million for miscellaneous items. Overall, capital expenditures in the Powder River basin coal bed methane development and in southwest Wyoming operations represent 50% and 11%, respectively, of the total 2000 budget. Gas Gathering, Processing, Storage and Transmission Gas Gathering and Processing We contract with producers to gather raw natural gas from individual wells located near our plants or gathering systems. Once we have executed a contract, we connect wells to gathering lines through which the natural gas is delivered to a processing plant or treating facility. At a processing plant, we compress the natural gas, extract raw NGLs and treat the remaining dry gas to meet pipeline quality specifications. Six of our processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane and natural gasoline to obtain a higher value for the NGLs, and two of our plants are able to process and treat natural gas containing hydrogen sulfide or other impurities which require removal prior to transportation. At a treating facility, we treat dry gas, which does not contain liquids that we can economically extract, by removing hydrogen sulfide or carbon dioxide to meet pipeline quality specifications. 7 We acquire dedicated acreage and natural gas supplies in an effort to maintain or increase throughput levels to offset natural production declines. We obtain these natural gas supplies by purchasing existing systems from third parties, by connecting additional wells, through internally developed projects or through joint ventures. Historically, while certain individual plants have experienced declines in dedicated reserves, we have been successful in connecting additional reserves to more than offset the natural declines. There has been a reduction in drilling activity, primarily in basins that produce oil and casinghead gas, from levels that existed in prior years. Overall, the level of drilling will depend upon, among other factors, the prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within our control. We have increased our dedicated estimated reserves from 2.3 Tcf at December 31, 1994 to 2.8 Tcf at December 31, 1999. In 1999, including the reserves associated with our joint ventures and partnerships and excluding the reserves associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 142% of throughput. In order to obtain additional dedicated acreage and to secure contracts on favorable terms, we may participate to a limited extent with producers in exploration and production activities. For the same reason, we may also offer to sell an ownership interest in our facilities to selected producers. Substantially all gas flowing through our gathering, processing and treating facilities is supplied under long-term contracts providing for the purchase, treating or processing of natural gas for periods ranging from five to twenty years, using three basic contract types. Approximately 67% of our plant facilities' gross margins, or revenues at the plants less product purchases, for the year ended December 31, 1999 resulted from percentage-of-proceeds agreements in which we are typically responsible for arranging for the transportation and marketing of the gas and NGLs. We pay producers a specified percentage of the net proceeds received from the sale of the gas and the NGLs. This type of contract permits us and the producers to share proportionally in price changes. Approximately 22% of our plant facilities' gross margins for the year ended December 31, 1999 resulted from contracts that are primarily fee-based whereby we receive a set fee for each Mcf of gas gathered and/or processed. This type of contract provides us with a steady revenue stream that is not dependent on commodity prices, except to the extent that low prices may cause a producer to curtail production. The proportion of fee-based contracts is expected to increase as the volumes from the Powder River basin coal bed methane development and southwest Wyoming increase. See further discussion in "-Significant Acquisitions, Projects and Dispositions." Approximately 11% of our plant facilities' gross margins for the year ended December 31, 1999 resulted from contracts that combine gathering, compression or processing fees with "keepwhole" arrangements or wellhead purchases. Typically, we charge producers a gathering and compression fee based upon volume. In addition, we retain a predetermined percentage of the NGLs recovered by the processing facility and keep the producers whole by returning to the producers at the tailgate of the plant an amount of residue gas equal on a Btu basis to the natural gas received at the plant inlet. The "keepwhole" component of the contracts permits us to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, we are adversely affected when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream. Transportation. We own and operate MIGC, an interstate pipeline located in the Powder River basin in Wyoming, and MGTC, an intrastate pipeline located in northeast Wyoming. MIGC charges a FERC approved tariff and is connected to the Colorado Interstate Gas Pipeline, the Williston Basin Interstate Pipeline, the Pony Express Pipeline, Wyoming Interstate Gas and MGTC. During July 1998, MIGC received approval from the FERC to increase its pipeline capacity from 90 MMcf per day to 130 MMcf per day. See further discussion in "-Significant Acquisitions, Projects and Dispositions," and for a further discussion of the revenue, operating profit and attributable assets of this business segment, see "Item 8-Financial Statements and Supplementary Data." MGTC provides transportation and gas sales at rates that are subject to the approval of the Wyoming Public Service Commission. 8 Significant Acquisitions Projects and Dispositions Our significant acquisitions, projects and dispositions since January 1, 1996 are: Coal Bed Methane. We continue to develop our Powder River basin coal bed methane natural gas gathering system and our coal seam gas reserves in Wyoming. We have acquired drilling rights on approximately 980,000 gross acres, or 466,000 net acres, in the basin. On approximately 18% of this acreage position, we have established proven developed and undeveloped reserves. Our production is derived primarily from wells drilled to depths of 400 to 1,200 feet. Together with our partner, we drilled 583 gross wells, or 274 net wells, in 1999. In 2000, we expect to increase our drilling schedule to approximately 800 gross wells, or 376 net wells, the majority of which are on locations with proven, undeveloped reserves. The average drilling, completion and gathering cost for our coal bed methane wells is approximately $70,000 to $90,000 with reserves per well of approximately 320 MMcf. As deeper wells are drilled, the average cost and reserves per well are expected to increase. Production of coal bed methane from the Powder River basin has been expanding, and approximately 180 MMcf/D of gas volumes in the fourth quarter of 1999 were being produced by several operators in the area, including 110 MMcf/D produced by our partner and us. This compares to 61 MMcf/D produced in January 1998. We transport most of the coal bed methane gas through our MIGC interstate pipeline located in Wyoming, for redelivery to gas markets in the Rocky Mountain and Midwest regions of the United States. Future drilling on federal acreage will be delayed subject to completion of an Environmental Impact Statement. This study is expected to take approximately two years. Our drilling plans for 2000 and 2001 are not expected to be substantially impacted by this study due to our large inventory of non-federal drilling locations. In addition, the Wyoming Department of Environmental Quality is evaluating changes in the standards for surface water discharge and the reclassification of certain drainage areas. These modifications may be approved within the second quarter of 2000 which will allow the issuance of previously requested water permits and expedite the issuance of future water permits. However, we can make no assurance that the conditions under which permits are granted will not impact the level of drilling or the timing of production. Our capital budget in this area provides for expenditures of approximately $45.0 million during 2000. This capital budget includes approximately $34.3 million for drilling costs for our interest in approximately 800 wells, production equipment and undeveloped acreage and $10.7 million for compression. In March 2000, we entered into a ten-year operating lease agreement for the leasing of as many as ten compressors. Depending upon future drilling success, we may need to make additional capital expenditures to continue expansion in this basin. However, because of drilling and other uncertainties beyond our control, we can make no assurance that we will incur this level of capital expenditure or that we will make additional capital expenditures. In each of the years ended December 31, 1999 and 1998, we expended approximately $51.4 million and $46.7 million, respectively, on this project. In October 1997, we sold a 50% undivided interest in our Powder River basin coal bed methane gas operations to Barrett Resources Corporation. This sale provided us with a substantial acreage dedication for gathering and compression services within an area of mutual interest, or AMI, additional man-power resources to accelerate development in this area and more technical expertise in exploration and production. The sale involved producing properties, production equipment and certain undeveloped acreage in this area. The final adjusted purchase price was $17.9 million, resulting in a pre-tax gain of $4.7 million, which was recognized in the fourth quarter of 1997. The AMI with Barrett encompasses approximately 2.1 million acres in the Powder River basin coal bed methane development area. Both parties will continue to develop certain specified areas within the AMI. Barrett became the operator of the producing wells in July 1999. We have committed to gather and compress all gas produced from the jointly-owned properties within the AMI under a long-term fee based agreement. In December 1998, we joined with other industry partners to form Fort Union Gas Gathering, L.L.C., to build a 106-mile long, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River basin in northeast Wyoming. We own an approximate 13% equity interest in Fort Union and are the construction manager and field operator. The new gathering header has a capacity of approximately 450 MMcf/D of natural gas with expansion capability and in February 2000 it had throughput of approximately 100 MMcf/D. The header delivers coal bed methane gas to a treating facility near Glenrock, Wyoming and accesses interstate pipelines serving gas markets in the Rocky Mountain and Midwest regions of the United States. The gathering header and treating system went into service in September 1999 and was project-financed, requiring a cash investment by us of approximately $900,000. In conjunction with the project financing, we also entered into a ten year agreement for firm gathering services on 60 MMcf/D of capacity at $.14 per Mcf on Fort Union beginning in December 1999. 9 Southwest Wyoming. The United States Geologic Survey estimates that the Greater Green River basin contains over 120 Tcf of unrecovered natural gas reserves. Our facilities in southwest Wyoming are comprised of the Granger facility and a 72% ownership interest in the Lincoln Road facility, or collectively the Granger Complex. These facilities have a combined operational capacity of 225 MMcf/D and processed an average of 180 MMcf/D in 1999. Our capital budget in this area provides for expenditures of approximately $9.7 million during 2000. This capital budget includes approximately $3.4 million for drilling costs and production equipment and approximately $6.3 million related to the gathering systems and plant facilities. Because of drilling and other uncertainties beyond our control, we can provide no assurance that we will incur this level of capital expenditure or that we will make future capital expenditures. During the years ended December 31, 1999 and 1998, we expended approximately $12.4 million and $16.0 million, respectively, on this project. In 1997, we entered into an agreement with a producer to participate in exploration and development in the Hoback basin in southwestern Wyoming. Under the agreement, we established a 1.8 million acre AMI, in which we participate in approximately 300,000 gross acres, or approximately 42,000 net acres. Approximately 4,000 gross acres, or approximately 600 net acres have proven reserves. We have also entered into agreements with the producer, or its assigns, for the gathering and processing of natural gas, which may be developed on 16 prospects within the AMI. Through 1999, we participated in 21 gross development wells, or 4 net development wells, in the Jonah field of southwest Wyoming. We also participated in 13 gross exploratory wells, or 4 net exploratory wells, in the Hoback basin. We expect to participate in the drilling of 13 gross wells, or 2 net wells in this area during 2000. The average drilling and completion costs per gross well in this area are approximately $2.2 million and the average well depth in this area approximates 13,000 feet. Additionally, we entered into two separate agreements with an affiliate of the producer to sell an undivided interest in the following assets. Under the first agreement, in February 1998, we sold a 50% undivided interest in a small portion of the Granger gathering system that services the AMI for approximately $4.0 million. This amount approximated our cost in this facility. We expect to install jointly additional gathering assets in this area as needed. Under the second agreement, we granted the same entity the option to purchase up to 50% of the Granger Complex. In conjunction with this agreement, in February 1998, we received a $1 million non-refundable option payment. This option to acquire an interest in these facilities expired in the fourth quarter of 1998. Western Gas Resources-California, Inc. In January 2000, we sold all of the outstanding stock of our wholly-owned subsidiary, Western Gas Resources- California, Inc., or WGR-California, for $14.9 million. The only asset of this subsidiary was a 162 mile pipeline in the Sacramento basin of California. The pipeline was acquired through the exercise of an option by us in a transaction which closed simultaneously with the sale of WGR-California. We will recognize a pre-tax gain on the sale, subject to final accounting adjustment, of approximately $5.5 million in the first quarter of 2000. Bethel Treating Facility. In 1996 and 1997, the Pinnacle Reef exploration area was rapidly developing into a very active lease acquisition and exploratory drilling area using 3-D seismic technology to identify prospects. The initial discoveries indicated a very large potential gas development. Based on our receipt of large acreage dedications in this area, we constructed the Bethel treating facility for a total cost of approximately $102.8 million with a throughput capacity of 350 MMcf/D. In 1998, the production rates from the wells drilled in this field and the recoverable reserves from these properties were far less than the producers originally expected. As a result, in 1999, the Bethel treating facility averaged gas throughput of approximately 83 MMcf/D. Due to the unexpected poor drilling results and reductions in the producers' drilling budgets, the number of rigs actively drilling for Pinnacle Reefs in this area has decreased from 18 in July 1998 to three in December 1999. Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed of," requires the review of long-lived assets whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. SFAS No.121 also requires that an impairment loss be recognized when the carrying amount of an asset exceeds its fair market value or its expected future undiscounted net cash flows. In the fourth quarter of 1998, because of uncertainties related to the pace and success of third-party drilling programs, declines in volumes produced at several wells and other conditions outside our control, we determined that such an evaluation of the Bethel treating facility was necessary. We compared the net book value of the assets to the discounted expected future cash flows of the facility and determined that the results of this comparison required a pre-tax, non-cash impairment charge of $77.8 million. Edgewood. In two transactions which closed in October 1998 we sold our Edgewood gathering system, including our 10 undivided interest in the producing properties associated with this facility, and our 50% interest in the Redman Smackover Joint Venture. The combined sales price was $55.8 million. We used the proceeds from these sales to repay a portion of the balances outstanding under the Revolving Credit Facility. After the accrual of certain related expenses, we recognized a pre-tax gain of approximately $1.6 million during the fourth quarter of 1998. Perkins. In November 1997, we entered into an agreement to sell our Perkins facility. In March 1998, we completed the sale of this facility, with an effective date of January 1, 1998. The sales price was $22.0 million and resulted in a pre-tax gain of approximately $14.9 million. Giddings. In April 1999, we sold our Giddings facility for gross proceeds of $36.0 million, which resulted in an approximate pre-tax loss of $6.6 million in the second quarter of 1999. Katy. We continue to view access to storage capacity as a significant element of our marketing strategy. However, as a result of an increase in third-party storage services available in the marketplace combined with our 1999 business plan objective of improving our balance sheet, in April 1999 we sold all the outstanding common stock of our wholly owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds of $100.0 million. This transaction resulted in an approximate pre-tax loss of $17.7 million, in 1999. The only asset of this subsidiary was the Katy facility. In April 1999, we also sold 5.1 Bcf of stored gas in the Katy facility for total sales proceeds of $11.7 million, which approximated our cost of the inventory. To meet the needs of our marketing operations, we will continue to contract for storage capacity. Accordingly, we entered into a long-term agreement with the purchaser for approximately 3 Bcf of storage capacity at market rates. MiVida. In June 1999, we sold our MiVida treating facility for gross proceeds of $12.0 million. This transaction resulted in an approximate pre-tax gain of $1.2 million. Black Lake. In December 1999, we signed an agreement for the sale of our Black Lake facility and related reserves for gross proceeds of $7.8 million, subject to final accounting adjustment. This sale closed in January 2000. This transaction resulted in an approximate pre-tax loss of $7.3 million which was accrued in the fourth quarter of 1999. Westana. In February 2000, we acquired the remaining 50% interest in this partnership for a gross purchase price of $10.8 million. This transaction is effective January 1, 2000 and is subject to final accounting adjustment. Other. We routinely review the economic performance of each of our operating facilities to ensure that a targeted rate of return is achieved. If an operating facility is not generating targeted returns we will explore various options, such as consolidation with other Western-owned or third party-owned facilities, dismantlement, asset swap or outright sale. Marketing Gas. We market gas produced at our plants and purchased from third parties to end-users, local distribution companies, or LDCs, pipelines and other marketing companies throughout the United States and in Canada. Historically, our gas marketing was an outgrowth of our gas processing activities and was directed towards selling gas processed at our plants to ensure their efficient operation. As we expanded into new basins and the natural gas industry became deregulated and offered more opportunity, we began to increase our third-party gas marketing. For the year ended December 31, 1999, our gas sales volumes averaged 1.9 Bcf/D. Third-party sales and gas storage, combined with the stable supply of gas from our facilities, enable us to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods. We sell gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Most of our current sales contracts range from a few days to two years. During 1997, we created a wholly owned subsidiary to operate a marketing office in Calgary, Alberta. The Calgary office markets third party gas volumes in Canada, provides us with information regarding gas supplies being transported from Canada and establishes a presence in an evolving gas market. In general, we do not expect to increase our third-party sales volumes in 2000 significantly from levels achieved during the year ended December 31, 1999. Our 2000 gas marketing plan emphasizes growth through our asset base and storage and transportation capacities which we control. 11 We continue to view access to storage capacity as a significant element of our marketing strategy. We customarily store gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and for resale during periods when prices are favorable. As of December 31, 1999, we had contracts in place for approximately 29.3 Bcf of storage capacity for resale during periods when prices are favorable. The fees associated with these contracts currently do not exceed $.61 per Mcf and the associated contract periods range from two months to six years. As of December 31, 1999, we also had contracts for approximately 606 MMcf/D of firm transportation; approximately 30% of which expire during 2000. The fees associated with these contracts do not exceed $.50 per Mcf, and the associated contract periods range from ten months to twelve years. Several of these long-term storage and firm transportation contracts require an annual renewal. In addition, some contracts contain provisions requiring us to pay the fees associated with these contracts whether or not the service is used. We held gas in storage and in imbalances at various facilities of approximately 13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999 compared to 19.9 Bcf at an average cost of $2.13 per Mcf at December 31,1998. At December 31, 1999, we had hedging contracts in place for anticipated sales of approximately 18.6 Bcf of stored gas at a weighted average price of $2.41 per Mcf for the stored inventory. See further discussion in "--Significant Acquisitions, Projects and Dispositions--Katy" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources--Risk Management Activities." During the year ended December 31, 1999, we sold gas to approximately 351 end- users, pipelines, LDCs and other customers. No single gas customer accounted for more than 4% of consolidated revenues for the year ended December 31, 1999. NGLs. We market NGLs, or ethane, propane, iso-butane, normal butane, natural gasoline and condensate, produced at our plants and purchased from third parties, in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. A majority of our production of NGLs moves to the Gulf Coast area, which is the largest NGL market in the United States. Through the development of end-use markets and distribution capabilities, we seek to ensure that products from our plants move on a reliable basis, avoiding curtailment of production. For the year ended December 31,1999, NGL sales averaged 2,885 MGal/D. Consumers of NGLs are primarily the petrochemical industry, the petroleum refining industry and the retail and industrial fuel markets. As an example, the petrochemical industry uses ethane, propane, normal butane and natural gasoline as feedstocks in the production of ethylene, which is used in the production of various plastics products. Over the last several years, the petrochemical industry has increased its use of NGLs as a major feedstock and is projected to continue to increase such usage. Further, consumers use propane for home heating, transportation and for agricultural applications. Price, seasonality and the economy primarily affect the demand for NGLs. We decreased sales to third parties by approximately 1,325 MGal/D for the year ended December 31, 1999 compared to 1998. In general, we do not anticipate that sales to third parties in 2000 will vary significantly from those experienced in 1999. Our NGL marketing plan contemplates: (i) continued growth in sales to end- users without increasing total sales volume; (ii) maximizing profitability on volumes produced at our facilities; and (iii) efficient use of various third- party storage facilities to increase profitability while limiting carrying risk. We lease NGL storage space at major trading locations, primarily near Houston and in central Kansas, in order to store products for resale during periods when prices are favorable and to facilitate the distribution of products. In addition, as of December 31, 1999, we had contracts in place for approximately 26,250 MGal of storage capacity. The base fees associated with those contracts currently do not exceed $.02 per gallon and the associated contract periods range from two months to three years. Several of the long-term contracts require an annual renewal and contain provisions requiring us to pay the fees associated with such contracts whether or not the service is used. We held NGLs in storage of 8,600 MGal, consisting primarily of propane and normal butane, at an average cost of $.34 per gallon and 16,900 MGal, consisting primarily of propane and normal butane, at an average cost of $.24 per gallon at December 31, 1999 and 1998, respectively, at various third-party storage facilities. At December 31, 1999, we had no significant hedging contracts in place for anticipated sales of stored NGLs. 12 NGL sales were made to approximately 132 different customers for the year ended December 31, 1999. One customer accounted for approximately 19% of our consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue, for the year ended December 31, 1999. This customer is a large integrated utility. We also derive revenues from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 1999, these fees were less than 1% of our consolidated revenues. Power Marketing. In July 1996, the FERC issued its final order requiring investor-owned electric utilities to provide open access for wholesale transmission. This action allowed companies to participate in a market previously controlled by electric utilities. During 1996 and 1997, we traded electric power in the wholesale market and entered into transactions that arbitrage the value of gas and electric power. During the second half of 1997, we elected to discontinue wholesale trading of electric power, due to a lack of profitability. Producing Properties Primarily to secure additional gas supply for our facilities, we selectively participate in exploration and production activities. Beginning in 1997, we substantially increased our investment in the acquisition of undeveloped acreage and development of the Powder River coal bed methane and during 1999 we invested $28.8 million in this project. This play has now developed into one of our most significant long-term holdings. See "Business--Significant Acquisitions, Projects and Dispositions--Coal Bed Methane" and "--Southwest Wyoming." Revenues derived from our producing properties comprised approximately 1.7%, 1.3% and 1.3% of consolidated revenues for the years ended December 31, 1999, 1998 and 1997, respectively. As a result of the increased investment in the Powder River coal bed methane, we expect the revenues derived from our producing properties to continue to increase. We will also consider investing in other exploration and production prospects that we consider to be low risk and complementary to our gathering and processing business. The following table provides a summary of our net annual production volumes:
December 31, ------------------------------------------------- 1999 1998 1997 --------------- --------------- --------------- Gas Oil Gas Oil Gas Oil State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) - -------------------- ------- ------ ------- ------ ------- ------ Colorado............ 332 3 274 2 243 6 Louisiana (1)....... 2,270 64 2,810 75 4,760 108 Texas (1)........... 62 4 1,787 5 6,092 21 Wyoming: Coal Bed Methane.. 12,766 - 7,136 - 1,751 - All Other......... 2,558 41 3,283 40 1,752 19 ------ --- ------ --- ------ --- Total............... 17,988 112 15,290 122 14,598 154 ====== === ====== === ====== ===
(1) We sold our producing properties in Louisiana during 1999 and our producing properties in Texas during 1998. 13 The following table provides a summary of our proved developed and proved undeveloped net reserves:
December 31, ---------------------------------------------------- 1999 1998 1997 ---------------- ---------------- ---------------- Gas Oil Gas Oil Gas Oil State/Basin (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) - -------------------- -------- ------ -------- ------ -------- ------ Colorado............ 6,452 40 2,278 8 1,185 5 Louisiana (1)....... - - 10,234 190 30,615 485 Texas (1)........... - - - - 45,370 - Wyoming: Coal Bed Methane.. 236,277 - 193,010 - 126,812 - All Other......... 29,089 289 33,408 359 18,833 317 ------- --- ------- --- ------- --- Total............... 271,818 329 238,930 557 222,815 807 ======= === ======= === ======= ===
(1) We sold our producing properties in Louisiana during 1999 and our producing properties in Texas during 1998. As a result of a review of the reserves at our Black Lake facility, and by comparing the net book value of the assets to the undiscounted expected future cash flows, which management determined by applying future prices estimated over the lives of the associated reserves, we wrote down the Black Lake reserves and the processing facility associated with such reserves in accordance with SFAS No. 121 to the net present value of expected cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. Accordingly, we recognized a pre-tax, non-cash loss of $28.8 million for the year ended December 31, 1998. In addition, we recognized a pre-tax, non-cash loss on the impairment of property and equipment, primarily related to our Black Lake facility and Sand Wash basin assets, of $34.6 million for the year ended December 31, 1997. We employ a total staff of eight full time reservoir and production engineers and geologists who complete annual reserve estimates of dedicated reserves behind each of our existing facilities. The reserve report for the Powder River coal bed methane for 1999 has been audited by Netherland, Sewell & Associates, Inc. Our reserve 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 these estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve estimates are imprecise and should be expected to change as additional information becomes available. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of those reserves are based upon certain assumptions about production levels, prices and costs, which may not be correct. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. Our estimates of reserves dedicated to our gathering and processing facilities are calculated by our reservoir engineering staff and are based on publicly available data. These estimates may be less reliable than the reserve estimates made for our own producing properties since the data available for estimates of our own producing properties also includes our proprietary data. Environmental The construction and operation of our gathering systems, plants and other facilities used for the gathering, transporting, processing, treating or storing of gas and NGLs are subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at our facilities or at facilities to which we send wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. We employ four environmental engineers, five safety specialists and three regulatory compliance specialists to monitor environmental and safety compliance at our facilities. Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In addition, on an ongoing basis, the environmental engineers perform environmental assessments of our existing facilities. We believe that we are in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities. We believe that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on our financial position or results of operations. 14 The Texas Natural Resource Conservation Commission which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to the Commission regarding a voluntary emissions reduction plan for the permitting of existing "grandfathered" air emissions sources within the State of Texas. A "grandfathered" air emissions source is one that does not need a state operating permit because it was constructed prior to 1971. We operate a number of these sources within the State of Texas, including portions of our Midkiff plant and many of our compressors. The recommendations proposed by the committee would create a voluntary permitting program for grandfathered sources, including incentives to participate, like the ability to operate these sources in a flexible manner. It is not clear which of the committee's recommendations, if any, that the Commission will implement and it is not possible to assess the potential effect on us until final regulations are issued. We anticipate that it is reasonably likely that the trend in environmental legislation and regulation will continue to be towards stricter standards. We are unaware of future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility. We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $2.6 million for the year ended December 31, 1999, including approximately $500,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material effect on our financial position or results of operations. Competition We compete with other companies in the gathering, processing, treating and marketing businesses both for supplies of natural gas and for customers for our natural gas and NGLs, and for the acquisition of leaseholds. Competition for natural gas supplies is primarily based on efficiency, reliability, availability of transportation and ability to obtain a satisfactory price for the producers' natural gas. Competition for sales customers is primarily based upon reliability and price of deliverable natural gas and NGLs. Our competitors for obtaining additional gas supplies, for gathering and processing gas and for marketing gas and NGLs include national and local gas gatherers, brokers, marketers and distributors of various sizes and experience. The majority of these competitors have much larger financial resources than us. For customers that have the capability of using alternative fuels, such as oil and coal, we also compete based primarily on price against companies capable of providing such alternative fuels. Our competitors for obtaining leaseholds include major and large independent oil companies with knowledgeable technical staffs as well as smaller independent oil companies and brokers. We have experienced narrowing margins related to third-party sales due to the increasing availability of pricing information in the natural gas industry. Suppliers in our gas marketing transactions may require additional security such as letters of credit that are not required of certain of our competitors. If the additional security is required, our marketing margins and volumes would be adversely impacted. Regulation Our purchase and sale of natural gas and the fees we receive for gathering and processing have generally not been subject to regulation and, therefore, except as constrained by competitive factors, we have considerable pricing flexibility. However, many aspects of our gathering, processing, marketing and transportation of natural gas and NGLs are subject to federal, state and local laws and regulations which can have a significant impact upon our overall operations. As a processor and marketer of natural gas, we depend on the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of our own gas supplies as well as those we process and/or market for others. Both the interstate pipelines' performance of transportation and storage services, and the rates charged for such services, are subject to the jurisdiction of the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. At times, other system users can pre- empt the availability of interstate transportation and storage services necessary to enable us to make deliveries and/or sales of gas in accordance with FERC-approved methods for allocating the system capacity of open access pipelines. Moreover, the rates the pipelines charge for such services are often subject to negotiation between shippers and the pipelines within certain FERC- established parameters and will periodically vary depending upon individual system usage and other factors. An inability to obtain transportation and/or storage services at competitive rates can hinder our processing and marketing operations and/or adversely affect our sales margins. 15 Generally, neither the FERC nor any state agency regulates gathering and processing prices. The Oklahoma Corporation Commission, or the OCC, has limited authority in certain circumstances, after the filing of a complaint by a producer, to compel a gas gatherer to provide open access gathering and to set aside unduly discriminatory gathering fees. The Oklahoma state legislature is considering legislation that would expand the authority of the OCC to compel a gas gatherer to provide open access gas gathering and to establish rates, terms and conditions of services which a gas gatherer provides. In addition, the state legislatures and regulators in other states in which we gather gas are also contemplating additional regulation of gas gathering. We do not believe that any of the proposed legislation of which we are aware is likely to have a material adverse effect on our financial position or results of operation. However, we cannot predict what additional legislation or regulations the states may adopt regarding gas gathering. Employees At December 31, 1999, we employed approximately 646 full-time employees, none of whom was a union member. We consider relations with employees to be excellent. ITEM 3. LEGAL PROCEEDINGS Reference is made to Note 8 of our Consolidated Financial Statements in Item 8 of this Form 10-K. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the quarter ended December 31, 1999. 16 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS As of March 1, 2000, there were 32,166,247 shares of Common Stock outstanding held by 281 holders of record. The Common Stock is traded on the New York Stock Exchange under the symbol "WGR." The following table sets forth quarterly high and low sales prices as reported by the NYSE Composite Tape for the quarterly periods indicated.
HIGH LOW ------- ------- 1999 Fourth Quarter.............. $18 3/4 $10 7/8 Third Quarter............... 19 3/4 15 1/8 Second Quarter.............. 17 7/8 7 1/2 First Quarter............... 7 5/8 3 7/8 1998 Fourth Quarter.............. 9 7/8 5 5/16 Third Quarter............... 15 1/8 8 Second Quarter.............. 19 5/8 13 7/8 First Quarter............... $22 1/8 $15 7/8
We paid annual dividends on our Common Stock aggregating $.20 per share during the years ended December 31, 1999 and 1998. We have declared a dividend of $.05 per share of Common Stock for the quarter ending March 31, 2000 to holders of record as of March 31, 2000. Declarations of dividends on our Common Stock are within the discretion of the Board of Directors. In addition, our ability to pay dividends on our Common Stock is restricted by certain covenants in our financing facilities, the most restrictive of which prohibits declaring or paying dividends that exceed, in the aggregate the sum of $20 million plus 50% of our consolidated net operating income (as defined in the subordinated note indenture) earned after July 1, 1999 (or minus 100% if a net loss) plus the aggregate net cash proceeds received after July 1, 1999 from the sale of any stock. At December 31, 1999, availability under this covenant was approximately $12.0 million. 17 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected consolidated historical financial and operating data for Western. Certain prior year amounts have been reclassified to conform to the presentation used in 1999. The data for the three years ended December 31, 1999, 1998 and 1997 should be read in conjunction with our Consolidated Financial Statements and the notes thereto included elsewhere in this Form 10-K. The selected consolidated financial data for the years ended December 31, 1996 and 1995 is derived from our audited historical Consolidated Financial Statements. See also Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Year Ended December 31, -------------------------------------------------------------------------- 1999 1998 1997 1996 1995 ---------- ---------- ---------- ---------- ---------- (000s, except per share amounts and operating data) Statement of Operations: Revenues.................... $1,910,724 $2,117,088 $2,380,545 $2,088,262 $1,697,046 Gross profit (a)............ 37,487 66,568 93,755 105,479 75,211 Income (loss) before income taxes..................... (25,184)(b) (105,623)(b) 2,220 (b) 41,631 (8,266)(c) Provision (benefit) for income taxes.............. (9,167) (38,418) 733 13,690 (2,158) Income (loss) before extraordinary items....... (16,017)(b) (67,205)(b) 1,487 (b) 27,941 (6,108)(c) Extraordinary charge for early extinguishment of debt...................... (1,107)(d) - - - - Net income (loss)........... (17,124)(b) (67,205)(b) 1,487 (b) 27,941 (6,108)(c) Earnings (loss) per share of common stock.............. (.86) (2.42) (.28) .66 (.84) Earnings (loss) per share of common stock - assuming dilution.................. (.86) (2.42) (.28) .66 (.84) Other financial data: Net cash provided by operating activities...... 95,184 (35,570) 114,755 168,266 86,373 EBITDA, as adjusted(e)...... 89,913 79,291 118,404 137,233 115,141 Capital expenditures........ 81,489 105,216 198,901 74,555 78,521 Balance Sheet Data (at year end): Total assets................ 1,049,486 1,219,377 1,348,276 1,361,631 1,193,997 Long-term debt.............. 378,250 504,881 441,357 379,500 529,500 Stockholders' equity........ 349,743 385,216 468,112 480,467 371,909 Dividends on preferred stock..................... 10,439 10,439 10,439 10,439 15,431 Dividends on common stock... 6,426 6,430 6,427 5,472 5,153 Operating Data: Average gas sales (MMcf/D).. 1,900 2,200 1,975 1,794 1,572 Average NGL sales (MGal/D).. 2,885 4,730 4,585 3,744 2,890 Average gas volumes gathered (MMcf/D).......... 1,214 1,162 1,229 1,171 1,020 Facility capacity (MMcf/D).. 2,485 2,237 2,302 1,940 1,907 Average gas prices ($/Mcf).. $ 2.17 $ 2.01 $ 2.30 $ 2.19 $ 1.53 Average NGL prices ($/Gal).. $ .33 $ .26 $ .36 $ .41 $ .31
(a) Excludes selling and administrative, interest, restructuring and income tax expenses, expenses for the impairment of property and equipment and any extraordinary items. See further discussion in notes (b), (c) and (d). (b) Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," or SFAS No. 121, requires that an impairment loss be recognized when the 18 carrying amount of an asset exceeds its fair market value or the expected future undiscounted net cash flows. In accordance with SFAS No. 121, we recognized a pre-tax, non-cash loss on the impairment of property and equipment of $1.2 million, or $0.7 million after-tax, and $108.5 million, or $69.0 million after-tax, and $34.6 million or $22.0 million after-tax for the years ended December 31, 1999, 1998 and 1997, respectively. (c) In accordance with SFAS No. 121, we recognized a pre-tax, non-cash loss for the year ended December 31, 1995 on the impairment of property and equipment of $17.6 million, or $12.4 million after-tax. Also, we implemented a cost reduction program to reduce operating and selling and administrative expenses. As a result of this program, a $2.1 million pre-tax, or $1.3 million after-tax, restructuring charge was incurred, primarily related to employee severance costs. (d) We recognized an extraordinary loss on the early extinguishment of long-term debt in the second quarter of 1999 of $1.8 million pre-tax, or $1.1 million after-tax, primarily related to the prepayment of indebtedness with the proceeds of the subordinated debt offering. (e) Reflects income before interest expense, income taxes, depreciation, depletion and amortization, $1.2 million, $108.5 million, $34.6 million and $17.6 million of non-cash impairment losses related to certain oil and gas assets and plant facilities in the fourth quarter of 1999, 1998, 1997 and 1995, respectively, in connection with SFAS No. 121, (gains) or losses on sales of assets of $29.8 million, $16.5 million, $4.7 million, $2.0 million, $(1.2) million for each of the years ended December 31, 1999, 1998, 1997, 1996, 1995, respectively and a $1.1 million after-tax charge for loss on the early extinguishment of long-term debt in the second quarter of 1999. This data does not purport to reflect any measure of operations or cash flow. EBITDA is not a measure determined pursuant to generally accepted accounting principles, or GAAP, nor is it an alternative to GAAP income. 19 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis relates to factors that have affected our consolidated financial condition and results of operations for the three years ended December 31, 1999, 1998 and 1997. Certain prior year amounts have been reclassified to conform to the presentation used in 1999. Reference should also be made to our Consolidated Financial Statements and related Notes thereto and the Selected Financial Data included elsewhere in this Form 10-K. Results of Operations Year ended December 31, 1999 compared to year ended December 31, 1998 (000s, except per share amounts and operating data)
Year Ended December 31, ----------------------- Percent 1999 1998 Change ----------- ---------- ------- Financial results: Revenues............................................. $1,910,724 $2,117,088 (10) Gross profit......................................... 37,487 66,568 (44) Net loss............................................. (17,124) (67,205) 75 Loss per share of common stock - basic and diluted... (.86) (2.42) 64 Net cash provided by (used in) operating activities.. $ 95,184 $ (35,570) - Operating data: Average gas sales (MMcf/D)........................... 1,900 2,200 (14) Average NGL sales (MGal/D)........................... 2,885 4,730 (39) Average gas prices ($/Mcf)........................... $ 2.17 $ 2.01 8 Average NGL prices ($/Gal)........................... $ .33 $ .26 27
Overall, the net loss decreased $50.1 million for the year ended December 31, 1999 compared to 1998. The decrease in net loss for the year was primarily due to a 1998 $69.0 million, after-tax, charge for impairment recorded in 1998 in connection with the evaluation of a decrease in product prices and the impact on our Bethel, Black Lake and Sand Dunes facilities, as required by SFAS No. 121. Revenues from the sale of gas decreased approximately $110.5 million for the year ended December 31, 1999 compared to 1998. Average gas sales volumes decreased 300 MMcf per day to 1,900 MMcf per day for the year ended December 31, 1999 compared to 1998, primarily due to an decrease in third party sales activity. The decrease in volumes sold was partially offset by an increase in average gas prices. Our average gas price increased $.16 per Mcf to $2.17 per Mcf for the year ended December 31, 1999 compared to 1998. Included in this gas price is approximately $4.1 million of loss recognized in the year ended December 31, 1999 related to futures positions on equity volumes. We have entered into futures positions for a portion of our equity gas for 2000. See further discussion in "-Liquidity and Capital Resources - Risk Management." Revenues from the sale of NGLs decreased approximately $102.9 million for the year ended December 31, 1999 compared to 1998. Average NGL sales volumes decreased 1,845 MGal per day to 2,885 MGal per day for the year ended December 31, 1999 compared to 1998, due to a decrease in third party sales activity of 1,325 MGal per day and a decrease in plant sales volumes of 520 MGal per day. Plant NGL sales volumes were largely affected by increased volumes taken in kind and curtailed drilling activity due to low oil prices by a producer behind Midkiff, and the sale of our Edgewood and Giddings facilities. Volumes taken in kind affect sales volumes and revenues but do not materially affect income. The decrease in sales volumes was partially offset by an increase in average NGL prices. Our average NGL price increased $.07 per gallon to $.33 per gallon for the year ended December 31, 1999 compared to 1998. Included in this NGL price was approximately $6.6 million of loss recognized in the year ended December 31, 1999 related to futures positions on equity volumes. We have entered into futures positions for a portion of our equity production for 2000. See further discussion in "-Liquidity and Capital Resources - Risk Management." 20 Processing, transportation and storage revenue increased approximately $4.3 million for the year ended December 31,1999 compared to 1998 due to increased volumes transported by our MIGC pipeline resulting from the activity in the Powder River basin. The reduction in product purchases of $198.5 million to $1.7 billion for the year ended December 31, 1999 compared to 1998, was primarily due to a decrease in product prices. Overall, combined product purchases as a percentage of sales of all products remained constant at 93% for the year ended December 31, 1999 compared to 1998. Our margins on third-party sales of natural gas have narrowed from $.03 per Mcf in 1997 to $.01 per Mcf in 1999. This decrease is partially due to increasing competitiveness in the marketplace. Contributing to this decrease in 1999 was the sale of our Katy storage facility in April 1999. This facility generated higher margins per Mcf as we were able to capture the summer/winter price differential on our storage position. We expect marketing margins to remain at the $.01 per Mcf level in 2000. Plant operating expense decreased approximately $17.9 million for the year ended December 31, 1999 compared to 1998. The decrease was primarily due to the reorganization of our operating areas as a result of the sales of the Giddings, MiVida, and Katy facilities during 1999. Depreciation, depletion and amortization decreased approximately $8.4 million for the year ended December 31, 1999 compared to 1998. The decrease was primarily due to the sales of the Giddings, MiVida, and Katy facilities during 1999 and impairment charges recognized against our Bethel and Black Lake facilities in 1998 and 1997. Interest expense decreased $.5 million for the year ended December 31, 1999 compared to 1998. The decrease is the result of an overall reduction in long- term debt of $126.6 million with the proceeds from our asset sales in 1999. The resulting decrease in interest expense was partially offset by higher interest rates on our Senior Debt facilities and on the Senior Subordinated Debt. In connection with the repayments on the Senior Debt, we incurred approximately $1.8 million of pre-tax yield maintenance and other charges. These charges are reflected as an extraordinary loss from early extinguishment of long-term debt in the second quarter of 1999. Year ended December 31, 1998 compared to year ended December 31, 1997 (000s, except per share amounts and operating data)
Year Ended December 31, ------------------------ Percent 1998 1997 Change ----------- ----------- ------- Financial results: Revenues............................................. $2,117,088 $2,385,260 (11) Gross profit......................................... 66,568 93,775 (29) Net income (loss).................................... (67,205) 1,487 - Loss per share of common stock - basic and diluted... (2.42) (.28) (764) Net cash provided by (used in) operating activities.. $ (35,570) $ 114,755 - Operating data: Average gas sales (MMcf/D)........................... 2,200 1,975 11 Average NGL sales (MGal/D)........................... 4,730 4,585 3 Average gas prices ($/Mcf)........................... $ 2.01 $ 2.30 (137) Average NGL prices ($/Gal)........................... $ .26 $ .36 (28)
Net income decreased $68.7 million for the year ended December 31, 1998 compared to 1997. The decrease in net income for the year was primarily due to a $69.0 million, after-tax, charge for impairment recorded in connection with the evaluation of a decrease in product prices and the impact on our Bethel, Black Lake and Sand Dunes facilities, as required by SFAS No. 121. Revenues from the sale of gas decreased approximately $46.0 million for the year ended December 31, 1998 compared 21 to 1997. Average gas sales volumes increased 225 MMcf/D to 2,200 MMcf/D for the year ended December 31, 1998 compared to 1997, primarily due to an increase in the sale of gas purchased from third parties. The increase in volumes sold was more than offset by a decrease in average gas prices. Average gas prices realized by us decreased $.29 per Mcf to $2.01 per Mcf for the year ended December 31, 1998 compared to 1997. Included in the realized gas price is approximately $71,000 of loss recognized in the year ended December 31, 1998 related to futures positions on equity volumes. See further discussion in "-- Liquidity and Capital Resources--Risk Management Activities." Revenues from the sale of NGLs decreased approximately $162.3 million for the year ended December 31, 1998 compared to 1997. Average NGL sales volumes increased 145 MGal/D to 4,730 MGal/D for the year ended December 31, 1998 compared to 1997, primarily due to an increase in the sale of NGLs purchased from third parties. The increase in sales volumes was more than offset by a decrease in average NGL prices. Average NGL prices realized by us decreased $.10 per gallon to $.26 per gallon for the year ended December 31, 1998 compared to 1997. Included in the realized NGL price was approximately $7.4 million of gain recognized in the year ended December 31, 1998 related to futures positions on equity volumes. See further discussion in "--Liquidity and Capital Resources-- Risk Management Activities." Revenue associated with electric power marketing decreased approximately $59.5 million for the year ended December 31, 1998 compared to 1997, as we discontinued wholesale trading of electric power in 1997, due to a lack of profitability. Other net revenue increased approximately $12.2 million for the year ended December 31, 1998 compared to 1997. The increase was primarily due to a $14.9 million gain on the sale of our Perkins facility and a $1.0 million option payment received from RIS in connection with the potential sale of a portion of our assets in southwest Wyoming. These increases were offset by decreases of approximately $2.8 million in earnings from our investments in joint ventures, primarily due to the decreases in product prices and the sale of our interest in Redman Smackover. See further discussion at "Business--Significant Acquisitions, Projects and Dispositions--Southwest Wyoming." The reduction in product purchases of $232.1 million to $1.9 billion for the year ended December 31, 1998 compared to 1997, was primarily due to a decrease in commodity prices. Overall, combined product purchases as a percentage of sales of all products increased from 92% to 93% for the year ended December 31, 1998 compared to 1997. Over the past several years, we have experienced narrowing margins in our third-party sales as a result of increasing competitiveness of the natural gas marketing industry. During the year ended December 31, 1998, margins on the sale of third-party gas declined and averaged approximately $.02 per Mcf compared to approximately $.03 per Mcf for 1997. Contributing to the increase in the product purchase percentage for the year ended December 31, 1998 were higher payments related to our "keepwhole" contracts at our Granger facility. Under a "keepwhole" contract, our margin is reduced when the value of NGLs declines relative to the value of gas. Also included in product purchases were lower of cost or market writedowns, primarily related to NGL inventories, of $826,000 and $1.1 million for the years ended December 31, 1998 and 1997, respectively. Plant operating expense increased approximately $7.2 million for the year ended December 31, 1998 compared to 1997. The increase was primarily due to compression costs associated with the increasing Powder River basin coal bed methane production activities and expenses incurred at the Bethel Treating facility, which became partially operational during the third quarter of 1997. Interest expense increased $6.1 million for the year ended December 31, 1998 compared to 1997. The increase is the result of less interest capitalized to capital projects, primarily the Bethel Treating facility, and larger debt balances outstanding during the year ended December 31, 1998 compared to 1997. The larger debt balances resulted primarily from higher product inventory positions, capital expenditures associated with the Bethel Treating facility and reduced cashflow from operations. Business Strategy Our long-term business plan is to increase our profitability by: (i) optimizing the profitability of existing operations; (ii) entering into additional agreements with third-party producers who dedicate acreage to our gathering and processing operations; and (iii) investing in projects or acquiring assets that complement and extend our core natural gas gathering, processing, production and marketing businesses. 22 We continually seek to improve the profitability of our existing operations by increasing natural gas throughput levels through new well connections and expansion of gathering systems, increasing our efficiency through the consolidation of existing gathering and processing facilities, evaluating the economic performance of each of our operating facilities to ensure that a targeted rate of return is achieved and controlling operating and overhead expenses. We continually seek to increase acreage dedicated to our facilities. Our operations are located in some of the most actively drilled oil and gas producing basins in the United States. We enter into agreements under which we gather and process natural gas produced on acreage dedicated to us by third parties. We contract for production from new wells and newly dedicated acreage in order to replace declines in existing reserves that are dedicated for gathering and processing at our facilities. We have increased our dedicated estimated reserves from 2.3 Tcf at December 31, 1994 to 2.8 Tcf at December 31, 1999. In 1999, including the reserves associated with our joint ventures and partnerships and excluding the reserves associated with the facilities sold during this period, we connected new reserves to our facilities to replace approximately 142% of throughput. In order to obtain additional dedicated acreage and to secure contracts on favorable terms, we may participate to a limited extent with producers in exploration and production activities. For the same reason, we may also offer to sell an ownership interest in our facilities to selected producers. We will continue to invest in projects that complement and extend our core natural gas gathering, processing, production and marketing businesses including the consideration of expansion into additional geographic areas in the continental United States and Canada. Liquidity and Capital Resources Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our financing facilities and proceeds from offerings of debt and equity securities. In the past, these sources have been sufficient to meet our needs and finance the growth of our business. We can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and we may be required to seek alternative financing sources. In 1998, sources of liquidity included the sales of the Perkins facility and the Edgewood facility and related production. In the second quarter of 1999, we completed the sales of our Giddings, Katy and MiVida facilities. In connection with the sale of Katy, we sold gas held in storage at this facility. In December 1999, we contracted for the sale of the Black Lake facility and related reserves. This sale closed in January 2000. The total gross proceeds from the asset sales reported in 1999 was $168.0 million. We used the proceeds from these sales to reduce debt. Product prices, sales of inventory, the volumes of natural gas processed by our facilities, the margin on third-party product purchased for resale, as well as the timely collection of our receivables will affect all future net cash provided by operating activities. Additionally, our future growth will be dependent upon obtaining additions to dedicated plant reserves, acquisitions, new project development, marketing, efficient operation of our facilities and our ability to obtain financing at favorable terms. We believe that the amounts available to be borrowed under the Revolving Credit Facility, together with net cash provided by operating activities and the sale of non-strategic assets, will provide us with sufficient funds to connect new reserves, maintain our existing facilities and complete our current capital expenditure program. Depending on the timing and the amount of our future projects, we may be required to seek additional sources of capital. Our ability to secure such capital is restricted by our financing facilities, although we may request additional borrowing capacity from our lenders, seek waivers from our lenders to permit us to borrow funds from third parties, seek replacement financing facilities from other lenders, use stock as a currency for acquisitions, sell existing assets or a combination of such alternatives. While we believe that we would be able to secure additional financing, if required, we can provide no assurance that we will be able to do so or as to the terms of any such financing. We also believe that cash provided by operating activities and amounts available under our Revolving Credit Facility will be sufficient to meet our debt service and preferred stock dividend requirements for 2000. Historically, while certain individual plants have experienced declines in dedicated reserves, we have been successful in connecting additional reserves to more than offset the natural declines. There has been a reduction in drilling activity, primarily in basins that produce oil and casinghead gas, from levels that existed in prior years. However, higher gas prices experienced over the last several years, improved technology, e.g., 3-D seismic and horizontal drilling, and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in the Powder River basin and southwest Wyoming. The overall level of drilling will depend upon, among other factors, the prices for gas and oil, the drilling budgets 23 of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which is within our control. There is no assurance that we will continue to be successful in replacing the dedicated reserves processed at our facilities. We have effective shelf registration statements filed with the Commission for an aggregate of $200 million of debt securities and preferred stock, along with the shares of common stock, if any, into which such securities are convertible, and $62 million of debt securities, preferred stock or common stock. Our sources and uses of funds for the year ended December 31, 1999 are summarized as follows (In thousands): Sources of funds: Borrowings under revolving credit facility................ $2,115,250 Proceeds from the dispositions of property and equipment.. 148,685 Proceeds from issuance of long-term debt.................. 155,000 Net cash provided by operating activities................. 95,184 Proceeds from exercise of common stock options............ 158 Other..................................................... 88 ---------- Total sources of funds.................................. $2,514,365 ========== Uses of funds: Payments related to long-term debt (including debt issue costs)............................ $2,406,349 Capital expenditures...................................... 81,489 Dividends paid............................................ 16,865 ---------- Total uses of funds..................................... $2,504,703 ========== Additional sources of liquidity available to us are our inventories of gas and NGLs in storage facilities. We store gas and NGLs primarily to ensure an adequate supply for long-term sales contracts and for resale during periods when prices are favorable. We held gas in storage and in imbalances of approximately 13.7 Bcf at an average cost of $2.40 per Mcf at December 31, 1999 compared to 19.9 Bcf at an average cost of $2.13 per Mcf at December 31, 1998 under storage contracts at various third-party facilities. At December 31, 1999, we had hedging contracts in place for anticipated sales of approximately 18.6 Bcf of stored gas at a weighted average price of $2.41 per Mcf for the stored inventory. See "Item 1 and 2 - Business and Properties - Significant Acquisitions, Projects and Dispositions - Katy." We held NGLs in storage of 8500 MGal, consisting primarily of propane and normal butane, at an average cost of $.34 per gallon and 16,900 MGal at an average cost of $.24 per gallon at December 31, 1999 and 1998, respectively, at various third-party storage facilities. At December 31, 1999, we had no significant hedging contracts in place for anticipated sales of stored NGLs. One customer accounted for approximately 19% of our consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue, for the year ended December 31, 1999. This customer is a large integrated utility. Capital Investment Program For the years ended December 31, 1999, 1998 and 1997, we expended $81.5 million, $105.2 million and $198.9 million, respectively, on new projects and acquisitions. For the year ended December 31, 1999, our expenditures consisted of the following: (i) $43.3 million for new connects, system expansions and asset consolidations; (ii) $2.5 million for maintaining existing facilities; (iii) $34.3 million for exploration and production activities and acquisitions of undeveloped acreage; and (iv) $1.3 million of miscellaneous expenditures. We expect capital expenditures related to existing operations to be approximately $89.7 million during 2000, consisting of the following: (i) approximately $49.7 million related to gathering, processing and pipeline assets, of which $8.0 million is for maintaining existing facilities and $9.8 million for acquisition of the remaining 50% in the Westana Gathering Company; (ii) approximately $38.0 million related to exploration and production activities; and (iii) approximately $2.0 million for miscellaneous items. Overall, capital expenditures in the Powder River basin coal bed methane development and in southwest Wyoming operations represent 50% and 11%, respectively, of the total 2000 budget. 24 Financing Facilities Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a five- year $167 million Revolving Credit Facility, or Tranche B. At December 31, 1999, $ 46.3 million in total was outstanding on this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. We have the option to determine which rate will be used. We also pay a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on our debt to capitalization ratio and range from .75% to 2.00%. At December 31, 1999, the interest rate payable on the facility was 7.9%. We are required to maintain a total debt to capitalization ratio of not more than 60% through December 31, 2000 and of not more than 55% thereafter, and a senior debt to capitalization ratio of not more than 40% through December 31, 2001 and of not more than 35% thereafter. The agreement also requires a ratio of EBITDA, excluding certain non-recurring items, to interest and dividends on preferred stock as of the end of any fiscal quarter, for the four preceding fiscal quarters, of not less than 1.35 to 1.0 and increasing to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed and secured via a pledge of the stock of certain of our subsidiaries. We generally utilize excess daily funds to reduce any outstanding balances on the Revolving Credit Facility and associated interest expense, and we intend to continue such practice. Master Shelf Agreement. In December 1991, we entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31, 1999 are as indicated in the following table (dollars in thousands):
Interest Final Issue Date Amount Rate Maturity Principal Payments Due - ----------------- -------- -------- ----------------- ----------------------------------------------- October 27, 1992 $ 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003 December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007 -------- $150,000 ========
In April 1999, effective January 1999, we amended our agreement with Prudential to reflect the following provisions. We are required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 60% through December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of 40% through March 2002 and 35% thereafter. This amendment also requires an EBITDA to interest ratio of not less than 1.75 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less than 1.75 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-recurring items. In addition, we are prohibited from declaring or paying dividends that in the aggregate exceed the sum of $50 million plus 50% of consolidated net income earned after June 30, 1995, or minus 100% of a net loss, plus the aggregate net cash proceeds received after June 30, 1995 from the sale of any stock. At December 31, 1999, approximately $25.6 million was available under this limitation. We financed the $8.3 million scheduled payment made in October 1999 with amounts available under the Revolving Credit Facility. Borrowings under the Master Shelf Agreement are guaranteed and secured via a pledge of the stock of certain of our subsidiaries. In June 1999, we prepaid approximately $33.3 million of notes outstanding under the Master Shelf Agreement with proceeds from the offering of the Subordinated Notes. 1995 Senior Notes. In 1995, we sold $42 million of Senior Notes, the 1995 Senior Notes, to a group of insurance companies with an interest rate of 8.16% per annum. In March 1999, we prepaid $15 million of the principal amount 25 outstanding on the 1995 Senior Notes at par. These payments were financed by a portion of the $37 million Bridge Loan described below and by amounts available under the Revolving Credit Facility. The remaining principal amount outstanding of $27 million is due in a single payment in December 2005. The 1995 Senior Notes are guaranteed and secured via a pledge of the stock of certain of our subsidiaries. This facility contains covenants similar to the Master Shelf Agreement. In the second quarter of 1999 and in January 2000, we posted letters of credit for a total of approximately $11.8 million for the benefit of the holders of the 1995 Senior Notes. We are currently paying an annual fee of not more than .65% on the amounts outstanding on the Master Shelf Agreement and the 1995 Senior Notes. This fee will continue until we have received an implied investment grade rating on our senior secured debt. This fee is not assessed on the portion of the 1995 Senior Notes for which letters of credit are posted. 1993 Senior Notes. In 1993, we sold $50 million of 7.65% Senior Notes, the 1993 Senior Notes, to a group of insurance companies. Scheduled annual principal payments of $7.1 million on the 1993 Senior Notes were made on April 30 of 1997 and 1998. In February 1999, we prepaid $33.5 million of the total principal amounts outstanding of $35.6 million at par. These payments were financed by a portion of the $37 million Bridge Loan. We prepaid the remaining outstanding principal of $2.1 million in April 1999 with amounts available under the Revolving Credit Facility. In connection with the repayments on the Master Shelf Agreement, the 1995 Senior Notes and the 1993 Senior Notes, we incurred approximately $1.8 million of pre-tax yield maintenance and other charges. These charges are reflected as an extraordinary loss from early extinguishment of long-term debt in the second quarter of 1999. Bridge Loan. In February 1999, in order to finance prepayments of amounts outstanding on the 1993 and 1995 Senior Notes, we entered into a Bridge Loan agreement in the amount of $37 million with our agent bank. This facility was paid in full in April 1999 with proceeds from the sale of the Katy facility. Senior Subordinated Notes. In June 1999, we sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment. The Subordinated Notes bear interest at 10% and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by certain of our subsidiaries. In November 1999, we exchanged the privately placed notes for registered publicly tradable notes under the same terms and conditions. We incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and will be amortized over the term of the notes. Covenant Compliance. The Company was in compliance with all covenants in its debt agreements at December 31, 1999. Taking into account all the covenants contained in these agreements, we had approximately $110 million of available borrowing capacity at December 31, 1999. In the second quarter of 1999, we amended our various financing facilities providing for financial flexibility and covenant modifications and issued the Subordinated Notes. These amendments were needed given the depressed commodity pricing experienced in the industry in general at that time and the disappointing results at our Bethel Treating facility. We can provide no assurance that further amendments or waivers can be obtained in the future, if necessary, or that the terms would be favorable to us. To strengthen our credit ratings and to reduce our overall debt outstanding, we will continue to dispose of non-strategic assets and investigate alternative financing sources including the issuance of public debt, project-financing, joint ventures and operating leases. Risk Management Activities Our commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of our equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by our operating budget. The second goal is to manage price risk related to our gas, crude oil and NGL marketing activities to protect profit margins. This risk relates to hedging fixed price purchase and sale commitments, preserving the value of storage inventories, reducing exposure to physical market price volatility and providing risk management services to a variety of customers. We utilize a combination of fixed price forward contracts, exchange-traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter, or OTC, market to accomplish these objectives. These instruments allow us to preserve value and protect margins because corresponding losses or gains in the value of the financial 26 instruments offset gains or losses in the physical market. We use futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. We enter into futures transactions on the New York Mercantile Exchange, or NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with various counterparties, consisting primarily of financial institutions and other natural gas companies. We conduct our standard credit review of OTC counterparties and have agreements with these parties that contain collateral requirements. We generally use standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked-to-market daily for the credit review process. Our OTC credit risk exposure is partially limited by our ability to require a margin deposit from our major counterparties based upon the mark-to-market value of their net exposure. We are subject to margin deposit requirements under these same agreements. In addition, we are subject to similar margin deposit requirements for our NYMEX counterparties related to our net exposures. The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) equity volumes are less than expected, (ii) our customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in these prices. We hedged a portion of our estimated equity volumes of gas and NGLs in 2000 at pricing levels approximating our 2000 operating budget. Our equity hedging strategy establishes a minimum price while allowing varying levels of market participation above the minimum. As of February 8, 2000, we had hedged approximately 42%, or 30,000 MMBtu/day, of our anticipated equity gas for 2000 at a weighted average NYMEX equivalent minimum price of $2.22 per MMBtu and an additional 31%, or 22,000 MMBtu/day, with collars with a minimum price of $2.10 per MMBtu and a maximum price of $2.44 per MMBtu NYMEX equivalent price. Additionally, we have hedged approximately 26%, or 25,000 Bbl per month of our anticipated equity natural gasoline, condensate and crude oil for 2000 using a collar with a minimum price of $15.00 per Bbl and maximum price of $17.00 per Bbl NYMEX crude oil monthly average price. We have also hedged approximately 46%, or 195,000 Bbl per month, of our anticipated equity production of NGLs for 2000 with a minimum weighted average Mt. Belvieu composite price of $0.27 per gallon. Finally, we have hedged approximately 27%, or 345,000 Bbls of our estimated first quarter production of equity NGLs at a weighted average Mt. Belvieu price of $0.52 per gallon. At December 31, 1999, we had $600,000 of unrecognized gains in inventory that will be recognized primarily during the first quarter of 2000 which may be offset by margins from our related forward fixed price hedges and physical sales. At December 31, 1999, we had unrecognized net losses of $925,000 related to financial instruments that are expected to be offset by corresponding unrecognized net gains from our obligations to sell physical quantities of gas and NGLs. We enter into speculative futures, swap and option trades on a very limited basis for purposes that include testing of hedging techniques. Our policies contain strict guidelines for these trades including predetermined stop-loss requirements and net open position limits. Speculative futures, swap and option positions are marked-to-market at the end of each accounting period and any gain or loss is recognized in income for that period. Net gains or losses from these speculative activities for the years ended December 31, 1999 and 1998 were not material. Natural Gas Derivative Market Risk As of December 31, 1999, we held a notional quantity of approximately 202 Bcf of natural gas futures, swaps and options extending from January 2000 to January 2001 with a weighted average duration of approximately three months. This was comprised of approximately 87 Bcf of long positions and 115 Bcf of short positions in such instruments. As of December 31, 1998, we held a notional quantity of approximately 370 Bcf of natural gas futures, swaps and options extending from 27 January 1999 to December 2000 with a weighted average duration of approximately four months. This was comprised of approximately 178 Bcf of long positions and 192 Bcf of short positions in such instruments. We use a Value-at-Risk (VaR) model designed by J.P. Morgan as one measure of market risk for our natural gas portfolio. The VaR calculated by this model represents the maximum change in market value over the holding period at the specified statistical confidence interval. The VaR model is generally based upon J.P. Morgan's RiskMetrics (TM) methodology using historical price data to derive estimates of volatility and correlation for estimating the contribution of tenor and location risk. The VaR model assumes a one day holding period and uses a 95% confidence level. As of December 31, 1999, the calculated VaR of our entire natural gas portfolio of futures, swaps and options was approximately $3.3 million. This figure includes the risk related to our entire portfolio of natural gas financial instruments and does not include the related underlying hedged physical transactions. All financial instruments for which there are no offsetting physical transactions are treated as either the hedge of an anticipated transaction or a speculative trade. As of December 31, 1999, the VaR of these type of transactions for natural gas was approximately $400,000. Crude Oil and NGL Derivative Market Risk As of December 31, 1999, we held a notional quantity of approximately 123,500 MGal of NGL futures, swaps and options extending from January 2000 to December 2000 with a weighted average duration of approximately seven months. This was comprised of approximately 110,000 MGal of long positions and 12,000 MGal of short positions in such instruments. As of December 31, 1998, we held a notional quantity of approximately 177,000 MGal of NGL futures, swaps and options extending from January 1999 to December 1999 with a weighted average duration of approximately six months. This was comprised of approximately 129,000 MGal of long positions and 48,000 MGal of short positions in such instruments. As of December 31, 1999, we had purchased 25,000 barrels per month of NYMEX monthly average settlement $15.00 per barrel puts and sold 25,000 barrels per month of NYMEX monthly average settlement $17.00 calls to hedge a portion of the Company's equity production of natural gasoline, condensates and crude oil. We do not hold any crude oil futures, swaps or options for settlement beyond 2000. As of December 31, 1999, we had purchased 125,000 barrels per month of OPIS Mt. Belvieu monthly average settlement $0.300 per gallon puts to hedge a portion of our equity production of propane for 2000. As of December 31, 1999, we had purchased 70,000 barrels per month of OPIS Mt. Belvieu monthly average settlement $0.220 per gallon of purity ethane puts to hedge a portion of our equity production of ethane for 2000. As of December 31, 1999, we did not hold any NGL futures, swaps or options for settlement beyond 2000. As of December 31, 1999, the estimated fair value of the aforementioned crude oil and NGL options held by us was approximately $(194,000). Foreign Currency Derivative Market Risk As a normal part of our business, we enter into physical gas transactions which are payable in Canadian dollars. We enter into forward purchases and sales of Canadian dollars from time to time to fix the cost of our future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 1999, the net notional value of such contracts was approximately $7.5 million in Canadian dollars, which approximates its fair market value. As of December 31, 1998, the net notional value of such contracts was approximately $11.0 million in Canadian dollars, which approximated its fair market value. Year 2000 Overall, we did not experience any significant disruption of our operations or computer systems as a result of the Year 2000 28 issue. Prior to December 31, 1999, we completed a comprehensive review of our computer systems to identify the systems that could be affected by the Year 2000 issue and developed and implemented a plan to mitigate the risk of any problems. Our remediation plan included: (i) creating a Year 2000 awareness program to educate employees; (ii) compiling an inventory of all systems; (iii) developing system test plans as appropriate; (iv) completing the testing and remediation as required for both information and non-information technology systems; and (v) developing contingency plans to minimize the impact of a Year 2000 related failure caused either internally or externally. Additionally, we surveyed our business counterparties periodically regarding their Year 2000 conversion and contingency plans. In total, we spent approximately $1.1 million for remediation purposes, which primarily consisted of purchasing hardware and software upgrades. We also incurred internal staff costs and other expenses, which were immaterial. Environmental The construction and operation of our gathering systems, plants and other facilities used for the gathering, transporting, processing, treating or storing of gas and NGLs are subject to federal, state and local environmental laws and regulations, including those that can impose obligations to clean up hazardous substances at our facilities or at facilities to which we send wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. We employ four environmental engineers, five safety specialists and three regulatory compliance specialists to monitor environmental and safety compliance at our facilities. Prior to consummating any major acquisition, our environmental engineers perform audits on the facilities to be acquired. In addition, on an ongoing basis, the environmental engineers perform environmental assessments of our existing facilities. We believe that we are in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating our facilities. We believe that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on our financial position or results of operations. The Texas Natural Resource Conservation Commission which has authority to regulate, among other things, stationary air emissions sources, has created a committee to make recommendations to the Commission regarding a voluntary emissions reduction plan for the permitting of existing "grandfathered" air emissions sources within the State of Texas. A "grandfathered" air emissions source is one that does not need a state operating permit because it was constructed prior to 1971. We operate a number of these sources within the State of Texas, including portions of our Midkiff plant and many of our compressors. The recommendations proposed by the committee would create a voluntary permitting program for grandfathered sources, including incentives to participate, like the ability to operate these sources in a flexible manner. It is not clear which of the committee's recommendations, if any, that the Commission will implement and it is not possible to assess the potential effect on us until final regulations are promulgated. We anticipate that it is reasonably likely that the trend in environmental legislation and regulation will continue to be towards stricter standards. We are unaware of future environmental standards that are reasonably likely to be adopted that will have a material effect on our financial position or results of operations, but we cannot rule out that possibility. We are in the process of voluntarily cleaning up substances at certain facilities that we operate. Our expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to our results of operations and totaled approximately $2.6 million for the year ended December 31, 1999, including approximately $500,000 in air emissions fees to the states in which we operate. Although we anticipate that such environmental expenses per facility will increase over time, we do not believe that such increases will have a material effect on our financial position or results of operations. 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 1999 and 1998 and for each of the three years in the period ended December 31, 1999: Page ---- Report of Management....................................................... 28 Report of Independent Accountants.......................................... 29 Consolidated Balance Sheets................................................ 30 Consolidated Statement of Cash Flows....................................... 31 Consolidated Statement of Operations....................................... 32 Consolidated Statement of Changes in Stockholders' Equity.................. 33 Notes to Consolidated Financial Statements................................. 34 30 REPORT OF MANAGEMENT - -------------------- The financial statements and other financial information included in this Annual Report on Form 10-K are the responsibility of Management. The financial statements have been prepared in conformity with generally accepted accounting principles appropriate in the circumstances and include amounts that are based on Management's informed judgments and estimates. Management relies on the Company's system of internal accounting controls to provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with Management's authorization. The concept of reasonable assurance is based on the recognition that there are inherent limitations in all systems of internal accounting control and that the cost of such systems should not exceed the benefits to be derived. The internal accounting controls, including internal audit, in place during the periods presented are considered adequate to provide such assurance. The Company's financial statements are audited by PricewaterhouseCoopers LLP, independent accountants. Their report states that they have conducted their audit in accordance with generally accepted auditing standards. These standards include an evaluation of the system of internal accounting controls for the purpose of establishing the scope of audit testing necessary to allow them to render an independent professional opinion on the fairness of the Company's financial statements. Oversight of Management's financial reporting and internal accounting control responsibilities is exercised by the Board of Directors, through an Audit Committee that consists solely of outside directors. The Audit Committee meets periodically with financial management, internal auditors and the independent accountants to review how each is carrying out its responsibilities and to discuss matters concerning auditing, internal accounting control and financial reporting. The independent accountants and the Company's internal audit department have free access to meet with the Audit Committee without Management present. /S/ L. F. Outlaw - ------------------------------ L. F. Outlaw Chief Executive Officer and President /S/ William J. Krysiak - ------------------------------ William J. Krysiak Vice President - Finance (Principal Financial and Accounting Officer) 31 REPORT OF INDEPENDENT ACCOUNTANTS - --------------------------------- To the Board of Directors and Stockholders of Western Gas Resources, Inc. In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 1999 and 1998, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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 of these statements in accordance with auditing standards generally accepted in the United States which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Denver, Colorado March 13, 2000 32 WESTERN GAS RESOURCES, INC. CONSOLIDATED BALANCE SHEET (000s, except share data)
December 31, ----------------------- ASSETS 1999 1998 ------ ---------- ---------- Current assets: Cash and cash equivalents.................................................... $ 14,062 $ 4,400 Trade accounts receivable, net............................................... 196,739 233,574 Product inventory............................................................ 35,228 46,207 Parts inventory.............................................................. 10,318 10,153 Assets held for sale......................................................... 7,237 - Other........................................................................ 9,571 2,951 ---------- ---------- Total current assets....................................................... 273,155 297,285 ---------- ---------- Property and equipment: Gas gathering, processing, storage and transmission.......................... 808,274 952,531 Oil and gas properties and equipment......................................... 104,137 111,602 Construction in progress..................................................... 39,987 87,943 ---------- ---------- 952,398 1,152,076 Less: Accumulated depreciation, depletion and amortization................... (260,081) (305,589) ---------- ---------- Total property and equipment, net.......................................... 692,317 846,487 ---------- ---------- Other assets: Gas purchase contracts (net of accumulated amortization of $31,273 and $29,978, respectively)..................................................... 36,883 41,263 Other........................................................................ 47,131 34,342 ---------- ---------- Total other assets........................................................... 84,014 75,605 ---------- ---------- Total assets................................................................... $1,049,486 $1,219,377 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ Current liabilities: Accounts payable............................................................. $ 240,235 $ 245,315 Accrued expenses............................................................. 41,075 31,727 Dividends payable............................................................ 4,218 4,217 ---------- ---------- Total current liabilities.................................................. 285,528 281,259 Long-term debt................................................................. 378,250 504,881 Deferred income taxes payable, net............................................. 35,965 48,021 ---------- ---------- Total liabilities.............................................................. 699,743 834,161 ---------- ---------- Commitments and contingent liabilities......................................... - - Stockholders' equity: Preferred Stock; 10,000,000 shares authorized: $2.28 cumulative preferred stock, par value $.10; 1,400,000 shares issued ($35,000,000 aggregate liquidation preference)........................... 140 140 $2.625 cumulative convertible preferred stock, par value $.10; 2,760,000 issued ($138,000,000 aggregate liquidation preference).................... 276 276 Common stock, par value $.10; 100,000,000 shares authorized; 32,186,747 and 32,173,009 shares issued, respectively..................................... 3,220 3,217 Treasury stock, at cost; 25,016 shares in treasury........................... (788) (788) Additional paid-in capital................................................... 397,522 397,344 Retained earnings............................................................ (51,064) (17,075) Accumulated other comprehensive income....................................... 1,321 3,053 Notes receivable from key employees secured by common stock.................. (884) (951) ---------- ---------- Total stockholders' equity................................................. 349,743 385,216 ---------- ---------- Total liabilities and stockholders' equity..................................... $1,049,486 $1,219,377 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements. 33 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (000s)
Year Ended December 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- Reconciliation of net income to net cash provided by operating activities: Net income (loss)........................................................... $ (17,124) $ (67,205) $ 1,487 Add income items that do not affect cash: Depreciation, depletion and amortization................................... 50,981 59,346 59,248 Deferred income taxes...................................................... (11,428) (32,722) 465 Distributions in excess of (less than) equity income, net.................. (987) 963 1,764 (Gain) Loss on the sale of property and equipment.......................... 29,802 (16,478) (4,715) Impairment of property and equipment....................................... 1,158 108,447 34,615 Other non-cash items, net.................................................. (1,080) 2,595 3,284 ----------- ----------- ----------- 51,322 54,946 96,148 ----------- ----------- ----------- Adjustments to working capital to arrive at net cash provided by operating activities: Decrease in trade accounts receivable...................................... 36,567 25,317 79,963 (Increase) decrease in product inventory................................... 10,963 (29,810) 7,480 Increase in parts inventory................................................ (165) (748) (6,806) (Increase) decrease in other current assets................................ (6,620) (587) (1,027) Decrease in other assets and liabilities, net............................. 350 257 257 (Decrease) in accounts payable............................................. (4,960) (81,381) (59,572) (Decrease) increase in accrued expenses.................................... 7,727 (3,564) (1,688) ----------- ----------- ----------- Total adjustments......................................................... 43,862 (90,516) 18,607 ----------- ----------- ----------- Net cash provided by (used in) operating activities......................... 95,184 (35,570) 114,755 ----------- ----------- ----------- Cash flows from investing activities: Purchases of property and equipment, including acquisitions................ (80,089) (104,171) (196,293) Proceeds from the disposition of property and equipment.................... 148,685 75,286 20,034 Contributions to unconsolidated affiliates................................. (1,400) (1,045) (2,608) Distribution from unconsolidated affiliates................................ 88 3,489 - ----------- ----------- ----------- Net cash provided by (used in) investing activities......................... 67,284 (26,441) (178,867) ----------- ----------- ----------- Cash flows from financing activities: Net proceeds from exercise of common stock options......................... 158 23 239 Proceeds from issuance of long-term debt................................... 155,000 - - Payments on long-term debt................................................. (92,380) (15,476) (94,643) Borrowings under revolving credit facility................................. 2,115,250 3,230,400 1,894,950 Payments on revolving credit facility...................................... (2,304,500) (3,151,400) (1,738,450) Debt issue costs paid...................................................... (9,469) (44) (847) Dividends paid............................................................. (16,865) (16,869) (16,864) ----------- ----------- ----------- Net cash provided by (used in) financing activities......................... (152,806) 46,634 44,385 ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents........................ 9,662 (15,377) (19,727) Cash and cash equivalents at beginning of year.............................. 4,400 19,777 39,504 ----------- ----------- ----------- Cash and cash equivalents at end of year.................................... $ 14,062 $ 4,400 $ 19,777 =========== =========== ===========
The accompanying notes are an integral part of the consolidated financial statements. 34 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF OPERATIONS (000s, except share and per share amounts)
Year Ended December 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- Revenues: Sale of gas............................................................. $ 1,501,066 $ 1,611,521 $ 1,657,479 Sale of natural gas liquids............................................. 346,819 449,696 611,969 Sale of electric power.................................................. - 20 59,477 Processing, transportation and storage revenue.......................... 48,994 44,743 40,906 Other, net.............................................................. 13,845 11,108 10,714 ----------- ----------- ----------- Total revenues........................................................ 1,910,724 2,117,088 2,380,545 ----------- ----------- ----------- Costs and expenses: Product purchases....................................................... 1,715,839 1,914,303 2,146,430 Plant operating expense................................................. 67,419 85,353 78,113 Oil and gas exploration and production costs............................ 9,196 7,996 7,714 Depreciation, depletion and amortization................................ 50,981 59,346 59,248 Selling and administrative expense...................................... 28,357 30,128 29,446 (Gain) loss on sale of assets........................................... 29,802 (16,478) (4,715) Interest expense........................................................ 33,156 33,616 27,474 Loss on the impairment of property and equipment........................ 1,158 108,447 34,615 ----------- ----------- ----------- Total costs and expenses.............................................. 1,935,908 2,222,711 2,378,325 ----------- ----------- ----------- Income (loss) before income taxes........................................ (25,184) (105,623) 2,220 Provision (benefit) for income taxes: Current................................................................. 2,261 (5,696) 268 Deferred................................................................ (11,428) (32,722) 465 ----------- ----------- ----------- Total provision (benefit) for income taxes............................ (9,167) (38,418) 733 ----------- ----------- ----------- Income (loss) before extraordinary items................................. (16,017) (67,205) 1,487 Extraordinary charge for early extinguishment of debt, net of tax benefit of $628,000........................................ (1,107) - - ----------- ----------- ----------- Net income (loss)........................................................ $ (17,124) $ (67,205) $ 1,487 ----------- ----------- ----------- Preferred stock requirements............................................. (10,436) (10,439) (10,439) ----------- ----------- ----------- Loss attributable to common stock........................................ $ (27,563) $ (77,644) $ (8,952) =========== =========== =========== Loss per share of common stock........................................... $ (.86) $ (2.42) $ (.28) =========== =========== =========== Weighted average shares of common stock outstanding...................... 32,150,887 32,147,354 32,134,011 =========== =========== =========== Loss per share of common stock - assuming dilution....................... $ (.86) $ (2.42) $ (.28) =========== =========== =========== Weighted average shares of common stock outstanding - assuming dilution.. 32,150,887 32,147,354 32,137,803 =========== =========== ===========
The accompanying notes are an integral part of the consolidated financial statements. 35 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (000s, except share amounts)
Shares of $2.625 $2.625 $2.28 Cumulative Shares $2.28 Cumulative Cumulative Convertible Shares of Common Cumulative Convertible Preferred Preferred of Common Stock Preferred Preferred Common Treasury Stock Stock Stock in Treasury Stock Stock Stock Stock ---------- ----------- ---------- ----------- ---------- ----------- ------ -------- Balance at December 31, 1996............ 1,400,000 2,760,000 32,109,135 25,016 $ 140 $ 276 $3,213 $ (788) Net income, 1997........................ - - - - - - - - Stock options exercised................. - - 37,302 - - - 4 - Tax benefit related to stock options.... - - - - - - - - Loans forgiven.......................... - - - - - - - - Dividends declared on common stock...... - - - - - - - - Dividends declared on $2.28 cumulative preferred stock........................ - - - - - - - - Dividends declared on $2.625 cumulative convertible preferred stock............ - - - - - - - - ---------- ----------- ---------- ----------- ---------- ----------- ------ -------- Balance at December 31, 1997............ 1,400,000 2,760,000 32,146,437 25,016 140 276 3,217 (788) Net income, 1998........................ - - - - - - - - Stock options exercised................. - - 1,556 - - - - - Loans forgiven.......................... - - - - - - - - Dividends declared on common stock...... - - - - - - - - Dividends declared on $2.28 cumulative preferred stock........................ - - - - - - - - Dividends declared on $2.625 cumulative convertible preferred stock............ - - - - - - - - Translation adjustments................. - - - - - - - - ---------- ----------- ---------- ----------- ---------- ----------- ------ -------- Balance at December 31, 1998............ 1,400,000 2,760,000 32,147,993 25,016 140 276 3,217 (788) Net income, 1999........................ - - - - - - - - Stock options exercised................. - - 13,738 - - - 3 - Tax benefit related to stock options.... - - - - - - - - Loans forgiven.......................... - - - - - - - - Dividends declared on common stock...... - - - - - - - - Dividends declared on $2.28 cumulative preferred stock........................ - - - - - - - - Dividends declared on $2.625 cumulative convertible preferred stock............ - - - - - - - - Translation adjustments................. - - - - - - - - ---------- ----------- ---------- ----------- ---------- ----------- ------ -------- Balance at December 31, 1999............ 1,400,000 2,760,000 32,161,731 25,016 $ 140 $ 276 $3,220 $ (788) ========== =========== ========== =========== ========== =========== ====== ======== Cumulative Accumulated Notes Total Additional Retained Other Receivable Stock- Paid-In (Deficit) Comprehensive from Key holders' Capital Earnings Income Employees Equity ---------- ----------- ------------- ---------- --------- Balance at December 31, 1996............ $ 397,061 $ 82,378 $ - $ (1,813) $ 480,467 Net income, 1997........................ - 1,487 - - 1,487 Stock options exercised................. 260 - - (25) 239 Tax benefit related to stock options.......................... - - 2,233 - 2,233 Loans forgiven.......................... - - - 552 552 Dividends declared on common stock...... - (6,427) - (6,427) Dividends declared on $2.28 cumulative preferred stock........................ - (3,194) - - (3,194) Dividends declared on $2.625 cumulative convertible preferred stock............ - (7,245) - - (7,245) ---------- ----------- ------------- ---------- --------- Balance at December 31, 1997............ 397,321 66,999 2,233 (1,286) 468,112 Net income, 1998........................ - (67,205) - - (67,205) Stock options exercised................. 23 - - - 23 Loans forgiven.......................... - - - 335 335 Dividends declared on common stock...... - (6,430) - - (6,430) Dividends declared on $2.28 cumulative preferred stock........................ - (3,194) - - (3,194) Dividends declared on $2.625 cumulative convertible preferred stock............ - (7,245) - - (7,245) Translation adjustments................. - - 820 - 820 ---------- ----------- ------------- ---------- --------- Balance at December 31, 1998............ 397,344 (17,075) 3,053 (951) 385,216 Net income, 1999........................ - (17,124) - - (17,124) Stock options exercised................. 155 - - - 158 Tax benefit related to stock options.... 23 - - - 23 Loans forgiven.......................... - - - 67 67 Dividends declared on common stock...... - (6,426) - - (6,426) Dividends declared on $2.28 cumulative preferred stock........................ - (3,194) - - (3,194) Dividends declared on $2.625 cumulative convertible preferred stock............ - (7,245) - - (7,245) Translation adjustments................. - - (1,732) - (1,732) ---------- ----------- ------------- ---------- --------- Balance at December 31, 1999............ $ 397,522 $ (51,064) $ 1,321 $ (884) $ 349,743 ========== =========== ============= ========== =========
The accompanying notes are an integral part of the consolidated financial statements. 36 NOTE 1 - NATURE OF ORGANIZATION - ------------------------------- Western Gas Resources, Inc. (the "Company") gathers, processes, treats, develops and produces, transports and markets natural gas and NGLs. The Company operates in major gas-producing basins in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. The Company designs, constructs, owns and operates natural gas gathering systems and processing and treating facilities in order to provide its customers with a broad range of services from the wellhead to the sales delivery point. Western Gas Resources, Inc. was formed in October 1989 to acquire a majority interest in Western Gas Processors, Ltd. (the "Partnership") and to assume the duties of WGP Company, the general partner of the Partnership. The Partnership was a Colorado limited partnership formed in 1977 to engage in the gathering and processing of natural gas. The reorganization was accomplished in December 1989 through an exchange for common stock of partnership units held by the former general partners of WGP Company and an initial public offering of Western Gas Resources, Inc. Common Stock. On May 1, 1991, a further restructuring ("Restructuring") of the Partnership and Western Gas Resources, Inc. (together with its predecessor, WGP Company, collectively, the "Company") was approved by a vote of the security holders. The combinations were reorganizations of entities under common control and were accounted for at historical cost in a manner similar to poolings of interests. The Company has completed three public offerings of Common Stock. In December 1989, the Company issued 3,527,500 shares of Common Stock at a public offering price of $11.50. In November 1991, the Company issued 4,115,000 shares of Common Stock at a public offering price of $18.375 per share. In November 1996, the Company issued 6,325,000 shares of Common Stock at a public offering price of $16.25 per share. The net proceeds to the Company from the November 1996 public offering of Common Stock of $96.4 million were primarily used to reduce indebtedness under the Revolving Credit Facility. The Company has also issued preferred stock in a private transaction and has completed two public offerings of preferred stock. In October 1991, the Company issued 400,000 shares of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock ("7.25% Preferred Stock") with a liquidation preference of $100 per share to an institutional investor. In May 1995, the Company redeemed all of the issued and outstanding shares of its 7.25% Preferred Stock pursuant to the provisions of its Certificate of Designation relating to such preferred stock, at an aggregate redemption price of approximately $42.0 million, including a redemption premium of $2.0 million. In November 1992, the Company issued 1,400,000 shares of $2.28 Cumulative Preferred Stock with a liquidation preference of $25 per share, at a public offering price of $25 per share, redeemable at the Company's option on or after November 15, 1997. In February 1994, the Company issued 2,760,000 shares of $2.625 Cumulative Convertible Preferred Stock with a liquidation preference of $50 per share, at a public offering price of $50 per share, redeemable at the Company's option on or after February 16, 1997 and convertible at the option of the holder into Common Stock at a conversion price of $39.75. Significant Business Acquisitions, Dispositions and Projects Coal Bed Methane The Company continues to expand its Powder River basin coal bed methane natural gas gathering system and developing its own coal seam gas reserves in Wyoming. During the years ended December 31, 1999, 1998 and 1997, the Company expended approximately $51.4 million, $46.7 million and $32.2 million, respectively, on this project. On October 30, 1997, the Company sold a 50% undivided interest in its Powder River basin coal bed methane gas operations. The purchase price was $17.9 million, resulting in a pre-tax gain of $4.7 million. In December 1998, the Company joined with other industry participants to form the Fort Union Gas Gathering, L.L.C., to construct a 106-mile, 24-inch gathering pipeline and treater to gather and treat natural gas in the Powder River basin in northeast Wyoming. The Company owns an approximate 13% interest in the L.L.C. and is the construction manager and field operator. The gathering pipeline went into service in the third quarter of 1999. Construction of the gathering header and treating system was project-financed and required a cash investment by the Company of approximately $900,000. In conjunction with the project financing, the Company entered into a ten year agreement for firm gathering services on 60 37 MMcf/D of capacity for $.14 per Mcf on Fort Union beginning in December 1999. Southwest Wyoming The Company's facilities in southwest Wyoming are comprised of the Granger facility and a 72% ownership interest in the Lincoln Road facility (collectively the "Granger Complex"). The Company began to expand its gas gathering and exploration and production activities in southwest Wyoming during 1997. The expansion in this area is primarily intended to develop acreage to replace declines in reserves and generate additional volumes for gathering and processing at its facilities. During the years ended December 31, 1999 and 1998, the Company expended approximately $13.2 million and $16.0 million, respectively, on this project. In February 1998, the Company sold a 50% undivided interest in a small portion of the Granger gathering system for approximately $4.0 million. This amount approximated the Company's cost in such facilities. In 1997, the Company granted an option to an affiliate of a producer behind the Granger Complex to purchase up to 50% of the Granger Complex. In conjunction with this agreement, in February 1998, the Company received a $1 million non- refundable option payment. The option to acquire an interest in these facilities expired in the fourth quarter of 1998. Black Lake In December 1999, the Company entered into an agreement for the sale of its Black Lake facility and related reserves for gross proceeds of $7.8 million. This sale closed in January 2000. This transaction resulted in an approximate pre-tax loss (subject to final accounting adjustment) of $7.3 million, which was accrued in the fourth quarter of 1999. MiVida In June 1999, the Company sold its MiVida treating facility for gross proceeds of $12.0 million, which resulted in an approximate pre-tax gain of $1.2 million. Giddings In April 1999, the Company sold its Giddings Facility for gross proceeds of $36.0 million, which resulted in an approximate pre-tax loss of $6.6 million. Katy In April 1999, the Company sold all of the outstanding common stock of its wholly-owned subsidiary, Western Gas Resources Storage, Inc., for gross proceeds of $100.0 million, which resulted in an approximate pre-tax loss of $17.7 million. The only asset of this subsidiary was the Katy Facility. In April 1999, the Company also sold approximately 5.1 Bcf of stored gas in the Katy Facility to the same purchaser for total sales proceeds of approximately $11.7 million, which approximated the cost of the inventory. To meet the needs of its marketing operations, the Company will continue to contract for storage capacity. Accordingly, the Company has entered into a long-term agreement with the purchaser for 3 Bcf of storage capacity at market rates. Bethel Treating Facility In 1996 and 1997, the Pinnacle Reef exploration area was rapidly developing into a very active lease acquisition and exploratory drilling area using 3-D seismic technology to identify prospects. The initial discoveries indicated a very large potential gas development. Based on the receipt of large acreage dedications in this area, the Company constructed the Bethel treating facility for a total cost of approximately $102.8 million with a throughput capacity of 350 MMcf/D. In 1998, the production rates from the wells drilled in this field and the recoverable reserves from these properties, were far less than the producers originally expected. As a result, in 1999, the Bethel treating facility averaged gas throughput of approximately 98 MMcf/D. Due to the unexpected poor drilling results and reductions in the producers' drilling budgets, the number of rigs actively drilling for Pinnacle Reefs has decreased from 18 in July 1998 to three in December 1999. 38 In the fourth quarter of 1998, because of uncertainties related to the pace and success of third-party drilling programs, declines in volumes produced at certain wells and other conditions outside of the Company's control, the Company determined that a pre-tax, non-cash impairment charge of $77.8 million was required. Edgewood In two transactions which closed in October 1998 the Company sold its Edgewood gathering system, including its undivided interest in the producing properties associated with this facility, and its 50% interest in the Redman Smackover Joint Venture ("Redman Smackover"). The combined sales price was $55.8 million. The proceeds from these sales were used to repay a portion of the balances outstanding under the Revolving Credit Facility. After the accrual of certain related expenses, the Company recognized a pre-tax gain of approximately $1.6 million, during the fourth quarter of 1998. Perkins In November 1997, the Company entered into an agreement to sell its Perkins facility. In March 1998, the Company completed the sale of this facility with an effective date of January 1, 1998. The sales price was $22.0 million and resulted in a pre-tax gain of approximately $14.9 million. Subsequent Events In January 2000, the Company sold all of the outstanding stock of its wholly- owned subsidiary, Western Gas Resources-California, Inc. ("WGR-California") for $14.9 million. The only asset of this subsidiary was a 162 mile pipeline in the Sacramento basin of California. The pipeline was acquired through the exercise of an option by the Company in a transaction which closed simultaneously with the sale of WGR-California. The Company will recognize a pre-tax gain on the sale, subject to final accounting adjustment, of approximately $5.5 million in the first quarter of 2000. In February 2000, the Company acquired the remaining 50% interest in the Westana Gathering Company for a gross purchase price of $10.8 million. This transaction is effective January 1, 2000 and is subject to final accounting adjustment. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - --------------------------------------------------- The significant accounting policies followed by the Company and its wholly-owned subsidiaries are presented here to assist the reader in evaluating the financial information contained herein. The Company's accounting policies are in accordance with generally accepted accounting principles. Principles of Consolidation The consolidated financial statements include the accounts of the Company and the Company's wholly-owned subsidiaries. All material inter-company transactions have been eliminated in consolidation. The Company's interest in certain investments is accounted for by the equity method. Inventories The cost of gas and NGL inventories is determined by the weighted average cost method on a location-by-location basis. Residue and NGL inventory covered by hedging contracts is accounted for on a specific identification basis. Product inventory includes $32.8 million and $42.8 million of gas and $2.9 million and $3.4 million of NGLs at December 31, 1999 and 1998, respectively. During the year ended December 31, 1998, the Company recorded a lower of cost or market write-down of NGL inventories of $826,000. 39 Property and Equipment Property and equipment is recorded at the lower of cost, including capitalized interest, or estimated realizable value. Interest incurred during the construction period of new projects is capitalized and amortized over the life of the associated assets. Depreciation is provided using the straight-line method based on the estimated useful life of each facility which ranges from three to 35 years. Useful lives are determined based on the shorter of the life of the equipment or the reserves serviced by the equipment. The cost of acquired gas purchase contracts is amortized using the straight-line method. Oil and Gas Properties and Equipment The Company follows the successful efforts method of accounting for oil and gas exploration and production activities. Acquisition costs, development costs and successful exploration costs are capitalized. Exploratory dry hole costs, lease rentals and geological and geophysical costs are charged to expense as incurred. Upon surrender of undeveloped properties, the original cost is charged against income. Producing properties and related equipment are depleted and depreciated by the units-of-production method based on estimated proved reserves for producing properties and proved developed reserves for lease and well equipment. Income Taxes Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. These temporary differences are determined and accounted for in accordance with SFAS No. 109, "Accounting for Income Taxes." Foreign Currency Adjustments During the second quarter of 1997, the Company began operating a subsidiary in Canada. The assets and liabilities associated with this subsidiary are translated into U.S. dollars at the exchange rate as of the balance sheet date and revenues and expenses at the weighted-average of exchange rates in effect during each reporting period. SFAS No. 52, "Foreign Currency Translation," requires that cumulative translation adjustments be reported as a separate component of stockholders' equity. The translation adjustments for the years ended December 31, 1999 and 1998 were $(1.7) million and $820,000, respectively. The adjustment for the year ended December 31, 1997 was not material. Revenue Recognition Revenue for sales or services is recognized at the time the gas, NGLs or electric power is delivered or at the time the service is performed. Comprehensive Income In June 1997, the Financial Accounting Standards Board issued SFAS No. 130, "Reporting Comprehensive Income," ("SFAS No. 130") effective for fiscal years beginning after December 15, 1997. SFAS No. 130 requires that changes in items of comprehensive income be reported as a separate component of stockholders' equity. The Company's cumulative translation adjustments of $(1.7) million and $820,000 for the years ended December 31, 1999 and 1998 and tax benefits related to stock options of $2.2 million for the year ended December 31, 1997 are separately reported on the Consolidated Statement of Changes in Stockholders' Equity. Gas and NGL Hedges Gains and losses on hedges of product inventory are included in the carrying amount of the inventory and are ultimately recognized in gas and NGL sales when the related inventory is sold. Gains and losses related to qualifying hedges, as defined by SFAS No. 80, "Accounting for Futures Contracts," of firm commitments or anticipated transactions (including hedges of equity production) are recognized in gas and NGL sales, as reported on the Consolidated Statement of Operations, when the hedged physical transaction occurs. For purposes of the Consolidated Statement of Cash Flows, all hedging gains and losses are classified in net cash provided by operating activities. To the extent the Company engages in speculative 40 transactions, they are marked to market at the end of each accounting period and any gain or loss is recognized in income for that period. Such amounts were negligible in 1999, 1998 and 1997. Impairment of Long-Lived Assets SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long- Lived Assets to be Disposed of" ("SFAS No. 121") requires long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The Company reviews its assets at the plant facility and oil and gas producing property levels. In order to determine whether an impairment exists, the Company compares its net book value of the asset to the estimated fair market value or the undiscounted expected future net cash flows, determined by applying future prices estimated by management over the shorter of the lives of the facilities or the reserves supporting the facilities. If an impairment exists, write-downs of assets are based upon expected future net cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. The Company has written down property and equipment of $1.2 million, $108.5 million and $34.6 million in accordance with SFAS No. 121 during the years ended December 31, 1999, 1998 and 1997, respectively. Earnings (Loss) Per Share of Common Stock The Company follows SFAS No. 128, "Earnings per Share" ("SFAS No. 128") which requires that earnings per share and earnings per share - assuming dilution be calculated and presented on the face of the statement of operations. In accordance with SFAS No. 128, earnings (loss) per share of common stock is computed by dividing income (loss) attributable to common stock by the weighted average shares of common stock outstanding. In addition, earnings (loss) per share of common stock -assuming dilution is computed by dividing income (loss) attributable to common stock by the weighted average shares of common stock outstanding as adjusted for potential common shares. Income (loss) attributable to common stock is income (loss) less preferred stock dividends. The Company declared preferred stock dividends of $10.4 million for each of the years ended December 31, 1999, 1998 and 1997, respectively. Common stock options, which are potential common shares, had a dilutive effect on earnings per share and increased the weighted average shares of common stock outstanding by 3,792 shares for the year ended December 31, 1997. The common stock options were anti- dilutive in 1999 and 1998 and therefore were excluded from the computation. SFAS No. 128 dictates that the computation of earnings per share shall not assume conversion, exercise or contingent issuance of securities that would have an antidilutive effect on earnings (loss) per share. As a result, the computations for each of the three years in the period ended December 31, 1999 were not adjusted to reflect the conversion of the Company's $2.625 Cumulative Convertible Preferred Stock outstanding. The shares are antidilutive as the incremental shares result in an increase in earnings per share, or a reduction of loss per share, after giving affect to the dividend requirements. Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of trade accounts receivable and over-the- counter ("OTC") swaps and options. The risk is limited due to the large number of entities comprising the Company's customer base and their dispersion across industries and geographic locations. At December 31, 1999, the Company believes it had no significant concentrations of credit risk. One customer accounted for approximately 19% of the Company's consolidated revenues from the sale of NGLs, or 3% of total consolidated revenue, for the year ended December 31, 1999. This customer is a large integrated utility. Cash and Cash Equivalents Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less. Supplementary Cash Flow Information 41 Interest paid was $34.1 million, $36.1 million and $33.1 million, respectively, for the years ended December 31, 1999, 1998 and 1997. Capitalized interest associated with construction of new projects was $2.0 million, $2.5 million and $5.1 million, respectively, for the years ended December 31, 1999, 1998 and 1997. Income taxes paid or (refunded) were $(2.9) million, $0 and $2.6 million, respectively, for the years ended December 31, 1999, 1998 and 1997. Stock Compensation As permitted under SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), the Company has elected to continue to measure compensation costs for stock-based employee compensation plans as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB No. 25"). The Company has complied with the pro forma disclosure requirements of SFAS No. 123 as required under the pronouncement. The Company realizes an income tax benefit from the exercise of non-qualified stock options related to the difference between the market price at the date of exercise and the option price. APB No. 25 requires that this difference be credited to additional paid-in capital. In September 1997, the Company recorded a credit of $2.2 million to additional paid-in capital to reflect such difference associated with the Company's $5.40 Stock Option Plan. Use of Estimates and Significant Risks The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in these financial statements and accompanying notes. The more significant areas requiring the use of estimates relate to oil and gas reserves, fair value of financial instruments, future net cash flows associated with assets and useful lives for depreciation, depletion and amortization. Actual results could differ from those estimates. The Company is subject to a number of risks inherent in the industry in which it operates, primarily fluctuating prices and gas supply. The Company's financial condition and results of operations will depend significantly upon the prices received for gas and NGLs. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the Company must continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled will depend upon, among other factors, prices for gas and oil, the drilling budgets of third-party producers, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within the Company's control. Accounting for Derivative Instruments and Hedging Activities In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000. Under SFAS No. 133, the Company will be required to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income depending upon the nature of the underlying transaction. The Company has not yet determined the impact that the adoption of SFAS No. 133 will have on its earnings or financial position. Reclassifications Certain prior years' amounts in the consolidated financial statements and related notes have been reclassified to conform to the presentation used in 1999. NOTE 3 - RELATED PARTIES - ------------------------ 42 The Company enters into joint ventures and partnerships in order to reduce risk, create strategic alliances and to establish itself in oil and gas producing basins in the United States. The Company had a 50% ownership interest in Williston Gas Company ("Williston") and Westana Gathering Company ("Westana"). Williston Gas Company was dissolved effective December 31, 1998 and the Company purchased the remaining 50% interest in Westana in February 2000. In addition, for the year ended December 31, 1997, the Company also had a 50% ownership interest in Redman Smackover. This interest was sold effective July 1, 1998. The Company acted as operator for Williston and Westana. The Company also had a 49% interest in the Sandia Energy Resources Joint Venture ("Sandia"), which was dissolved in 1999. The Company's share of equity income or loss in these ventures is reflected in other net revenue. All transactions entered into by the Company with its related parties were consummated in the ordinary course of business. Historically, the Company had purchased a significant portion of the production of Williston. The Company also performed various operational and administrative functions for Williston and charged a monthly overhead fee to cover such services. The Company performed various operational and administrative functions for Westana and charged a monthly overhead fee to cover such services. The Company recorded receivable and payable balances at the end of each accounting period related to transactions with Westana. At December 31, 1999, the Company's investment in Westana was $28.9 million. The Company provided substantially all of the natural gas that Sandia marketed and also provided it with various administrative services. In addition, the Company purchased gas from the joint venture. The following table summarizes account balances reflected in the financial statements (000s): As of or for the Year Ended December 31, ---------------------------------------- 1999 1998 1997 ------------ ------------ ------------ Trade accounts receivable.. $ 4,895 $ 3,794 $ 4,295 ============ ============ ============ Accounts payable........... 3,915 9,474 7,246 ============ ============ ============ Sales of gas and NGLs...... 6,635 31,319 19,504 ============ ============ ============ Processing revenue......... 225 192 336 ============ ============ ============ Product purchases.......... 51,676 58,899 59,082 ============ ============ ============ Administrative expense..... $ 450 $ 483 $ 421 ============ ============ ============ The Company has entered into agreements committing the Company to loan to certain key employees an amount sufficient to exercise their options as each portion of their options vests under the Key Employees' Incentive Stock Option. The loan and accrued interest will be forgiven if the employee has been continuously employed by the Company for periods specified under the agreements and Board of Directors' resolutions. As of December 31, 1999 and 1998, loans related to 75,000 and 81,250 shares of Common Stock, respectively, totaling $803,000 and $870,000, respectively, were outstanding to certain current and past employees under these programs. The loans are secured by a portion of the Common Stock issued upon exercise of the options and are accounted for as a reduction of stockholders' equity. During 1999 and 1998, the Board of Directors approved the forgiveness of loans to certain individuals totaling approximately $67,000 and $335,000, respectively, in connection with these plans. NOTE 4 - COMMODITY RISK MANAGEMENT - ---------------------------------- Risk Management Activities 43 The Company's commodity price risk management program has two primary objectives. The first goal is to preserve and enhance the value of the Company's equity volumes of gas and NGLs with regard to the impact of commodity price movements on cash flow, net income and earnings per share in relation to those anticipated by the Company's operating budget. The second goal is to manage price risk related to the Company's physical gas, crude oil and NGL marketing activities to protect profit margins. This risk relates to hedging fixed price purchase and sale commitments, preserving the value of storage inventories, reducing exposure to physical market price volatility and providing risk management services to a variety of customers. The Company utilizes a combination of fixed price forward contracts, exchange- traded futures and options, as well as fixed index swaps, basis swaps and options traded in the over-the-counter ("OTC") market to accomplish these objectives. These instruments allow the Company to preserve value and protect margins because gains or losses in the physical market are offset by corresponding losses or gains in the value of the financial instruments. The Company uses futures, swaps and options to reduce price risk and basis risk. Basis is the difference in price between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. The Company enters into futures transactions on the New York Mercantile Exchange ("NYMEX") and the Kansas City Board of Trade and through OTC swaps and options with various counterparties, consisting primarily of financial institutions and other natural gas companies. The Company conducts its standard credit review of OTC counterparties and has agreements with such parties that contain collateral requirements. The Company generally uses standardized swap agreements that allow for offset of positive and negative exposures. OTC exposure is marked to market daily for the credit review process. The Company's OTC credit risk exposure is partially limited by its ability to require a margin deposit from its major counterparties based upon the mark-to-market value of their net exposure. The Company is subject to margin deposit requirements under these same agreements. In addition, the Company is subject to similar margin deposit requirements for its NYMEX counterparties related to its net exposures. The use of financial instruments may expose the Company to the risk of financial loss in certain circumstances, including instances when (i) equity volumes are less than expected, (ii) the Company's customers fail to purchase or deliver the contracted quantities of natural gas or NGLs, or (iii) the Company's OTC counterparties fail to perform. To the extent that the Company engages in hedging activities, it may be prevented from realizing the benefits of favorable price changes in the physical market. However, it is similarly insulated against decreases in such prices. The Company has hedged a portion of its equity volumes of gas and NGLs in 2000, at pricing levels approximating its 2000 operating budget. The Company's equity hedging strategy establishes a minimum price to the Company while allowing varying levels of market participation above the minimum. As of February 8, 2000, the Company has hedged approximately 42%, or 30,000 MMBtu/day, of its anticipated equity gas for 2000 at a weighted average NYMEX equivalent price of $2.22 per MMBtu and an additional 31%, or 22,000 MMBtu/day, of collars with a minimum $2.10 per MMBtu and a maximum $2.44 per MMBtu NYMEX equivalent price. The Company has hedged approximately 26%, or 25,000 Bbl per month of its anticipated equity natural gasoline, condensate and crude oil for 2000 using a collar with a minimum $15.00 per Bbl and maximum $17.00 per Bbl NYMEX crude oil monthly average price. The Company has also hedged approximately 46%, or 195,000 Bbl per month, of its anticipated equity production of NGLs for 2000 with a minimum weighted average Mt. Belvieu price composite of $0.27 per gallon. Additionally, the Company has hedged approximately 27%, or 345,000 Bbls of first quarter NGLs at a weighted average Mt. Belvieu price of $0.52 per gallon. At December 31, 1999 the Company had $600,000 of unrecognized gains in inventory that will be recognized primarily during the first quarter of 2000 which may be offset by margins from the Company's related forward fixed price hedges and physical sales. At December 31, 1999 the Company had unrecognized net losses of $925,000 related to financial instruments that are expected to be offset by corresponding unrecognized net gains from the Company's obligations to sell physical quantities of gas and NGLs. The Company enters into speculative futures, swap and option trades on a very limited basis for purposes that include testing of hedging techniques. The Company's policies contain strict guidelines for such trading including predetermined stop-loss 44 requirements and net open positions limits. Speculative futures, swap and option positions are marked-to-market at the end of each accounting period and any gain or loss is recognized in income for that period. Net gains or losses from such speculative activities for the years ended December 31, 1999 and 1998 were not material. Natural Gas Derivative Market Risk As of December 31, 1999, the Company held a notional quantity of approximately 202 Bcf of natural gas futures, swaps and options extending from January 2000 to January 2001 with a weighted average duration of approximately three months. This was comprised of approximately 87 Bcf of long positions and 115 Bcf of short positions in such instruments. As of December 31, 1998, the Company held a notional quantity of approximately 370 Bcf of natural gas futures, swaps and options extending from January 1999 to December 2000 with a weighted average duration of approximately four months. This was comprised of approximately 178 Bcf of long positions and 192 Bcf of short positions in such instruments. Crude Oil and NGL Derivative Market Risk As of December 31, 1999, the Company held a notional quantity of approximately 123,500 MGal of NGL futures, swaps and options extending from January 2000 to December 2000 with a weighted average duration of approximately seven months. This was comprised of approximately 111,000 MGal of long positions and 13,000 MGal of short positions in such instruments. As of December 31, 1998, the Company held a notional quantity of approximately 177,000 MGal of NGL futures, swaps and options extending from January 1999 to December 1999 with a weighted average duration of approximately six months. This was comprised of approximately 129,000 MGal of long positions and 48,000 MGal of short positions in such instruments. As of December 31, 1999, the Company had purchased 25,000 barrels per month of NYMEX monthly average settlement $15.00 per barrel puts and sold 25,000 barrels per month of NYMEX monthly average settlement $17.00 calls to hedge a portion of the Company's equity production of natural gasoline, condensates and crude oil. The Company held no crude oil futures, swaps or options for settlement beyond 2000. As of December 31, 1999, the Company had purchased 125,000 barrels per month of OPIS Mt. Belvieu monthly average settlement $0.300 per gallon puts to hedge a portion of the Company's equity production of propane and butanes for 2000. As of December 31, 1999, the Company had purchased 70,000 barrels per month of OPIS Mt. Belvieu monthly average settlement $0.220 per gallon of purity ethane puts to hedge a portion of the Company's equity production of ethane for 2000. As of December 31, 1999, the Company held no NGL futures, swaps or options for settlement beyond 2000. As of December 31, 1999, the estimated fair value of the aforementioned crude oil and NGL options held by the Company was approximately $(194,000). Foreign Currency Derivative Market Risk 45 As part of its normal business, the Company enters into physical gas transactions payable in Canadian dollars. The Company enters into forward purchases and sales of Canadian dollars from time to time to fix the cost of its future Canadian dollar denominated natural gas purchase, sale, storage and transportation obligations. This is done to protect marketing margins from adverse changes in the U.S. and Canadian dollar exchange rate between the time the commitment for the payment obligation is made and the actual payment date of such obligation. As of December 31, 1999, the net notional value of such contracts was approximately $7.5 million in Canadian dollars, which approximates its fair market value. As of December 31, 1998, the net notional value of such contracts was approximately $11.0 million in Canadian dollars, which approximated its fair market value. NOTE 5 - DEBT - ------------- The following summarizes the Company's consolidated debt at the dates indicated (000s): December 31, ------------------ 1999 1998 -------- -------- Master Shelf and Senior Notes............ $332,000 $269,381 Variable rate Revolving Credit Facility.. 46,250 235,500 -------- -------- Total long-term debt.................... $378,250 $504,881 ======== ======== Revolving Credit Facility. The Revolving Credit Facility is with a syndicate of banks and provides for a maximum borrowing commitment of $250 million consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A, and a five- year $167 million Revolving Credit Facility, or Tranche B. At December 31, 1999, $46.3 million in total was outstanding on this facility. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's prime rate. The Company has the option to determine which rate will be used. The Company also pays a facility fee on the commitment. The interest rate spreads and facility fee are adjusted based on its debt to capitalization ratio and range from .75% to 2.00%. At December 31, 1999, the interest rate payable on the facility was 7.9%. The Company is required to maintain a total debt to capitalization ratio of not more than 60% through December 31, 2000 and of not more than 55% thereafter, and a senior debt to capitalization ratio of not more than 40% through December 31, 2001 and of not more than 35% thereafter. The agreement also requires a ratio of EBITDA, excluding certain non-recurring items, to interest and dividends on preferred stock as of the end of any fiscal quarter, for the four preceding fiscal quarters, of not less than 1.35 to 1.0 and increasing to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed and secured via a pledge of the stock of certain of its subsidiaries. The Company generally utilizes excess daily funds to reduce any outstanding balances on the Revolving Credit Facility and associated interest expense, and intends to continue such practice. Master Shelf Agreement. In December 1991, the Company entered into a Master Shelf Agreement with The Prudential Insurance Company of America. Amounts outstanding under the Master Shelf Agreement at December 31,1999 are as indicated in the following table (000s):
Interest Final Issue Date Amount Rate Maturity Principal Payments Due - ------------------- ------- --------- ----------------- ----------------------------------------------- October 27, 1992 $ 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003 December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity July 28, 1995 50,000 7.61% July 28, 2007 $10,000 on each of July 28, 2003 through 2007 -------- $150,000 ========
In April 1999, effective January 1999, the Company amended its agreement with Prudential to reflect the following provisions. The Company is required to maintain a current ratio, as defined therein, of at least .9 to 1.0, a minimum tangible net worth equal to the sum of $300 million plus 50% of consolidated net earnings earned from January 1, 1999 plus 75% of the net proceeds of any equity offerings after January 1, 1999, a total debt to capitalization ratio of not more than 60% through December 31, 2001 and of not more than 55% thereafter and a senior debt to capitalization ratio of 40% through March 2002 and 35% thereafter. This amendment also requires an EBITDA to interest ratio of not less than 1.75 to 1.0 increasing to a ratio of not less than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt ratio of not less 46 than 1.75 to 1.0 increasing to a ratio of not less than 5.50 to 1.0 by March 31, 2002. EBITDA in these calculations excludes certain non-recurring items. In addition, the Company is prohibited from declaring or paying dividends that in the aggregate exceed the sum of $50 million plus 50% of consolidated net income earned after June 30, 1995, or minus 100% of a net loss, plus the aggregate net cash proceeds received after June 30, 1995 from the sale of any stock. At December 31, 1999, approximately $25.6 million was available under this limitation. The Company financed the $8.3 million payment made in October 1999 with amounts available under the Revolving Credit Facility. Borrowings under the Master Shelf Agreement are guaranteed and secured via a pledge of the stock of certain of its subsidiaries. In June 1999, the Company prepaid approximately $33.3 million of notes outstanding under the Master Shelf Agreement with proceeds from the offering of the Subordinated Notes. 1995 Senior Notes. In 1995, the Company sold $42 million of Senior Notes, the 1995 Senior Notes, to a group of insurance companies with an interest rate of 8.16% per annum. In March 1999, the Company prepaid $15 million of the principal amount outstanding on the 1995 Senior Notes at par. These payments were financed by a portion of the $37 million Bridge Loan described below and by amounts available under the Revolving Credit Facility. The remaining principal amount outstanding of $27 million is due in a single payment in December 2005. The 1995 Senior Notes are guaranteed and secured via a pledge of the stock of certain of its subsidiaries. This facility contains covenants similar to the Master Shelf Agreement. In the second quarter of 1999 and in January 2000, the Company posted letters of credit for a total of approximately $11.8 million for the benefit of the holders of the 1995 Senior Notes. The Company is currently paying an annual fee of not more than .65% on the amounts outstanding on the Master Shelf Agreement and the 1995 Senior Notes. This fee will continue until the Company receives an implied investment grade rating on its senior secured debt. This fee is not assessed on the portion of the 1995 Senior Notes for which letters of credit are posted. 1993 Senior Notes. In 1993, the Company sold $50 million of 7.65% Senior Notes, the 1993 Senior Notes, to a group of insurance companies. Scheduled annual principal payments of $7.1 million on the 1993 Senior Notes were made on April 30 of 1997 and 1998. In February 1999, the Company prepaid $33.5 million of the total principal amounts outstanding of $35.6 million at par. These payments were financed by a portion of the $37 million Bridge Loan. The Company prepaid the remaining outstanding principal of $2.1 million in April 1999 with amounts available under the Revolving Credit Facility. In connection with the repayments on the Master Shelf Agreement, the 1995 Senior Notes and the 1993 Senior Notes, the Company incurred approximately $1.8 million of pre-tax yield maintenance and other charges. These charges are reflected as an extraordinary loss from early extinguishment of long-term debt in the second quarter of 1999. Bridge Loan. In February 1999, in order to finance prepayments of amounts outstanding on the 1993 and 1995 Senior Notes, the Company entered into a Bridge Loan agreement in the amount of $37 million with its agent bank. This facility was paid in full in April 1999 with proceeds from the sale of the Katy facility. Senior Subordinated Notes. In June 1999, the Company sold $155.0 million of Senior Subordinated Notes in a private placement with a final maturity of 2009 due in a single payment. The Subordinated Notes bear interest at 10% and were priced at 99.225% to yield 10.125%. These notes contain maintenance covenants which include limitations on debt incurrence, restricted payments, liens and sales of assets. The Subordinated Notes are unsecured and are guaranteed on a subordinated basis by certain of its subsidiaries. In November 1999, the Company exchanged the privately placed notes for registered publicly tradable notes under the same terms and conditions. The Company incurred approximately $5.0 million in offering commissions and expenses which have been capitalized and will be amortized over the term of the notes. Covenant Compliance. The Company was in compliance with all covenants in its debt agreements at December 31, 1999. Taking into account all the covenants contained in these agreements, the Company had approximately $110 million of available borrowing capacity at December 31, 1999. In the second quarter of 1999, the Company amended its various financing facilities providing for financial flexibility and covenant modifications and issued the Subordinated Notes. These amendments were needed given the depressed commodity pricing experienced in the industry in general at that time and the disappointing results at its Bethel Treating facility. The Company can provide no assurance that further amendments or waivers can be obtained in the future, if necessary, or that the terms would be favorable to it. To strengthen its credit ratings and to reduce its overall debt outstanding, the Company will continue to dispose of non-strategic assets and investigate alternative financing sources including the issuance of public debt, project-financing, joint ventures 47 and operating leases. Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 1999 (000s): 2000............................................ $ 0 2001............................................ 33,333 2002............................................ 8,333 2003............................................ 43,334 2004............................................ 81,250 Thereafter...................................... 212,000 -------- Total......................................... $ 378,250 ======== NOTE 6 - FINANCIAL INSTRUMENTS - ------------------------------ The estimated fair values of the Company's financial instruments have been determined by the Company using available market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amount that the Company could realize upon the sale or refinancing of such financial instruments. December 31, 1999 December 31, 1998 ------------------- ------------------- Carrying Fair Carrying Fair Value Value Value Value --------- -------- --------- -------- (000s) (000s) Cash and cash equivalents.. $ 14,062 $ 14,062 $ 4,400 $ 4,400 Trade accounts receivable.. 210,628 210,628 233,574 233,574 Accounts payable........... 240,235 240,235 245,315 245,315 Long-term debt............. 378,250 367,496 504,881 503,001 Risk management contracts.. $ - $ (1,668) $ - $ 2,281 The following methods and assumptions were used by the Company in estimating the fair value of its financial instruments: Cash and cash equivalents, trade accounts receivable and accounts payable Due to the short-term nature of these instruments, the carrying value approximates the fair value. Long-term debt The Company's long-term debt was primarily comprised of fixed rate facilities; for this portion, fair market value was estimated using discounted cash flows based upon the Company's current borrowing rates for debt with similar maturities. The remaining portion of the long-term debt was borrowed on a revolving basis which accrues interest at current rates; as a result, carrying value approximates fair value of the outstanding debt. Risk Management Contracts Fair value represents the amount at which the instrument could be exchanged in a current arms-length transaction. NOTE 7 - INCOME TAXES - --------------------- 48 The provision (benefit) for income taxes for the years ended December 31, 1999, 1998 and 1997 before the tax effect of the extraordinary item is comprised of (000s): 1999 1998 1997 -------- -------- ----- Current: Federal............................. $ 2,261 $ (5,696) $ 268 State............................... - - - -------- -------- ----- Total Current....................... 2,261 (5,696) 268 -------- -------- ----- Deferred: Federal............................. (11,004) (31,272) 448 State............................... (424) (1,450) 17 -------- -------- ----- Total Deferred...................... (11,428) (32,722) 465 -------- -------- ----- Total tax provision (benefit).. $ (9,167) $(38,418) $ 733 ======== ======== ===== The tax benefit allocated to the extraordinary charge was $628,000. Temporary differences and carry-forwards which give rise to the deferred tax liabilities (assets) at December 31, 1999 and 1998 net of the tax effect of the extraordinary item are as follows (000s):
1999 1998 --------- --------- Property and equipment......................................... $108,357 $133,054 Differences between the book and tax basis of acquired assets.. 13,439 14,386 -------- -------- Total deferred income tax liabilities......................... 121,796 147,440 -------- -------- Alternative Minimum Tax (AMT) credit carry-forwards.......... (23,389) (21,128) Net Operating Loss (NOL) carry-forwards...................... (62,442) (78,291) -------- -------- Total deferred income tax assets.............................. (85,831) (99,419) -------- -------- Net deferred income taxes..................................... $ 35,965 $ 48,021 ======== ========
The differences between the provision (benefit) for income taxes at the statutory rate and the actual provision (benefit) for income taxes before the tax effect of the extraordinary item for the years ended December 31, 1999, 1998 and 1997 are summarized as follows (000s): 49
1999 % 1998 % 1997 % -------- ----- --------- ----- ------ ----- Income tax (benefit) before effect of extraordinary item at statutory rate......... $(8,814) 35.0 $(36,968) 35.0 $ 777 35.0 State income taxes (benefit), net of federal benefit...................................... (353) 1.4 (1,450) 1.4 31 1.4 Other......................................... - - - - (75) (3.4) ------- ---- -------- ---- ----- ---- Total........................................ $(9,167) 36.4 $(38,418) 36.4 $ 733 33.0 ======= ==== ======== ==== ===== ====
At December 31, 1999 the Company had NOL carry-forwards for Federal and State income tax purposes and AMT credit carry-forwards for Federal income tax purposes of approximately $171.8 million and $23.4 million, respectively. These carry-forwards expire as follows (000s): Expiration Dates NOL AMT -------------------------------- -------- ------- 2008............................ $ 11,269 $ - 2009............................ 7,122 - 2010............................ 56,487 - 2011............................ 15,247 - 2012............................ 38,990 - 2018............................ 42,690 - No expiration................... - 23,389 -------- ------- Total........................ $171,805 $23,389 ======== ======= The Company believes that the NOL carry-forwards and AMT credit carry-forwards will be utilized prior to their expiration because they are substantially offset by existing taxable temporary differences reversing within the carry-forward period or are expected to be realized by achieving future profitable operations based on the Company's dedicated and owned reserves, past earnings history, projections of future earnings and current assets. NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES - ----------------------------------------------- McMurry Oil Company, et al. v. TBI Exploration, Inc., Mountain Gas Resources, Inc. and Wildhorse Energy Partners, LLC, District Court, Ninth Judicial District, Sublette County, Wyoming, Civil Action No. 5882. McMurry Oil Company and certain other producers (collectively, "McMurry") filed suit against TBI Exploration, Inc. ("TBI"), Mountain Gas Resources, Inc., our wholly-owned subsidiary ("Mountain Gas"), and Wildhorse Energy Partners, LLC ("Wildhorse"). The central dispute in this case concerns the ownership, nature and extent of a call on certain gas and the rights to match offers for gathering and/or purchasing gas (collectively the "Preferential Rights"). In November 1998, the court granted summary judgment in favor of McMurry as to the ownership of the Preferential Rights. In early 1999, McMurry, TBI and Wildhorse settled their claims and crossclaims and as a result TBI and Wildhorse were dismissed from the case. Trial on the liability phase of the litigation between McMurry and Mountain Gas was held in May 1999 and judgment was rendered against Mountain Gas in June 1999, assessing liability for intentional interference of business expectancies and opportunities and a finding that such interference caused McMurry to forego or delay entry into these opportunities and further, that Mountain Gas' assertion of ownership of Preferential Rights were false and thereby disparaged McMurry's title and rights. McMurry alleged damages in this matter of approximately $30 million. In February 2000, the parties reached a confidential settlement on all issues for substantially less than the amount claimed. The amount of the settlement is reflected in the Company's 1999 results of operations. Mountain Gas has not admitted any liability or fault in the settlement. Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources, Inc., United States District Court, District of Colorado, Civil Action No. 97-WM-1332. 50 Berco Resources, Inc. is a producer in the Temple/Tioga Area in North Dakota. Berco alleged that Amerada Hess engaged in unlawful monopolization under Section 2 of the Sherman Act and Section 7 of the Clayton Act by acquiring natural gas gathering and producing facilities owned by us. Berco also alleged that the Company, along with Amerada Hess, had conspired, through the purchase and sale of its facilities in the Temple/Tioga Area, to create a monopoly affecting an appreciable amount of interstate commerce in violation of Sections 1 and 2 of the Sherman Act. Berco sought an award against Amerada Hess and the Company of threefold the amount of damages actually sustained by it, in an amount to be determined at trial, and/or divestiture of the assets which Amerada Hess acquired, or an order restraining and enjoining the Company and Amerada Hess from violating the antitrust laws, and for costs, attorney fees and interest. In February 2000 a confidential settlement was reached between the Company and Berco for an amount which will not have a material impact on the Company's results of operations or financial position. Other The Company is involved in various other litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims will not, individually or in the aggregate have a material adverse effect on its financial position or results of operations. NOTE 9 - BUSINESS SEGMENTS AND RELATED INFORMATION - -------------------------------------------------- The Company operates in four principal business segments, as follows: Gas Gathering and Processing, Producing Properties, Marketing and Transmission, and these segments are separately monitored by management for performance against its internal forecast and are consistent with the Company's internal financial reporting package. These segments have been identified based upon the differing products and services, regulatory environment and the expertise required for these operations. The Gas Gathering and Processing segment connects producers' wells to its gathering systems for delivery to its processing or treating plants, processes the natural gas to extract NGLs and treats the natural gas in order to meet pipeline specifications. The results of the Black Lake facility and related reserves are included in this segment. The residue gas and NGLs extracted at the processing facilities are sold by the Marketing segment. The activities of the Producing Properties segment includes the exploration and development of certain oil and gas producing properties in basins where the Company's facilities are located. The majority of the gas and oil produced from these properties is sold by the Marketing segment. The Marketing segment buys and sells gas and NGLs nationwide and in Canada to or from a variety of customers. In addition, this segment also markets gas and NGLs produced by the Company's facilities. The operations associated with the Company's Katy Facility are included in the Marketing segment as are the Company's Canadian marketing operations (which are immaterial for separate presentation). Also included in the Marketing segment are gains and losses associated with the Company's equity hedging program of $(10.9) million, $7.5 million and $(527,000) for the years ended December 31, 1999, 1998 and 1997, respectively. The Transmission segment reflects the operations of the Company's MIGC and MGTC pipelines. The majority of the revenue presented in this segment is derived from transportation of residue gas. The following table sets forth the Company's segment information as of and for the years ended December 31, 1999, 1998 and 1997 (in 000s). Due to the Company's integrated operations, the use of allocations in the determination of business segment information is necessary. Intersegment revenues are valued at prices comparable to those of unaffiliated customers. 51
Gas Gathering Elim- and Producing Trans- inating Processing Properties Marketing mission Corporate Entries Total ----------- ---------- ----------- --------- ---------- ---------- ----------- Year ended December 31, 1999 Revenues from unaffiliated customers............................ $ 43,257 $ 2,895 $1,858,776 $ 7,498 $ 554 $ - $1,912,980 Interest income...................... 2 1 100 - 25,715 (25,435) 383 Other, net........................... 1,483 - (7,078) 413 2,543 - (2,639) Intersegment sales................... 389,928 26,137 88,379 16,235 56 (520,735) - -------- -------- ---------- ------- ------- --------- ---------- Total revenues....................... 434,670 29,033 1,940,177 24,146 28,868 (546,170) 1,910,724 -------- -------- ---------- ------- ------- --------- ---------- Product purchases.................... 288,668 2,029 1,939,400 - - (514,258) 1,715,839 Plant operating expense.............. 62,301 68 1,718 11,237 (1,478) (6,427) 67,419 Oil and gas exploration and production expense............... 535 8,705 (44) - - - 9,196 -------- -------- ---------- ------- ------- --------- ---------- Operating margin..................... $ 83,166 $ 18,231 $ (897) $12,909 $30,346 $ (25,485) $ 118,270 ======== ======== ========== ======= ======= ========= ========== Depreciation, depletion and amortization......................... 35,763 8,181 1,226 1,166 4,645 - 50,981 Interest expense..................... 33,156 Impairment of property & plant....... 1,158 Loss on sale of assets............... 29,802 Selling and administrative expense... 28,357 ---------- Loss before income taxes............. $ (25,184) ========== Identifiable assets.................. $606,424 $104,470 $ 73 $70,354 $18,837 $ - $ 800,158 ======== ======== ========== ======= ======= ========= ========== Gas Gathering Elim- and Producing Trans- inating Processing Properties Marketing mission Corporate Entries Total ----------- ---------- ---------- --------- ---------- ---------- ----------- Year ended December 31, 1998 Revenues from unaffiliated customers............................ $ 37,171 $ 2,089 $2,060,685 $ 4,952 $ 247 $ - $2,105,144 Interest income...................... 1 - 174 - 29,402 (28,486) 1,091 Other, net........................... (4,554) 703 13,086 659 959 - 10,853 Intersegment sales................... 431,511 18,263 81,473 12,365 232 (543,844) - -------- -------- ---------- ------- ------- --------- ---------- Total revenues....................... 464,129 21,055 2,155,418 17,976 30,840 (572,330) 2,117,088 -------- -------- ---------- ------- ------- --------- ---------- Product purchases.................... 325,414 1,431 2,127,907 82 - (540,531) 1,914,303 Plant operating expense.............. 73,724 36 7,460 9,944 (2,412) (3,399) 85,353 Oil and gas exploration and production expense............... 535 7,162 155 - 3 141 7,996 -------- -------- ---------- ------- ------- --------- ---------- Operating margin..................... $ 64,456 $ 12,426 $ 19,896 $ 7,950 $33,249 $ (28,541) $ 109,436 ======== ======== ========== ======= ======= ========= ========== Depreciation, depletion and amortization......................... 40,679 8,831 4,000 1,013 4,823 - 59,346 Interest expense..................... 33,616 Impairment of property & plant....... 108,447 (Gain) on sale of assets............. (16,478) Selling and administrative expense... 30,128 ---------- Loss before income taxes............. $ (105,623) ========== Identifiable assets.................. $577,782 $ 89,191 $ 118,661 $63,946 $17,780 $ - $ 867,360 ======== ======== ========== ======= ======= ========= ==========
52
Gas Gathering Elim- and Producing Trans- inating Processing Properties Marketing mission Corporate Entries Total ---------- ---------- ---------- ------- --------- --------- ---------- Year ended December 31, 1997 Revenues from unaffiliated customers............................ $ 33,279 $ 1,271 $2,354,276 $ 5,455 $ 4,718 $ - $2,398,999 Interest income...................... 18 - 1 - 27,414 (26,204) 1,229 Other, net........................... (7,835) 2,038 (13,617) 14 (283) - (19,683) Intersegment sales................... 539,173 17,328 51,410 7,419 46 (615,376) - -------- -------- ---------- ------- ------- --------- ---------- Total revenues....................... 564,635 20,637 2,392,070 12,888 31,895 (641,580) 2,380,545 -------- -------- ---------- ------- ------- --------- ---------- Product purchases.................... 385,323 1,228 2,363,914 90 - (604,125) 2,146,430 Plant operating expense.............. 72,456 192 7,514 8,209 (2,613) (7,645) 78,113 Oil and gas exploration and production expense............... 906 6,734 106 - 3 (35) 7,714 -------- -------- ---------- ------- ------- --------- ---------- Operating margin..................... $105,950 $ 12,483 $ 20,536 $ 4,589 $34,505 $ (29,775) $ 148,288 ======== ======== ========== ======= ======= ========= ========== Depreciation, depletion and amortization......................... 43,311 5,913 4,040 1,054 4,930 - 59,248 Interest expense..................... 27,474 Impairment of property & equip....... 34,615 (Gain) on sale of assets............. (4,715) Selling and administrative expense... 29,446 ---------- Income before income taxes........... $ 2,220 ========== Identifiable assets.................. $698,899 $104,744 $121,305 $48,541 $13,723 $ - $ 987,212 ======== ======== ========== ======= ======= ========= ==========
NOTE 10 - EMPLOYEE BENEFIT PLANS - -------------------------------- Profit Sharing Plan A discretionary profit sharing plan (a defined contribution plan) exists for all Company employees meeting certain service requirements. The Company may make annual discretionary contributions to the plan as determined by the Board of Directors and provides for a match of 50% of employee contributions on the first 4% of employee compensation contributed. Contributions are made to common/collective trusts for which Fidelity Management Trust Company acts as trustee. The discretionary contributions made by the Company were $1.7 million, $1.9 million and $1.9 million, for the years ended December 31, 1999, 1998 and 1997, respectively. The matching contributions were $541,000, $668,000 and $310,000 for the years ended December 31, 1999, 1998 and 1997, respectively. Key Employees' Incentive Stock Option Plan and Non-Employee Director Stock Option Plan Effective April 1987, the Board of Directors of the Company adopted a Key Employees' Incentive Stock Option Plan ("Key Employee Plan") and a Non-Employee Director Stock Option Plan ("Directors' Plan") that authorize the granting of options to purchase 250,000 and 20,000 shares of the Company's Common Stock, respectively. Under the plans, each of these options became exercisable as to 25% of the shares covered by it on the later of January 1, 1992 or one year from the date of grant, subject to the continuation of the optionee's relationship with the Company, and became exercisable as to an additional 25% of the covered shares on the later of each subsequent January 1 through 1995 or on each subsequent date of grant anniversary, subject to the same condition. Each of these plans terminated on the earlier of February 6, 2000 or the date on which all options granted under each of the plans have been exercised in full. The Company has entered into agreements committing the Company to loan certain employees an amount sufficient to exercise their options as each portion of their options vests. The Company will forgive such loans and associated accrued interest if the employee has been continuously employed by the Company for four years after the date of each loan increment. In January 1999, the Board of Directors 53 voted to extend the maturity for all such loans for officers still employed in January 1999, until January 2001. During 1996, under the terms of a severance agreement, the Company extended the maturity date of one former officer's loans to December 31, 2000. In addition, under the terms of a severance agreement, the loans of a former officer are being forgiven over the life of the original loan forgiveness schedule. As of December 31, 1999 and 1998, loans related to 75,000 and 81,250 shares of Common Stock, respectively, totaling $803,000 and $870,000, respectively, were outstanding under these terms. 1999 Non-Employee Directors' Stock Option Plan Effective March 1999, the Board of Directors of the Company adopted a 1999 Non- Employee Directors' Stock Option Plan ("1999 Directors' Plan") that authorize the granting of options to purchase 15,000 shares of the Company's Common Stock. During 1999, the Board approved grants totaling 15,000 options to several Board members. Under this plan, each of these options becomes exercisable as to 33 1/3% of the shares covered by it on each anniversary from the date of grant. This plan terminates on the earlier of March 12, 2009 or the date on which all options granted under each of the plans have been exercised in full. 1993, 1997 and 1999 Stock Option Plans The 1993 Stock Option Plan ("1993 Plan"), the 1997 Stock Option Plan ("1997 Plan") and the 1999 Stock Option Plan ("1999 Plan") became effective on May 24, 1993, May 21, 1997 and on May 21, 1999, respectively, after approvals by the Company's stockholders. Each plan is intended to be an incentive stock option plan in accordance with the provisions of Section 422 of the Internal Revenue Code of 1986, as amended. The Company has reserved 1,000,000 shares of Common Stock for issuance upon exercise of options under each of the 1993 Plan and the 1997 Plan and 750,000 shares of Common Stock for issuance upon exercise of options under the 1999 Plan. The 1993 Plan, the 1997 Plan and the 1999 Plan will terminate on the earlier of March 21, 2003, May 21, 2007 and May 21, 2009, respectively, or the date on which all options granted under each of the plans have been exercised in full. Under each of the plans, the Board of Directors of the Company determines and designates from time to time those employees of the Company to whom options are to be granted. If any option terminates or expires prior to being exercised, the shares relating to such option are released and may be subject to re-issuance pursuant to a new option. The Board of Directors has the right to, among other things, fix the price, terms and conditions for the grant or exercise of any option. The purchase price of the stock under each option shall be the average closing price for the ten days prior to the grant. Under the 1993 Plan, options granted vest 20% each year on the anniversary of the date of grant commencing with the first anniversary. Under the 1997 and 1999 Plans, the Board of Directors has the authority to set the vesting schedule from 20% per year to 33 1/3% per year. Under each of the plans, the employee must exercise the option within five years of the date each portion vests. In March 1999, certain officers of the Company were granted a total of 300,000 options, which vest ratably over the next three years under the 1997 Plan. The exercise price of $5.51 was determined by using the average stock price for the ten trading days prior to the grant date. In exchange, these officers were required to relinquish a total of 246,200 vested and unvested options at prices ranging from $18.63 to $34.00 per share. $5.40 Stock Option Plan In April 1987 and amended in February 1994, Western Gas Processes, Ltd. adopted an employee option plan ("$5.40 Plan") that authorized granting options to employees to purchase 483,000 common units in the Partnership. Pursuant to the Restructuring, the Company assumed the Partnership's obligation under the employee option plan. The plan was amended upon the Restructuring to allow each holder of existing options to exercise such options and acquire one share of Common Stock for each common unit they were originally entitled to purchase. The exercise price and all other terms and conditions for the exercise of such options issued under the amended plan were the same as under the plan, except that the Restructuring accelerated the time upon which certain options may be exercised. All options under the plan were either exercised or forfeited on or before May 31, 1997. The Company has entered into agreements committing the Company to loan to certain employees an amount sufficient to exercise their options, provided that the Company will not loan in excess of 25% of the total amount available to the employee in any one year. In accordance with the agreements, the Company forgave the majority of such loans and associated accrued interest on July 2, 1997. Under the terms of a severance agreement, the Company extended the maturity date of one former officer's loans to December 31, 2000. As of December 31, 1999 and 1998, loans related to 15,000 shares of Common Stock in each year, respectively, totaling $81,000, were outstanding under these terms. The following table summarizes the number of stock options exercisable and available for grant under the Company's benefit plans: 54
Key 1999 $5.40 Employee Directors' Directors' Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan ---------- ---------- ---------- ---------- --------- --------- --------- Exercisable: December 31, - - - - 407,787 47,240 - 1999............ December 31, - 75,000 13,500 - 562,138 26,250 - 1998............ December 31, - 75,000 12,250 - 448,171 - - 1997............ Available for Grant: December 31, - - - - - 350,000 714,734 1999............ December 31, - 31,250 1,250 - 96,609 763,400 - 1998............ December 31, - 31,250 1,250 - 9,382 828,900 - 1997............
55 The following table summarizes the stock option activity under the Company's benefit plans:
Number of Shares ---------------------------------------------------------------------------------------- 1999 Per Share $ 5.40 Key Employee Directors' Directors' Price Range Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan ------------ -------- ------------ ---------- ------------ ---------- --------- --------- Balance 12/31/96 33,148 75,000 13,500 - 993,203 - - Granted $17.75-24.00 - - - - 64,654 171,100 - Excercised $ 5.40-23.50 (32,077) - - - (5,225) - - Forfeited or $ 5.40-34.13 (1,071) - - - (69,302) - - canceled ---------------------------------------------------------------------------------------- Balance 12/31/97 - 75,000 13,500 - 983,330 171,100 - Granted $ 19.28 - - - - 40,511 106,500 - Excercised $ 15.83 - - - - (1,556) - - Forfeited or $19.19-21.78 - - - - (129,809) (41,000) - canceled ---------------------------------------------------------------------------------------- Balance 12/31/98 - 75,000 13,500 - 892,476 236,600 - Granted $ 4.59-17.11 - - - 15,000 - 505,500 35,266 Excercised $10.71-16.50 - - (8,500) - (1,938) (3,300) - Forfeited or $ 4.59-35.50 - (75,000) (5,000) - (324,664) (92,100) - canceled ---------------------------------------------------------------------------------------- Balance 12/31/99 - - - 15,000 565,874 646,700 35,266 ========================================================================================
The following table summarizes the weighted average option exercise price information under the Company's benefit plans:
1999 Key Employee Directors' Directors' $5.40 Plan Plan Plan Plan 1993 Plan 1997 Plan 1999 Plan ---------- ------------ ----------- ---------- --------- ---------- --------- Balance 12/31/96 $ 5.40 $ 30.23 $ 14.13 $ - $ 21.31 $ - $ - Granted - - - - 19.71 19.63 - Excercised 5.40 - - - 16.91 - - Forfeited or canceled 5.40 - - - 25.54 - - ---------- ------------ ----------- ---------- --------- ---------- --------- Balance 12/31/97 - 30.23 14.13 - 20.93 19.63 - Granted - - - - 19.28 11.69 - Excercised - - - - 14.78 - - Forfeited or canceled - - - - 21.97 19.16 - ---------- ------------ ----------- ---------- --------- ---------- --------- Balance 12/31/98 - 30.23 14.13 - 20.71 16.15 - Granted - - - 5.51 - 5.15 13.58 Excercised - - 10.71 - 14.53 11.64 - Forfeited or canceled - 30.23 19.94 - 22.79 15.11 - ---------- ------------ ----------- ---------- --------- ---------- --------- Balance 12/31/99 $ - $ - $ - $ 5.51 $ 19.54 $ 7.72 $ 13.58 ========== ============ =========== ========== ========= ========== =========
SFAS No. 123 encourages companies to record compensation expense for stock-based compensation plans at fair value. As permitted under SFAS No. 123, the Company has elected to continue to measure compensation costs for such plans as prescribed by APB No. 25. SFAS No. 123 requires pro forma disclosures for each year a statement of operations is 56 presented. Such information was only calculated for the options granted under the 1993 Plan, the 1997 Plan, the 1999 Plan and the 1999 Directors' Plan, as there were no grants under any other plans. The weighted average fair value of options granted under the 1997 Plan was $9.25, $1.00 and $12.66 for the years ended December 31, 1999, 1998 and 1997, respectively. The weighted average fair value of options granted under the 1999 Plan was $6.82 for the year ended December 31, 1999. The weighted average fair value of options granted under the 1999 Directors' Plan was $9.12 for the year ended December 31, 1999. The weighted average fair value of options granted was estimated using the Black- Scholes option-pricing model with the following assumptions:
1999 1999 Plan 1997 Plan Directors' Plan --------------- -------------------------- --------------- 1999 1999 1998 1997 1999 --------------- ------ ---------- ------ --------------- Risk-free interest rate......... 6.96% 6.96% 5.3% 6.1% 6.96% Expected life (in years)........ 5 5 6 10 5 Expected volatility............. 51% 51% 45% 42% 51% Expected dividends (quarterly).. $ .05 $ .05 $ .05 $ .05 $ .05
Had compensation expense for the Company's 1999, 1998 and 1997 grants for stock- based compensation plans been determined consistent with the fair value method under SFAS No. 123, the Company's net income (loss), income (loss) attributable to common stock, earnings (loss) per share of common stock and earnings (loss) per share of common stock - assuming dilution would approximate the pro forma amounts below (000s, except per share amounts):
1999 1998 1997 ------------------------ ------------------------ ------------------------ As Reported Pro forma As Reported Pro forma As Reported Pro forma ------------ ---------- ------------ ---------- ------------ ---------- Net income (loss).................... $(17,124) $(18,589) $(67,205) $(67,997) $ 1,487 $ 941 Net income (loss) attributable to common stock........................ (27,563) (29,028) (77,644) (78,436) (8,952) (9,498) Earnings (loss) per share of common stock............................... (.86) (.90) (2.42) (2.44) (.28) (.30) Earnings (loss) per share of common stock - assuming dilution.......... $ (.86) $ (.90) $ (2.42) $ (2.44) $ (.28) $ (.30)
The 1993 Plan dictates that the options granted vest 20% each year on the anniversary of the date of grant commencing with the first anniversary. The Board of Directors has the authority to set the vesting schedule from 20% per year to 33 1/3% per year for the 1997 and 1999 Plans. As a result, no compensation expense, as defined under SFAS No. 123, is recognized in the year options are granted. In addition, the fair market value of the options at grant date is amortized over the appropriate vesting period for purposes of calculating compensation expense. NOTE 11 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - ---------------------------------------------------------------------- (UNAUDITED): - ------------ Costs The following tables set forth capitalized costs at December 31, 1999, 1998 and 1997 and costs incurred for oil and gas producing activities for the years ended December 31, 1999, 1998 and 1997 (000s): 57
1999 1998 1997 --------- --------- --------- Capitalized costs: Proved properties............................................... $ 74,594 $110,090 $134,102 Unproved properties............................................. 42,928 33,255 18,464 -------- -------- -------- Total............................................................ 117,522 143,345 152,566 Less accumulated depletion...................................... (23,003) (58,994) (61,766) -------- -------- -------- Net capitalized costs............................................ $ 94,519 $ 84,351 $ 90,800 ======== ======== ======== The Company's share of Redman Smackover's net capitalized costs.. $ - $ - $ 3,845 ======== ======== ======== Costs incurred: Acquisition of properties Proved.......................................................... $ - $ 2,174 $ 7,499 Unproved........................................................ 11,675 22,633 10,457 Development costs................................................ 20,973 23,208 13,134 Exploration costs................................................ 5,148 4,177 1,322 -------- -------- -------- Total costs incurred............................................. $ 37,796 $ 52,192 $ 32,412 ======== ======== ======== The Company's share of Redman Smackover's costs incurred......... $ - $ 72 $ 236 ======== ======== ========
Results of Operations The results of operations for oil and gas producing activities, excluding corporate overhead and interest costs, for the years ended December 31, 1999, 1998 and 1997 are as follows (000s):
1999 1998 1997 --------- --------- --------- Revenues from sale of oil and gas: Sales................................................ $ 2,081 $ 2,592 $ 5,970 Transfers............................................ 30,537 23,188 25,571 -------- -------- -------- Total.............................................. 32,618 25,780 31,541 Production costs...................................... (8,002) (6,611) (6,384) Exploration costs (1,492) (1,599) (1,439) Depreciation, depletion and amortization.............. (11,536) (11,749) (11,549) Impairment of oil and gas properties.................. - (16,528) (19,615) Income tax benefit (expense).......................... (3,921) (3,690) 2,792 -------- -------- -------- Results of operations................................. $ 7,667 $ (7,017) $ (4,654) ======== ======== ======== The Company's share of Redman Smackover's operations.. $ - $ 421 $ 1,265 ======== ======== ========
Reserve Quantity Information Reserve 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. Estimates of economically recoverable reserves and of future net cash flows expected therefrom prepared by different engineers or by the 58 same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations. The following table sets forth information for the years ended December 31, 1999, 1998 and 1997 with respect to changes in the Company's proved reserves, all of which are in the United States. The Company has no significant undeveloped reserves.
Natural Crude Gas Oil (MMcf) (MBbls) -------- ------- Proved reserves: December 31, 1996.......................................... 96,031 843 Revisions of previous estimates............................ (18,132) (74) Extensions and discoveries................................. 113,251 191 Purchases of reserves in place............................. 34,588 - Production................................................. (13,142) (154) ------- ---- December 31, 1997.......................................... 212,596 806 Revisions of previous estimates............................ (28,617) (200) Extensions and discoveries................................. 43,248 66 (Sales) Purchases of reserves in place, net................ (31,020) - Production................................................. (14,511) (117) ------- ---- December 31, 1998.......................................... 238,930 555 Revisions of previous estimates............................ 13,152 (2) Extensions and discoveries................................. 45,688 14 (Sales)Purchases of reserves in place...................... (7,964) (126) Production................................................. (17,988) (112) ------- ---- December 31, 1999.......................................... 271,818 329 ======= ==== The Company's share of Redman Smackover's proved reserves: December 31, 1997.......................................... 10,218 - ======= ==== December 31, 1998.......................................... - - ======= ==== December 31, 1999.......................................... - - ======= ====
Standardized Measures of Discounted Future Net Cash Flows Estimated discounted future net cash flows and changes therein were determined in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying year end prices of oil and gas relating to the Company's proved reserves to the year end quantities of those reserves. 59 The assumptions used to compute estimated future net revenues do not necessarily reflect the Company's expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company's control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company's proved oil and gas reserves. Permanent differences in oil and gas-related tax credits and allowances are recognized. An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Information with respect to the Company's estimated discounted future cash flows from its oil and gas properties for the years ended December 31, 1999, 1998 and 1997 is as follows (000s):
1999 1998 1997 ---------- ---------- ---------- Future cash inflows......................................................... $ 419,104 $ 345,217 $ 352,491 Future production costs..................................................... (121,129) (108,457) (118,056) Future development costs.................................................... (57,999) (46,066) (28,803) Future income tax expense................................................... (44,130) (33,749) (32,614) --------- --------- --------- Future net cash flows....................................................... 195,846 156,945 173,018 10% annual discount for estimated timing of cash flows...................... (82,919) (59,068) (73,445) --------- --------- --------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves............................................... $ 112,927 $ 97,877 $ 99,573 ========= ========= ========= The Company's share of Redman Smackover's standardized measure of discounted future net cash flows relating to proved oil and gas reserves.. $ - $ - $ 6,326 ========= ========= =========
60 Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 1999, 1998 and 1997 are as follows (000s):
1999 1998 1997 -------- -------- --------- January 1............................................. $ 97,877 $ 99,573 $ 110,717 Sales and transfers of oil and gas produced, net of production costs.................................... (24,616) (19,170) (25,157) Net changes in prices and production costs related to future production................................ 19,569 367 (146,968) Development costs incurred during the period......... 20,973 23,208 13,134 Changes in estimated future development costs........ (29,725) (33,723) (26,875) Changes in extensions and discoveries................ 26,597 23,336 158,314 Revisions of previous quantity estimates............. 9,028 35,438 (47,859) Purchases (sales) of reserves in place............... (5,842) (38,251) 47,867 Accretion of discount................................ 9,788 9,957 11,072 Net change in income taxes........................... (10,381) (1,134) 5,256 Other, net........................................... - (1,724) 72 -------- -------- --------- December 31........................................... $113,268 $ 97,877 $ 99,573 ======== ======== ========= NOTE 12 - QUARTERLY RESULTS OF OPERATIONS (UNAUDITED): - ------------------------------------------------------ The following summarizes certain quarterly results of operations (000s, except per share amounts): Earnings (Loss) Per Share of Net Earnings (Loss) Common Stock - Operating Gross Income Per Share of Assuming Revenues Profit(a) (Loss) Common Stock Dilution --------- --------- --------- -------------- --------------- 1999 quarter ended: March 31............................................. $ 429,360 $ 13,259 $ (2,176) $ (.15) $ (.15) June 30.............................................. 456,302 (6,449) (14,764) (.54) (.54) September 30......................................... 505,550 16,794 1,058 (.05) (.05) December 31.......................................... 519,512 13,883 (1,242) (b) (.12) (.12) --------- -------- --------- -------------- -------------- $1,910,724 $ 37,487 $ (17,124) $ (.86) $ (.86) ========== ======== ========= ============== ============== 1998 quarter ended: March 31............................................. $565,504 $ 36,394 $ 13,185 $ .33 $ .33 June 30.............................................. 500,945 10,876 (2,609) (.16) (.16) September 30......................................... 516,253 8,301 (4,653) (.23) (.23) December 31.......................................... 534,386 10,457 (73,128) (c) (2.36) (2.36) --------- -------- --------- -------------- -------------- $2,117,088 $ 66,028 $ (67,205) $(2.42) $(2.42) ========== ========= ========= ============== ==============
(a) Excludes selling and administrative, interest and income tax expenses and loss on the impairment of property and equipment. (b) Includes a pre-tax, non-cash expense resulting from the evaluation of property and equipment in accordance with SFAS No. 121 of $1.2 million. (c) Includes a pre-tax, non-cash expense resulting from the evaluation of property and equipment in accordance with SFAS No. 121 of $108.5 million. 61 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are omitted because the Company will file a definitive proxy statement (the "Proxy Statement") pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such Items will be included in the definitive proxy statement to be so filed for the Company's annual meeting of stockholders scheduled for May 19, 2000 and is hereby incorporated by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: (1) Financial Statements: Reference is made to page 30 for a list of all financial statements filed as a part of this report. (2) Financial Statement Schedules: None required. (3) Exhibits: 3.1 Certificate of Incorporation of Western Gas Resources, Inc. (Filed as exhibit 3.1 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference). 3.2 Certificate of Amendment to the Certificate of Incorporation of Western Gas Resources, Inc. (Filed as exhibit 3.2 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-31604 and incorporated herein by reference). 3.3 Certificate of Designation of 7.25% Cumulative Senior Perpetual Convertible Preferred Stock of the Company (Filed as exhibit 3.5 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077 dated November 14, 1991 and incorporated herein by reference). 3.4 Certificate of Designation of $2.28 Cumulative Preferred Stock of the Company (Filed as exhibit 3.6 to Western Gas Resources, Inc.'s Registration Statement of Form S-1, Registration No. 33-53786 dated November 12, 1992 and incorporated herein by reference). 3.5 Certificate of Designation of the $2.625 Cumulative Convertible Preferred Stock of the Company (Filed under cover of Form 8-K dated February 24, 1994 and incorporated herein by reference). 4.1 Western Gas Resources, Inc., 1999 Stock Option Plan (filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-8, Registration No. 33-95255 dated January 24, 2000) and incorporated herein by reference. 4.2 Western Gas Resources, Inc., Non-Employee Director Stock Option Plan (filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-8, Registration No. 33-95259 dated January 24, 2000) and incorporated herein by reference. 4.3 Western Gas Resources, Inc., 10% Senior Subordinated Notes due 2009 (filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-4, Registration No. 33-333-86881 dated September 10, 1999) and incorporated herein by reference. 4.4 Western Gas Resources, Inc., Exchange Offer (filed as an exhibit to Western Gas Resources Inc.'s Registration Statement on Form S-3, Registration No. 33-86881 dated April 19, 1999) and incorporated herein by reference. 62 10.1 Restated Profit-Sharing Plan and Trust Agreement of Western Gas Resources, Inc. (Filed as exhibit 10.8 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference). 10.2 Western Gas Resources, Inc. Key Employees' Incentive Stock Option Plan (Filed as exhibit 10.13 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference). 10.3 Registration Rights Agreement among Western Gas Resources, Inc., WGP, Inc., Heetco, Inc., NV, Dean Phillips, Inc., Sauvage Gas Company and Sauvage Gas Service, Inc. (Filed as exhibit 10.14 to Western Gas Resources, Inc.'s Registration Statement on Form S-4, Registration No. 33-39588 dated March 27, 1991 and incorporated herein by reference). 10.4 Amendment No. 1 to Registration Rights Agreement as of May 1, 1991 between Western Gas Resources, Inc., Bill Sanderson, WGP, Inc., Dean Phillips, Inc., Heetco, Inc., NV, Sauvage Gas Company and Sauvage Gas Service, Inc. (Filed as exhibit 4.2 to Western Gas Resources, Inc.'s Form 10-Q for the quarter ended June 30, 1991 and incorporated herein by reference). 10.5 Second Amendment and First Restatement of Western Gas Processors, Ltd. Employees' Common Units Option Plan (Filed as exhibit 10.6 to Western Gas Resources, Inc.'s Registration Statement on Form S-1, Registration No. 33-43077 dated November 14, 1991 and incorporated herein by reference). 10.6 Agreement to provide loans to exercise key employees' common stock options (Filed as exhibit 10.26 to Western Gas Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 1991 and incorporated herein by reference). 10.7 Agreement to provide loans to exercise employees' common stock options (Filed as exhibit 10.27 to Western Gas Resources, Inc.'s Annual Report on Form 10-K for the fiscal year ended December 31, 1991 and incorporated herein by reference). 10.8 Note Purchase Agreement (without exhibits) dated as of April 1, 1993 by and between the Company and the Purchasers for $50,000,000, 7.65% Senior Notes Due April 30, 2003 (Filed as exhibit 10.48 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1993 and incorporated herein by reference). 10.9 General Partnership Agreement (without exhibits), dated August 10, 1993 for Westana Gathering Company by and between Western Gas Resources-Oklahoma, Inc. (a subsidiary of the Company) and Panhandle Gathering Company (Filed as exhibit 10.50 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1993 and incorporated herein by reference). 10.10 Amendment to General Partnership Agreement dated August 10, 1993 by and between Western Gas Resources-Oklahoma, Inc. (a subsidiary of the Company) and Panhandle Gathering Company (Filed as exhibit 10.51 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1993 and incorporated herein by reference). 10.11 Amendment No. 1 to Note Purchase Agreement dated as of August 31, 1993 by and among the Company and the Purchasers (Filed as exhibit 10.61 to Western Gas Resources, Inc.'s Form 10-Q for the nine months ended September 30, 1993 and incorporated herein by reference). 10.12 Amendment No. 2 to Note Purchase Agreement dated as of August 31, 1994 by and among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit 10.68 to Western Gas Resources, Inc.'s Form 10-Q for the nine months ended September 30, 1994 and incorporated herein by reference). 10.13 Amendment No. 3 to Note Purchase Agreement as of March 22, 1995 by and among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit 10.38 to Western Gas Resources, Inc.'s Form 10-Q for the three months ended March 31, 1995 and incorporated herein by reference). 10.14 Form of Employment Agreement by and between Western Gas Resources, Inc. and certain Executive Officers (Filed as exhibit 10.40 to Western Gas Resources, Inc.'s Form 10-Q for the three months ended March 31, 1995 and incorporated herein by reference). 63 10.15 Amendment No. 4 to Note Purchase Agreements as of July 14, 1995 by and among Western Gas Resources, Inc. and the Purchasers (Filed as exhibit 10.43 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1995 and incorporated herein by reference). 10.16 Second Amended and Restated Master Shelf Agreement effective January 31, 1996 by and between Western Gas Resources, Inc. and Prudential Company of America (Filed as exhibit 10.49 to Western Gas Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 10.17 Fourth Amendment to First Restated Loan Agreement (Revolver) dated November 29, 1995 by and among Western Gas Resources, Inc. and NationsBank, as agent, and the Lenders (Filed as exhibit 10.51 to Western Gas Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 10.18 Senior Note Purchase Agreement dated November 29, 1995 by and among Western Gas Resources, Inc. and the Purchasers identified therein (Filed as exhibit 10.52 to Western Gas Resources, Inc.'s Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 10.19 Loan Agreement dated May 30, 1997 among Western Gas Resources, Inc. and NationsBank of Texas, N.A. as agent, Bank of America National Trust and Savings Association as Co-agent and Certain Banks as Lenders (Revolver) (Filed as exhibit 10.40 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1996 and incorporated herein by reference). 11.1 Statement regarding computation of per share earnings. 12.1 Amended and Restated Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on February 12, 1999. (Filed as exhibit 12.1 to Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 12.2 Second Amendment dated February 17, 1999 to Credit Agreement by and among Western Gas Resources, Inc. and NationsBank N.A., successor to NationsBank of Texas, N.A., by merger, and the Lenders identified in the Original Agreement dated May 30, 1997. (Filed as exhibit 12.2 to Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 12.3 Offer to Acquire Notes dated February 12, 1999 by and between Western Gas Resources, Inc. and CIGNA Investments, Inc., Royal Maccabees Life Insurance Company, The Canada Life Assurance Company, and Canada Life Insurance Company of America, original Purchasers under the Note Purchase Agreement dated as of April 1, 1993 by and between Company and Purchasers for $50,000,000, 7.65% Senior Notes due April 30, 2003. (Filed as exhibit 12.3 to Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 12.4 Offer to Acquire Notes dated February 12, 1999 by and between Western Gas Resources, Inc. and MONY Life Insurance Company, one of the original Purchasers under the Note Purchase Agreement dated as of November 29, 1995 by and between Company and Purchasers for $42,000,000, 8.02% Senior Notes due December 1, 2005. (Filed as exhibit 12.4 to Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 12.5 Loan Agreement dated February 17, 1999 by and among Western Gas Resources, Inc. and NationsBank, N.A., for $37,000,000 Bridge Loan. (Filed as exhibit 12.5 to Western Gas Resources, Inc. Form 10-K for the year ended December 31, 1998 and incorporated herein by reference). 21.1 List of Subsidiaries of Western Gas Resources, Inc. 23.1 Consent of PricewaterhouseCoopers LLP 23.2 Consent of Netherland, Sewell & Associates, Inc. 27 Financial Data Schedule (b) Reports on Form 8-K: Western Gas Resources, Inc., filed a report on 8-K on May 10, 1999 announcing the sale of the Katy Storage Facility in Texas and financial information related thereto, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-K on May 25, 1999 announcing an agreement for the sale of its assets in the MiVida facility in Texas, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-K on May 27, 1999 announcing the offering of $150,000,000 in Senior Subordinated Notes due in 2009, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-KA on July 7, 1999 amending certain previously filed financial information, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-K on September 22, 1999 announcing the appointment of Lanny F. Outlaw as Chief Executive Officer and President, and Brion G. Wise as Chairman of the Board, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-K on January 2, 2000 announcing the sale of its interest in the Black Lake Facility in Louisiana and financial information related thereto, which is incorporated herein by reference. Western Gas Resources, Inc., filed a report on 8-K on February 22, 2000 announcing the stock sale of its wholly-owned subsidiary Western Gas Resources - California, Inc., and a report on the McMurry Oil Company, et al., v. TBI Exploration, Inc., Mountain Gas Resources, Inc., and Wildhorse Energy Partners, LLC, District Court, Ninth Judicial District, Sublette County, Wyoming, Civil Action No. 5882, which is incorporated herein by reference. (c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above. 64 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, in the City of Denver, State of Colorado on March 13, 2000. WESTERN GAS RESOURCES, INC. --------------------------- (Registrant) By: /S/ Lanny F. Outlaw ------------------- Lanny F. Outlaw Chief Executive Officer, President and Director Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /S/ Brion G. Wise Chairman of the Board March 13, 2000 - ----------------------- Brion G. Wise Vice Chairman of the Board March 13, 2000 /S/ W. L. Stonehocker and Director - ----------------------- Walter L. Stonehocker /S/ B. M. Sanderson Director March 13, 2000 - ----------------------- Bill M. Sanderson /S/ Richard B. Robinson Director March 13, 2000 - ----------------------- Richard B. Robinson /S/ Dean Phillips Director March 13, 2000 - ----------------------- Dean Phillips S/ Ward Sauvage Director March 13, 2000 - ----------------------- Ward Sauvage /S/ James A. Senty Director March 13, 2000 - ----------------------- James A. Senty /S/ Joseph E. Reid Director March 13, 2000 - ----------------------- Joseph E. Reid Vice President - Finance (Principal Financial and /S/ William J. Krysiak Accounting Officer) March 13, 2000 - ----------------------- William J. Krysiak 65 EX-11.1 2 COMPUTATION OF PER SHARE EARNINGS EXHIBIT 11.1 WESTERN GAS RESOURCES, INC. COMPUTATION OF PER SHARE EARNINGS DECEMBER 31, 1999
Weighted Average Shares Of Earnings Common Per Share Stock Net Of Common Outstanding Income Stock ------------- ------------ ----------- Net income........................................................... $(17,124,000) Weighted average shares of common stock outstanding.................. 32,150,769 Less preferred stock dividends: $2.28 cumulative preferred stock.................................... (3,194,000) $2.625 cumulative convertible preferred stock....................... (7,245,000) ------------ ------------ 32,150,769 $(27,563,000) ============ ============ Basic earnings per share of common stock............................. $ (.86) =========== (Assume no conversion of anti-dilutive convertible preferred stock) Assume exercise of common stock equivalents: Weighted average shares of common stock outstanding................. 32,150,769 (Anti-dilutive common stock equivalents are not used in this calculation) 32,150,769 $(27,563,000) ========== ============ Fully diluted earnings per share of common stock..................... $ (.86) ===========
EX-21.1 3 LIST OF SUBSIDIARIES OF WESTERN GAS RESOURCES, INC EXHIBIT 21.1 Subsidiaries of Western Gas Resources, Inc. Name of Subsidiary Relationship - ------------------ ------------
1) MIGC, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 2) MGTC, Inc. Wholly-owned subsidiary of MIGC, Inc. 3) Western Gas Resources - Texas, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 4) Western Gas Resources - Oklahoma, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 5) Mountain Gas Resources, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 6) Western Power Services, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 7) Pinnacle Gas Treating, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 8) WGR Canada, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 9) Lance Oil & Gas Company, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 10) Mountain Gas Transportation, Inc. Wholly-owned subsidiary of Mountain Gas Resources, Inc. 11) Western Gas Wyoming, L.L.C. Wholly-owned subsidiary of Western Gas Resources, Inc. 12) Green River Gathering Company A joint venture between Western Gas Resources, Inc. and Mountain Gas Resources, Inc. 13) Westana Gathering Company A general partnership with Western Gas Resources, Inc., as general partner
EX-23.1 4 CONSENT OF PRICEWATERHOUSECOOPERS LLP EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 33-86881) and in the Registration Statements on Form S-8 (No. 33-95255 and No. 333-95259) of Western Gas Resources, Inc. of our report dated March 13, 2000 appearing on page 32 of this Form 10-K. Pricewaterhousecoopers LLC Denver, Colorado March 13, 2000 EX-23.2 5 CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. [NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD] EXHIBIT 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to the use of our name and information related to reserves in the Annual Report on Form 10-K of Western Gas Resources, Inc. and Subsidiaries (the "Company") for the year ended December 31, 1999. NETHERLAND, SEWELL & ASSOCIATES, INC. By: /s/ Clarence M. Netherland --------------------------------------- Clarence M. Netherland Chairman Dallas, Texas March 9, 2000 EX-27 6 FINANCIAL DATA SCHEDULE
5 1,000 12-MOS DEC-31-1999 DEC-31-1999 14,062 0 196,739 0 35,228 273,155 952,398 (260,081) 1,049,486 285,528 378,250 0 416 3,220 346,107 1,049,486 1,847,885 1,910,724 1,715,839 1,935,908 220,069 0 33,156 (25,184) (9,167) (16,017) 0 (1,107) 0 (17,124) (.86) (.86)
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