-----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, KUn2qohIzg3SyFf+ic6vOZY9CPbK66w7a6IDebeh2eDJgvn0fGVmx6MGmqVpnMUh vWGznBV/438goeSJg3jXsQ== 0000927356-98-000341.txt : 19980319 0000927356-98-000341.hdr.sgml : 19980319 ACCESSION NUMBER: 0000927356-98-000341 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980318 SROS: NYSE 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: 98568121 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, 1997 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 February 27, 1998 was $338,659,119. 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 22, 1998. 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............................................. 4 Gas Gathering, Processing, Storage and Transmission.............. 5 Significant Acquisitions, Projects and Dispositions.............. 7 Marketing........................................................ 10 Producing Properties............................................. 12 Competition...................................................... 13 Regulation....................................................... 13 Employees........................................................ 13 3. Legal Proceedings.................................................... 14 4. Submission of Matters to a Vote of Security Holders.................. 14 II. 5. Market for Registrant's Common Equity and Related Stockholder Matters 14 6. Selected Financial Data.............................................. 15 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................. 16 8. Financial Statements and Supplementary Data.......................... 26 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................... 55 III. 10. Directors and Executive Officers of the Registrant................... 55 11. Executive Compensation............................................... 55 12. Security Ownership of Certain Beneficial Owners and Management....... 55 13. Certain Relationships and Related Transactions....................... 55 IV. 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 55
2 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES GENERAL Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and processor and energy marketer providing a full range of services to its customers from the wellhead to the delivery point. The Company designs, constructs, owns and operates natural gas gathering, processing, treating and storage facilities in major gas-producing basins in the Rocky Mountain, Mid- Continent, Gulf Coast and Southwestern regions of the United States. The Company connects producers' wells to its gathering systems for delivery to its processing or treating plants, processes the natural gas to extract natural gas liquids ("NGLs") and treats the natural gas in order to meet pipeline specifications. The Company markets gas and NGLs nationwide and in Canada, providing risk management, storage, transportation, scheduling, peaking and other services to a variety of customers. The Company explores and develops certain producing properties, primarily in Wyoming, Louisiana and Texas, in support of its existing facilities and to expand into new producing areas. Historically, the Company has derived over 95% of its revenues from the sale of gas and NGLs. Set forth below are the Company's revenues by type of operation (000s):
Year Ended December 31, ---------------------------------------------------------------- 1997 % 1996 % 1995 % ---------------- ------ ---------- ------ ---------- ------ Sale of gas...................................... $1,657,479 69.5 $1,440,882 68.9 $ 876,399 69.7 Sale of NGLs..................................... 611,969 25.7 561,581 26.9 331,760 26.4 Sale of electric power........................... 59,477 2.5 30,667 1.5 - - Processing, transportation and storage revenues.. 40,906 1.7 44,943 2.1 41,358 3.3 Other, net....................................... 15,429 .6 12,936 .6 7,467 .6 ---------- ----- ---------- ----- ---------- ----- $2,385,260 100.0 $2,091,009 100.0 $1,256,984 100.0 ========== ===== ========== ===== ========== =====
The Company has expanded through acquisitions, internal project development and increased marketing activity. This expansion has strengthened the Company's position in major producing basins and increased its access to multiple natural gas markets. The table below illustrates the Company's growth over the last five years:
Average for the Year Ended Average ------------------------------------- Average NGL Gas Gas NGL Gas Sales Sales Throughput Production Production (MMcf/D) (MGal/D) (MMcf/D) (MMcf/D) (MGal/D) ---------- -------- ----------- ----------- ----------- December 31, 1992.. 442 2,400 669 331 1,874 December 31, 1997.. 1,975 4,585 1,229 1,053 2,264 % increase......... 347 91 84 218 21
The Company's four-part business plan is designed to increase profitability through: (i) investing in projects that complement and extend its core gas gathering, processing and marketing business; (ii) creating ventures with producers who will dedicate additional acreage to the Company; (iii) expanding its energy sales volumes and margins by maximizing its asset base, firm transportation and storage contracts and other contractual arrangements; and (iv) optimizing the profitability of existing operations. See further discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Business Strategy." 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 the Company's gathering operations, its project development schedules, marketing plans, throughput capacity and anticipated volumes 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 the Company's 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 the Company operates, could cause actual results to differ materially. 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." The Company's principal offices are located at 12200 North Pecos Street, Denver, Colorado 80234-3439, and its telephone number is (303) 452-5603. The Company was incorporated in Delaware in 1989. 3 PRINCIPAL FACILITIES The following table provides information concerning the Company's principal facilities. The Company also owns and operates several smaller treating and processing facilities located in the same areas as its other facilities.
Average for the Year Ended December 31, 1997 Gas Gas -------------------------------------------- Gathering Throughput Gas Gas NGL Year Placed Systems Capacity Throughput Production Production Plant Facilities (1) In Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5) - ------------------------------- ----------- ------------- ------------- ------------- ------------- ----------- SOUTHERN REGION: Texas Bethel Treating (6).......... 1997 79 350 42 38 - Edgewood (6)(7).............. 1964 89 65 26 8 63 Giddings Gathering........... 1979 656 80 60 51 84 Gomez Treating............... 1971 307 280 156 151 - Midkiff/Benedum.............. 1955 2,127 165 152 99 948 Mitchell Puckett Gathering... 1972 86 85 80 79 - MiVida Treating (6).......... 1972 287 150 66 63 - Perkins (8).................. 1975 2,573 40 21 12 134 Rosita Treating.............. 1973 - 60 39 39 - Louisiana Black Lake................... 1966 56 75 22 14 61 Toca (7)(9).................. 1958 - 160 101 97 69 NORTHERN REGION: Wyoming Coal Bed Methane Gathering (10).............. 1990 139 55 37 33 - Granger (7)(11)(12)(13)...... 1987 366 235 146 128 288 Hilight Complex (7).......... 1969 622 80 38 32 89 Kitty/Amos Draw (7).......... 1969 307 17 11 7 46 Lincoln Road (13)............ 1988 149 50 32 31 29 Newcastle (7)................ 1981 145 5 2 1 16 Red Desert (7)............... 1979 111 42 22 21 37 Reno Junction (11)........... 1991 - - - - 56 Oklahoma Arkoma....................... 1985 63 8 5 5 - Chaney Dell (14)............. 1966 2,042 180 78 62 242 Westana (14)................. 1986 726 45 59 51 97 New Mexico San Juan River (6)........... 1955 130 60 31 28 1 Utah Four Corners Gathering....... 1988 104 15 3 3 4 ------ ----- ----- ----- ----- Total....................... 11,164 2,302 1,229 1,053 2,264 ====== ===== ===== ===== =====
Average for the Year Ended December 31, 1997 Interconnect ----------------- and Gas Storage Pipeline Gas Storage and Year Placed Transmission Capacity Capacity Throughput Transmission Facilities (1) In Service Miles(2) (Bcf)(2) (MMcf/D)(2) (MMcf/D)(4) - ------------------------------- ----------- ------------ ---------- ---------- --------------- Katy Facility (15)............. 1994 17 20 - 250 MIGC (16)...................... 1970 245 - 90 58 MGTC (17)...................... 1963 252 - 18 9 ------ ----- ----- ----- Total........................ 514 20 108 317 ====== ===== ===== =====
- ------------------ Footnotes on following page. 4 (1) The Company's interest in all facilities is 100% except for Midkiff/Benedum (73%); Black Lake (69%); Lincoln Road (72%); Westana Gathering Company ("Westana") (50%); Newcastle (50%) and Coal Bed Methane Gathering (50%). All facilities are operated by the Company and all data include interests of the Company, other joint interest owners and producers of gas volumes dedicated to the facility. (2) Gas gathering systems miles, interconnect and transmission miles, gas storage capacity and pipeline capacity are as of December 31, 1997. (3) Gas throughput capacity is as of December 31, 1997 and represents capacity in accordance with design specifications unless other physical constraints exist, including permitting or field compression limits. (4) Aggregate wellhead natural gas volumes collected by a gathering system, aggregate residue volumes delivered over the header at the Katy Hub and Gas Storage Facility ("Katy Facility") or residue 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) In November 1997, the Company entered into an agreement to sell its Perkins facility. The sales price is $22.0 million, subject to certain adjustments, and is expected to result in a pre-tax gain of approximately $11.0 million. The sale is pending Federal Trade Commission approval. The Company expects to obtain such approval and for the sale to close during the first quarter of 1998. (9) Straddle plant (a plant located near a transmission pipeline that processes gas dedicated to or gathered by a pipeline company or another third party). (10) On October 30, 1997, the Company sold a 50% undivided interest in its Powder River Basin coal bed methane gas operations. The sale involved gathering assets, producing properties, production equipment and certain undeveloped acreage in this area. See further discussion in "Significant Acquisitions, Projects and Dispositions." (11) NGL production includes conversion of third-party feedstock to iso-butane. (12) In February 1998, the Company sold a 50% undivided interest in a portion of the Granger gathering system for approximately $4.0 million. This amount approximated the Company's cost in such facilities. See further discussion in "Significant Acquisitions, Projects and Dispositions." (13) The Company and its joint venture partner at the Lincoln Road facility have agreed to process such gas at the Company's Granger facility as long as there is available capacity at the Granger facility. As a result, a periodic election is made as to whether or not gas will be processed at the Lincoln Road facility. Accordingly, operations at the Lincoln Road facility were temporarily suspended for the period between March 1996 and April 1997. Beginning February 1998, processing at the Lincoln Road facility was again temporarily suspended. (14) Gas throughput and gas production in excess of plant throughput capacity is unprocessed gas delivered to the Company's Chaney Dell facility for processing or delivered into an unaffiliated pipeline. These processed volumes are included in Westana's NGL production volumes. (15) Hub and gas storage facility. (16) MIGC is an interstate pipeline located in Wyoming and is regulated by the Federal Energy Regulatory Commission ("FERC"). (17) MGTC is a public utility located in Wyoming and is regulated by the Wyoming Public Service Commission. Capital expenditures related to existing operations are expected to be approximately $129.4 million during 1998, consisting of the following: capital expenditures related to gathering, processing and pipeline assets are expected to be approximately $84.8 million, of which approximately $74.8 million is budgeted to be used for new connects, system expansions and asset consolidations and approximately $10.0 million for maintaining existing facilities. The Company expects capital expenditures on exploration and production activities, the Katy Facility and miscellaneous items to be approximately $40.2 million, $1.5 million and $2.9 million, respectively. GAS GATHERING, PROCESSING, STORAGE AND TRANSMISSION Gas Gathering and Processing The Company contracts with producers to gather raw natural gas ("natural gas") from individual wells located near its plants. Once a contract has been executed, the Company connects wells to gathering lines through which the natural gas is delivered to a processing plant or treating facility. At a processing plant, the natural gas is compressed, unfractionated NGLs are extracted and the remaining dry gas is treated to meet pipeline quality specifications ("residue gas" or "gas"). Seven of the Company's processing plants can further separate, or fractionate, the mixed NGL stream into ethane, propane, normal butane 5 and natural gasoline to obtain a higher value for the NGLs and four of the Company's plants are able to process and treat natural gas containing hydrogen sulfide or other impurities which require removal prior to transportation. In addition, the Company has two facilities which convert normal butane into iso- butane. At a treating facility, dry gas, which does not contain liquids that can economically be extracted, is treated to meet pipeline quality specifications by removing hydrogen sulfide or carbon dioxide. The Company continually acquires additional dedicated natural gas supplies in an effort to maintain or increase throughput levels to offset natural production declines in dedicated volumes. Such natural gas supplies are obtained by purchasing existing systems from third parties, by connecting additional wells, through internally developed projects or through joint ventures with entities which control acreage. Historically, while certain individual plants have experienced declines in dedicated reserves, the Company has been successful in connecting additional reserves to more than offset the natural declines and reserves dedicated to existing facilities. Drilling activity in certain basins in which the Company operates has continued to be significantly reduced from levels that existed in prior years. However, higher gas prices experienced since the beginning of 1996, improved technology (e.g., 3-D seismic and horizontal drilling) and increased pipeline capacity from the Rocky Mountain region have stimulated drilling in certain of the basins in which the Company operates, primarily the Permian Basin, the Cotton Valley Pinnacle Reef trend, Powder River Basin and Southwest Wyoming. The level of drilling will depend upon, among other factors, the prices for gas and oil, the energy policy of the federal government and the availability of foreign oil and gas, none of which are within the Company's control. There is no assurance that the Company will continue to be successful in replacing the dedicated reserves processed at its facilities. In 1997, including the reserves associated with the Company's joint ventures and partnerships, the Company connected new reserves to its gathering systems to replace approximately 220% of 1997 production. On a Company-wide basis, dedicated reserves increased from approximately 2.8 Tcf as of December 31, 1996 to approximately 3.3 Tcf at December 31, 1997. Substantially all gas flowing through the Company's 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 70% of the Company's plant facilities' gross margin (revenues at the plants less product purchases) for the year ended December 31, 1997 resulted from percentage-of-proceeds agreements in which the Company is typically responsible for arranging for the transportation and marketing of the gas and NGLs. The price paid to producers is a specified percentage of the net proceeds received from the sale of the gas and the NGLs. This type of contract permits the Company and the producers to share proportionally in price changes. Approximately 15% of the Company's plant facilities' gross margin (revenues at the plants less product purchases) for the year ended December 31, 1997 resulted from contracts that are primarily fee-based whereby the Company receives a set fee for each Mcf of gas gathered. This type of contract provides the Company 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 percentage of fee-based contracts is expected to increase as the volumes at the Bethel Treating facility increase. See further discussion in "Significant Acquisitions, Projects and Dispositions." Approximately 15% of the Company's plant facilities' gross margin (revenues at the plants less product purchases) for the year ended December 31, 1997 resulted from contracts that combine gathering and compression fees with "keepwhole" arrangements or wellhead purchases. Typically, producers are charged a gathering and compression fee based upon volume. In addition, the Company retains a predetermined percentage of the NGLs recovered by the processing facility and keeps 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 the Company to benefit when the value of the NGLs is greater as a liquid than as a portion of the residue gas stream. However, when the value of the NGLs is lower as a liquid than as a portion of the residue gas stream, the Company will be unfavorably affected. Storage and Transmission In order to enhance the Company's gas marketing activities, it constructed the Katy Facility. The Company commenced operations of the Katy Facility in February 1994. The Katy Facility, which is located approximately 20 miles from Houston, Texas, utilizes a partially depleted natural gas reservoir with 20 Bcf of working gas capacity and a pipeline header system, currently connected to 11 pipelines, which has the capability to deliver up to 400 MMcf per day of gas from the reservoir. See "Marketing - Gas." 6 The Company owns and operates MIGC, an interstate pipeline located in the Powder River Basin in Wyoming and MGTC, an intrastate pipeline located in Northeast Wyoming. As of December 31, 1997, MIGC is connected to the Colorado Interstate Gas Pipeline, the Williston Basin Interstate Pipeline and the Pony Express Pipeline. During November 1997, MIGC received approval from the FERC to increase its pipeline capacity from 45 MMcf per day to 90 MMcf per day. The compressors associated with this expansion began operating in December 1997. As part of the Company's continuing plan to expand its Powder River Basin coal bed methane operations, MIGC is currently seeking another approval from the FERC to increase its pipeline capacity from 90 MMcf per day to 130 MMcf per day. The Company anticipates receiving such approval during the third quarter of 1998. See further discussion in "Significant Acquisitions, Projects and Dispositions." SIGNIFICANT ACQUISITIONS, PROJECTS AND DISPOSITIONS The Company's significant acquisitions and projects since January 1, 1995 are: Coal Bed Methane The Company is expanding its Powder River Basin coal bed methane natural gas gathering system and developing its own coal seam gas reserves in Wyoming. The Company has acquired drilling rights in the vicinity of known coal bed methane production. The Company and other operators in the area have established production from wells drilled to depths of 200 to 700 feet. The typical gathering and completion costs associated with such drilling activities have approximated $60,000 per well. As deeper wells are drilled, the average cost per well is expected to increase. The Company will utilize its existing dry gas gathering system and interstate pipeline to transport this pipeline quality gas to market. The Company's capital budget provides for expenditures of approximately $42.0 million during 1998. This capital budget includes approximately $18.8 million for drilling costs, production equipment and purchase of operating wells and undeveloped acreage. The remainder is to be used primarily for compression equipment. Depending upon future drilling success, additional capital expenditures will be required to continue expansion in this basin. However, because of drilling and other uncertainties beyond the Company's control, there can be no assurance that this level of capital expenditure will be incurred or that future capital expenditures will be made. During the years ended December 31, 1997 and 1996, the Company has expended approximately $32.2 million and $6.9 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 to Barrett Resources Corporation ("Barrett"). This sale provides the Company with a substantial acreage dedication within an area of mutual interest ("AMI"), additional man-power resources to accelerate development in this area and more technical expertise in exploration and production. The sale involved gathering assets, 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. An AMI has been created under the agreement with Barrett which encompasses approximately 2.1 million acres in the Powder River coal bed methane play. Both parties will develop certain specified areas within the AMI, with Barrett becoming the operator of the producing wells at the earlier of July 1, 1999 or when production in the AMI reaches 60 MMcf per day. Production from the Powder River coal bed methane play has been expanding over the last two years, and the Company estimates that approximately 50 MMcf per day of gas volumes are currently being produced from several operators in the area, including the Company's interest. Most of the coal bed methane gas is being transported by MIGC to gas markets in the Rocky Mountain and Midwest regions of the United States. The Company has committed to purchase all gas produced from the jointly- owned properties within the AMI under a long-term gas purchase agreement. The Company entered into a firm transportation agreement under which MIGC will install additional compression and transmission facilities as needed to handle the anticipated increase in gas volumes. In January 1998, the Company acquired an interest in approximately 25,000 acres, which includes approximately 50 coal bed methane wells, located in Campbell County, Wyoming. The Company will initially serve as operator of the properties. Barrett has elected to participate in this project and will become the principal operator. The Company's share of the purchase price was $6.4 million and is subject to certain adjustments. Southwest Wyoming The Company began to expand its gas gathering and exploration and production activities in Southwest Wyoming, including the Jonah field, 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 Granger and Lincoln Road facilities. The Company's capital 7 budget provides for expenditures of approximately $18.0 million during 1998. This capital budget includes approximately $9.9 million for drilling costs and production equipment and approximately $8.1 million related to gathering, transportation and expansion of the Granger facility. Depending upon future drilling success, additional capital expenditures will be required to continue expansion in this basin. However, because of drilling and other uncertainties beyond the Company's control, there can be no assurance that this level of capital expenditure will be incurred or that future capital expenditures will be made. During the year ended December 31, 1997, the Company has expended approximately $6.2 million on this project. In November 1997, the Company entered into an agreement with Ultra Resources, Inc. ("Ultra") to participate in the exploration, development, gathering and processing in the Hoback Basin in Southwestern Wyoming. Under the agreement, a 1.8 million acre AMI was established, in which Ultra currently controls approximately 350,000 acres. The Company has the option to participate in exploration and production activities for approximately a 15% interest. The Company and Ultra have also entered into agreements for the natural gas, which is developed on 16 prospects within the AMI, to be gathered and processed through the Company's Granger facility. Eight of the 16 prospects were drilled in 1997 and are in various stages of completion. The Company can expand the area dedicated for gathering and acreage by funding Ultra's share of specified development wells which will be paid back through future production. Additionally, the Company entered into two separate agreements with RIS Resources (USA) Inc. ("RIS"), an affiliate of Ultra, to sell RIS undivided interests in certain assets. Under the first agreement, in February 1998, the Company sold RIS a 50% undivided interest in a portion of the Granger gathering system servicing the Ultra AMI (the "Bird Canyon Line") for approximately $4.0 million. This amount approximated the Company's cost in such facilities. RIS and the Company expect to install jointly additional gathering assets in this area as needed. Under the second agreement with RIS, the Company has granted RIS the option to purchase up to 50% of the Granger processing facility and its remaining gathering system and up to a 50% interest in the Company's 72% ownership interest in the Lincoln Road facility (collectively the "Granger Complex"). This option is exercisable in two 25% increments. The first option is exercisable at any time prior to July 1, 1998 and the second option, which is contingent upon the exercise of the first increment, is exercisable at any time prior to July 1, 1999. In conjunction with this agreement, in February 1998, RIS paid a $1 million option payment of which $500,000 is non-refundable. In addition, RIS is required to pay an additional $59 million at the closing of the first option and $50 million at the closing of the second option. The purchase price will be further increased by a pro-rata share of capital expenditures incurred at the Granger Complex from November 1997 until closing. These options are subject to various regulatory approvals and third-party purchase preferential rights. Pursuant to the agreement with RIS, the Company will remain the operator of the Bird Canyon Line and the Granger Complex. Bethel Treating Facility (Cotton Valley Pinnacle Reef) In September 1996, the Company began constructing the Bethel Treating facility in East Texas to gather and treat gas containing hydrogen sulfide and carbon dioxide ("Sour Gas") from the Cotton Valley Pinnacle Reef Trend. The Company embarked upon the project based upon producer reserve estimates, well rates encountered by exploration companies and the need for a treating facility in this area. The producer reserve estimates were based upon advancements in 3-D seismic technology which facilitated the identification of potential pinnacle reefs. Long-term gathering and treating agreements have been signed with several producers, including Sonat Exploration Company ("Sonat"), UMC Petroleum Corporation, Broughton Associates Joint Venture and Union Pacific Resources Company, relating to their interests in the Cotton Valley Pinnacle Reef trend. These agreements, in addition to other agreements, cover specified areas of dedication aggregating approximately 650,000 acres of previously undedicated interests and other individual wellsites. Although the producers' reported success rates remain high in the Cotton Valley Pinnacle Reef Trend, a number of producers in the trend are currently re- evaluating their 1998 drilling plans downward. Pursuant to its agreement with Sonat, the Company will begin treating additional volumes in May 1999 which are currently being treated by a competitor. At present, this production is approximately 100 MMcf per day. In the third quarter of 1997, the Company completed the initial portion of the Bethel Treating facility, which is capable of treating approximately 350 MMcf per day, assuming 500 parts per million of hydrogen sulfide in the gas stream. The Company has designed the Bethel Treating facility to accommodate incremental expansions, depending upon the success of continued development in the trend. To accommodate wells which contain greater concentrations of hydrogen sulfide, the Company began to construct a 60-ton sulfur recovery plant which is expected to become operational in March 1998. The 8 Bethel Treating facility, including the sulfur recovery plant, is expected to cost approximately $97.0 million, of which approximately $90.5 million has been expended since inception through December 31, 1997. While the Bethel Treating facility did not contribute to profitability during the year ended December 31, 1997, the Company anticipates that revenues will be sufficient to cover both operating costs and depreciation at its current level of operation. See further discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations." Reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of reserves and in the projection of future rates of production and the timing of development expenditures. A portion of the production that is anticipated to be gathered and treated at the Bethel Treating facility is expected to be produced from prospects that have not yet been drilled and completed, and there can be no assurance of successful completion of wells in these prospects. In addition, the carbon dioxide and hydrogen sulfide content of the gas that can be produced from these wells is unknown and affects the ultimate capacity of the Bethel Treating facility. Future expansions of the Bethel Treating facility will be dependent upon drilling progress and permitting of additional pipelines. Due to uncertainties related to future costs, possible delays in pipeline permitting and other conditions outside the Company's control, there can also be no assurance that further expansions of the Bethel Treating facility will be economical. Midkiff/Benedum During 1997, the Company expanded the capacity at its Midkiff/Benedum processing plant to approximately 165 MMcf per day. The expansion was to accommodate increased drilling activity by Pioneer Natural Resources Company and other producers which supply natural gas to this facility. The Company's share of the expansion cost was approximately $4.3 million. Perkins In November 1997, the Company entered into an agreement to sell its Perkins facility. The sales price is $22.0 million, subject to certain adjustments, and is expected to result in a pre-tax gain of approximately $11.0 million. The sale is pending Federal Trade Commission approval. The Company expects to obtain such approval and for the sale to close during the first quarter of 1998. Northern Acquisition In July 1995, the Company purchased eight West Texas gathering systems, consisting of approximately 230 miles of gathering lines in the Permian Basin, from Transwestern Gathering Company and Enron Permian Gathering, Inc. The adjusted purchase price was $18.7 million. Redman Smackover Joint Venture Effective January 1, 1995, the Company entered into the Redman Smackover Joint Venture ("Redman Smackover") agreement with various third parties. Redman Smackover acquired working interests in three producing gas fields in East Texas in the Smackover formation for an adjusted purchase price of $11.0 million. The Company is the managing venturer with a 50% ownership interest. Other The Company continually monitors the economic performance of each of its operating facilities to ensure that a desired cash flow objective is achieved. If an operating facility is not generating desired cash flows or does not fit in with the Company's strategic plans, the Company will explore various options, such as consolidation with other Company-owned facilities, dismantlement, asset swap or outright sale. The Company and its joint venture partner at the Lincoln Road facility have agreed to process all such gas at the Company's Granger facility as long as there is available capacity at the Granger facility. As a result, a periodic election is made as to whether or not gas will be processed at the Lincoln Road facility. Accordingly, operations at the Lincoln Road facility were temporarily suspended for the period between March 1996 and April 1997. As a result of a producer stopping delivery in December 1997 of approximately 40 MMcf per day of gas, 9 processing at the Lincoln Road facility was again temporarily suspended. In 1996, the Company sold its Temple and Baker facilities and the remaining non- strategic assets associated with a 1994 acquisition. In January 1996, Koch Hydrocarbon Company, which operated the Teddy Roosevelt and Williston Gas Company assets under a lease agreement, exercised its option to purchase certain gas gathering assets located in North Dakota from the Company and Williston Gas Company. MARKETING Gas The Company markets gas produced at its plants and purchased from third parties to end-users, local distribution companies ("LDCs"), pipelines and other marketing companies throughout the United States and in Canada. Historically, the Company's gas marketing was an outgrowth of the Company's gas processing activities and was directed towards selling gas processed at its plants to ensure their efficient operation. As the Company expanded into new basins and the natural gas industry became deregulated and offered more opportunity, the Company began to increase its third-party gas marketing. Since 1992, the Company's gas sales volumes have increased by 347% to 2.0 Bcf per day for the year ended December 31, 1997, primarily as a result of the increase in third- party sales. Third-party sales and gas storage, combined with the stable supply of gas from Company facilities, enable the Company to respond quickly to changing market conditions and to take advantage of seasonal price variations and peak demand periods. The Company sells gas under agreements with varying terms and conditions in order to match seasonal and other changes in demand. Most of the Company's current sales contracts range from a few days to two years. During 1997, the Company increased sales to end-users and expanded its marketing in areas beyond its traditional gas supply centers. In general, the Company does not expect dramatically to increase its third-party sales volumes from levels achieved during the year ended December 31, 1997. Also during 1997, the Company closed its Boston and Chicago offices. No significant costs were incurred as a result of these office closures. The Company's 1998 gas marketing plan emphasizes growth through its asset base and storage and transportation capacities which it controls. However, it does intend to continue to develop and market products tailored to meet the needs of end-users located primarily in the Rocky Mountain region. During 1997, the Company created a wholly-owned subsidiary to operate a marketing office in Calgary, Alberta. In addition, the Company, through this Canadian subsidiary, contracted capacity for approximately 4.1 Bcf of storage in Canada. The Company anticipates that the Calgary office will (i) provide the Company with information regarding gas supplies being transported from Canada; (ii) establish a presence in an evolving gas market; and (iii) allow it to increase profitability through its storage capacity. The Company customarily stores gas in underground storage facilities to ensure an adequate supply for long-term sales contracts and for resale during periods when prices are favorable. In order to expand its ability to provide market services and seasonal price differentials, the Company constructed the Katy Facility. The ability to withdraw gas from the Katy Facility on short notice positions the Company to market gas to LDCs and other customers that need a reliable yet variable supply of gas. The Katy Facility's header system allows the Company to bypass certain transportation bottlenecks and enhances flexibility in its marketing operations. In addition, as of December 31, 1997, the Company had contracts in place for approximately 16.1 Bcf of storage capacity, including storage through its Canadian subsidiary, for resale during periods when prices are favorable. The fees associated with such contracts range from $.05 per Mcf to $1.25 per Mcf and the associated periods range from one month to one year. As of December 31, 1997, the Company also had contracts for approximately 400 MMcf per day of firm transportation; 50% of such contracts expire during 1998. The fees associated with such contracts do not exceed $.37 per Mcf per day and the associated periods range from one month to ten years. Certain of these long-term storage and firm transportation contracts require an annual renewal. In addition, certain contracts contain provisions which would require the Company to pay the fees associated with such contracts whether or not the service was used. The Company held gas in storage and held imbalances of approximately 6.0 Bcf at an average cost of $1.97 per Mcf at December 31, 1997 compared to 10.4 Bcf at an average cost of $1.84 per Mcf at December 31, 1996, at various storage facilities, including the Katy Facility. At December 31, 1997, the Company had hedging contracts in place for anticipated sales of approximately 4.8 Bcf of stored gas at a weighted average price of $2.28 per Mcf for the stored inventory. See further discussion in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - -Risk Management Activities." 10 The Company has a three-year, winter-peaking gas purchase and sales agreement with a major utility in East Texas, expiring in March 1999, which designates the Katy Facility as the primary delivery point. Under the agreement, the utility has the right to purchase, during each year of the contract, up to approximately 100 MMcf per day and 70 MMcf per day of gas in November and March, respectively, and approximately 140 MMcf per day of gas in December, January and February, at a monthly index price plus a fixed charge. The agreement calls for a minimum charge to be paid to the Company for each contract term, whether or not delivery is taken. This minimum charge is calculated based upon five Bcf of annual storage during each fiscal year of the contract term. In February 1995, the Company entered into a long-term firm storage and transportation agreement with a St. Louis-based LDC that expires in March 2000. Under the agreement, the Company has leased approximately three Bcf of storage capacity of the Katy Facility to the LDC. The gas will principally serve local distribution requirements of the LDC's customers in central Missouri. During the year ended December 31, 1997, the Company sold gas to approximately 500 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, 1997. NGL Marketing The Company markets NGLs (ethane, propane, iso-butane, normal butane, natural gasoline and condensate) produced at its plants and purchased from third parties in the Rocky Mountain, Mid-Continent, Gulf Coast and Southwestern regions of the United States. A majority of the Company's 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, the Company seeks to ensure that products from its plants move on a reliable basis, avoiding curtailment of production. For the year ended December 31, 1997, NGL sales averaged 4,585 MGal per day, an increase from 2,400 MGal per day in 1992, primarily due to the increase in third-party sales, acquisitions and facility expansions during the five-year period. The volatility of NGL prices causes the Company to move to short-term contracts for its NGL marketing activities, with no prices set on a firm basis for more than a 30-day period. Although some existing contracts do commit the Company for periods as long as three years, prices are typically redetermined on a market-related basis. Consumption of NGLs is primarily determined by various end-user markets including 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, propane is used for home heating, transportation and for certain agricultural applications. Demand for NGLs is primarily affected by price, seasonality and the economy. The Company increased sales to third parties by approximately 800 MGal per day for the year ended December 31, 1997 compared to 1996. In general, the Company does not anticipate that sales to third parties in 1998 will increase at the rate experienced in 1997. The NGL marketing plan contemplates: (i) continued growth in sales to end-users; (ii) maximizing profitability on volumes produced at the Company's facilities; and (iii) efficient use of various third-party storage facilities to increase profitability while limiting carrying risk. The Company leases NGL storage space at major trading locations, primarily near Houston and in central Kansas, in order to store products so that they can be sold at higher prices on a seasonal basis and to facilitate the distribution of products. In addition, as of December 31, 1997, the Company has contracts in place for approximately 27,300 MGal of storage capacity for resale during periods when prices are favorable. The base fees associated with such contracts currently do not exceed $.02 per gallon and the associated periods range from three months to five years. Certain of the long-term contracts require an annual renewal and contain provisions which would require the Company to pay the fees associated with such contracts whether or not the service was used. The Company held NGLs in storage of 14,400 MGal, consisting primarily of propane and normal butane, at an average cost of $.37 per gallon and 16,100 MGal at an average cost of $.42 per gallon at December 31, 1997 and 1996, respectively, at various third-party storage facilities. At December 31, 1997, the Company had hedging contracts in place for anticipated sales, consisting primarily of propane, at a weighted average price of $.36 per gallon for approximately 3,200 MGal of the stored NGLs in inventory. The Company generally intends that stored NGLs turn over on an annual basis. 11 NGL sales were made to approximately 175 different customers and no single customer accounted for more than 2% of the Company's consolidated revenues for the year ended December 31, 1997. Revenues are also derived from contractual marketing fees charged to some producers for NGL marketing services. For the year ended December 31, 1997, such fees were less than 1% of the Company's 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 allows companies to participate in a market previously controlled by electric utilities. During 1996 and 1997, the Company traded electric power in the wholesale market and entered into transactions that arbitraged the value of gas and electric power. Due to a lack of profitability, the Company elected to discontinue trading electric power and began to evaluate its role in this emerging business, during the second half of 1997. PRODUCING PROPERTIES Revenues derived from the Company's producing properties comprised approximately 1.3%, 1.6% and 2.6% of consolidated revenues, respectively, for the years ended December 31, 1997, 1996 and 1995. During 1997, the Company began to invest more capital in oil and gas producing activities primarily to replace declining reserves which are processed at the Company's facilities and encourage expansion into basins where the Company's facilities are located. The Company believes that in order to secure additional gas supply for its facilities, it must be willing to increase its participation in exploration and production activities. However, the Company, where possible, has entered into agreements with third parties to reduce a portion of the risk associated with exploration and production activities. The net annual production volumes are summarized as follows:
December 31, ------------------------------------------------- 1997 1996 1995 --------------- ---------------- -------------- Gas Oil Gas Oil Gas Oil State (MMcf) (MBbl) (MMcf) (MBbl) (MMcf) (MBbl) - ---------------------------- ------- ------ ------- ------ ------- ------ Colorado.................... 243 6 73 6 73 6 Louisiana................... 4,760 108 7,255 117 11,429 131 Texas....................... 6,092 21 7,193 32 6,588 61 Wyoming: Coal Bed Methane.......... 1,751 - 12 - - - All Other................. 1,752 19 233 3 263 2 ------ --- ------ --- ------ ---- Total....................... 14,598 154 14,766 158 18,353 200 ====== === ====== === ====== ====
Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121"), which requires that an impairment loss be recognized when the carrying amount of an asset exceeds the fair market value or the expected future undiscounted net cash flows. SFAS No.121 also requires long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. As a result of a review of the reserves, the Company determined that circumstances had changed, primarily related to its Black Lake facility and Sand Wash Basin assets, and an impairment evaluation was necessary. In order to determine whether an impairment existed, the Company compared its net book value of the assets to the estimated fair market value or the undiscounted expected future cash flows, determined by applying future prices estimated by management over the lives of the associated reserves. Where impairment existed, assets were written-down to the net present value of expected cash flows discounted using an interest rate commensurate with the risk associated with the underlying asset. As a result of this analysis, the Company recognized a pre-tax, non-cash loss on the impairment of property and equipment of $34.6 million. 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 same engineers at different times may vary substantially. Results of subsequent drilling, testing and production may cause 12 either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Any significant revision of reserve estimates could materially adversely affect the Company's financial condition and results of operations. COMPETITION The Company competes with other companies in the gathering, processing, treating and marketing businesses both for supplies of natural gas and for customers for its gas and NGLs. 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 customers is primarily based upon reliability and price of deliverable gas and NGLs. For customers that have the capability of using alternative fuels, such as oil and coal, the Company also competes based primarily on price against companies capable of providing such alternative fuels. The Company's competitors for obtaining additional natural gas supplies, for gathering and processing natural gas and for marketing gas and NGLs include national and local gas gatherers, brokers, marketers and distributors of various size, financial resources and experience. REGULATION The purchase and sale of natural gas and the fees received for gathering and processing by the Company have generally not been subject to regulation and, therefore, except as constrained by competitive factors, the Company has considerable pricing flexibility. Many aspects of the gathering, processing, marketing and transportation of natural gas and NGLs by the Company, however, are subject to federal, state and local laws and regulations which can have a significant impact upon the Company's overall operations. As a processor and marketer of natural gas, the Company depends on the transportation and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of its own gas supplies as well as those it processes and/or markets for others. Both the performance of transportation and storage services by interstate pipelines, 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. The availability of interstate transportation and storage service necessary to enable the Company to make deliveries and/or sales of gas can at times be pre- empted by other system users in accordance with FERC-approved methods for allocating the system capacity of "open access" pipelines. Moreover, the rates charged by pipelines 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 the Company's processing and marketing operations and/or affect its sales margins. In 1997, the State of Texas adopted a statute that will require the Company to obtain a pre-construction permit for certain gas gathering lines containing more than 100 parts per million of hydrogen sulfide and grants affected persons, in certain circumstances, the right to request a hearing relating to the issuance of such a permit. This may increase the time and cost associated with constructing hydrogen sulfide gathering lines. The Company operates three facilities in Texas which treat hydrogen sulfide; the Edgewood facility, the MiVida Treating facility and the Bethel Treating facility, and owns certain producing properties in Texas that produce hydrogen sulfide. Generally, gathering and processing prices are not regulated by the FERC or any state agency. However, in May 1995, the Oklahoma Corporation Commission (the "OCC") was granted 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 greatly 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 provided by a gas gatherer. In addition, the state legislatures and regulators in certain other states in which the Company gathers gas are also contemplating additional regulation of gas gathering. The Company does not believe that any of the proposed legislation of which it is aware is likely to have a material adverse effect on the Company's financial position or results of operation. However, the Company cannot predict what additional legislation or regulations the states may adopt regarding gas gathering. EMPLOYEES At December 31, 1997, the Company employed approximately 930 full-time employees, none of whom was a union member. The Company considers relations with employees to be excellent. 13 ITEM 3. LEGAL PROCEEDINGS Reference is made to Note 9 of the Company's 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, 1997. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS As of February 27, 1998, there were 32,146,437 shares of Common Stock outstanding held by 325 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 ---------------- -------- 1997 Fourth Quarter.................... $ 25 9/16 $ 20 Third Quarter..................... 22 1/2 16 3/4 Second Quarter.................... 20 1/2 14 7/8 First Quarter..................... 21 3/8 17 3/4 1996 Fourth Quarter.................... 19 7/8 13 7/8 Third Quarter..................... 16 3/8 13 1/8 Second Quarter.................... 16 3/4 13 1/2 First Quarter..................... $ 16 5/8 $ 11 1/8
The Company paid annual dividends on the Common Stock aggregating $.20 per share during the years ended December 31, 1997 and 1996. The Company has declared a dividend of $.05 per share of Common Stock for the quarter ending March 31, 1998 to holders of record as of such date. Declarations of dividends on the Common Stock are within the discretion of the Board of Directors. In addition, the Company's ability to pay dividends is restricted by certain covenants in its financing facilities, the most restrictive of which prohibits declaring or paying dividends after December 31, 1995 that exceed, in the aggregate, the sum of $10 million plus 50% of the Company's cumulative consolidated net income earned after December 31, 1995 plus 50% of the net proceeds received by the Company after December 31, 1995 from the sale of any equity securities. The dividends declared in the fourth quarter of 1995, payable in 1996, were excluded from this calculation. At December 31, 1997, availability under this covenant amounted to $118.5 million. 14 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected consolidated financial and operating data for the Company. Certain prior year amounts have been reclassified to conform to the presentation used in 1997. The data for the three years ended December 31, 1997 should be read in conjunction with the Company's Consolidated Financial Statements included elsewhere in this Form 10-K. The selected consolidated financial data for the two years ended December 31, 1994 is derived from the Company's historical Consolidated Financial Statements. See also Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Year Ended December 31, -------------------------------------------------------------- 1997 1996 1995 1994 1993 ----------- ---------- ---------- ---------- ---------- (000s, except per share amounts and operating data) STATEMENT OF OPERATIONS: Revenues............................................... $2,385,260 $2,091,009 $1,256,984 $ 1,063,489 $ 932,338 Gross profit (a)....................................... 93,755 105,479 75,211 72,556 92,012 Income (loss) before income taxes...................... 2,220(b) 41,631 (8,266)(c) 11,524 55,631 Provision (benefit) for income taxes................... 733 13,690 (2,158) 4,160 17,529 Net income (loss)...................................... 1,487(b) 27,941 (6,108)(c) 7,364 38,102 Earnings (loss) per share of common stock.......................................... (.28) .66 (.84) (.19) 1.25 Earnings (loss) per share of common stock - assuming dilution...................... (.28) .66 (.84) (.19) 1.25 CASH FLOW DATA: Net cash provided by operating activities............................................ 114,755 168,266 86,373 31,866 107,116 Capital expenditures................................... 198,901 74,555 78,521 100,540 492,328 BALANCE SHEET DATA (at year end): Total assets........................................... 1,348,276 1,361,631 1,193,997 1,167,362 1,114,748 Long-term debt......................................... 441,357 379,500 529,500 493,000 547,000 Stockholders' equity................................... 468,112 480,467 371,909 436,683 314,387 Dividends declared per share of common stock.......................................... $ .20 $ .20 $ .20 $ .20 $ .20 OPERATING DATA: Average gas sales (MMcf/D)............................. 1,975 1,794 1,572 1,097 755 Average NGL sales (MGal/D)............................. 4,585 3,744 2,890 2,970 2,941 Average gas volumes gathered (MMcf/D)..................................... 1,229 1,171 1,020 934 804 Facility capacity (MMcf/D)............................. 2,302 1,940 1,907 1,560 1,586 Average gas prices ($/Mcf)............................. $ 2.30 $ 2.19 $ 1.53 $ 1.77 $ 2.02 Average NGL prices ($/Gal)............................. $ .36 $ .41 $ .31 $ .28 $ .31
- --------------- (a) Excludes selling and administrative, interest, restructuring and income tax expenses and loss on the impairment of property and equipment. See further discussion in notes (b) and (c). (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" ("SFAS No. 121"), requires that an impairment loss be recognized when the carrying amount of an asset exceeds the fair market value of or the expected future undiscounted net cash flows. In accordance with SFAS No. 121, the Company recognized a pre-tax, non-cash loss on the impairment of property and equipment of $34.6 million, pre-tax, and $22.0 million, after-tax. (c) In accordance with SFAS No. 121, the Company recognized a pre-tax, non-cash loss on the impairment of property and equipment of $17.6 million, pre-tax, and $12.4 million, after-tax. Also, the Company 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, and $1.3 million, after- tax, restructuring charge was incurred, primarily related to employee severance costs. 15 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 the consolidated financial condition and results of operations of the Company for the three years ended December 31, 1997. Certain prior year amounts have been reclassified to conform to the presentation used in 1997. Reference should also be made to the Company's 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, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996 (000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended December 31, ------------------------- Percent 1997 1996 Change ------------- ---------- ------- FINANCIAL RESULTS: Revenues....................................................... $2,385,260 $2,091,009 14 Gross profit................................................... 93,775 105,479 (11) Net income..................................................... 1,487 27,941 (95) Earnings (loss) per share of common stock...................... (.28) .66 - Earnings (loss) per share of common stock - assuming dilution.. (.28) .66 - Net cash provided by operating activities...................... $ 114,755 $ 168,266 (32) OPERATING DATA: Average gas sales (MMcf/D)..................................... 1,975 1,794 10 Average NGL sales (MGal/D)..................................... 4,585 3,744 22 Average gas prices ($/Mcf)..................................... $ 2.30 $ 2.19 5 Average NGL prices ($/Gal)..................................... $ .36 $ .41 (12)
Net income decreased $26.5 million for the year ended December 31, 1997 compared to 1996. The decrease in net income for the year was primarily due to a $22.0 million, after-tax, impairment loss recorded in connection with the evaluation of certain property and equipment, primarily related to its Black Lake facility and Sand Wash Basin assets, as required by SFAS No. 121. Net income increased by a $3.0 million after-tax gain associated with the sale of a 50% interest in the Company's coal bed methane operations. Revenues from the sale of gas increased approximately $216.6 million for the year ended December 31, 1997 compared to 1996. Average gas sales volumes increased 181 MMcf per day to 1,975 MMcf per day for the year ended December 31, 1997 compared to 1996, primarily due to an increase in the sale of gas purchased from third parties. Average gas prices realized by the Company increased $.11 per Mcf to $2.30 per Mcf for the year ended December 31, 1997 compared to 1996. Included in the realized gas price was approximately $5.6 million of loss recognized in the year ended December 31, 1997 related to futures positions on equity volumes. The Company has entered into futures positions for a portion of its equity gas for 1998. See further discussion in "Liquidity and Capital Resources - Risk Management." Revenues from the sale of NGLs increased approximately $50.4 million for the year ended December 31, 1997 compared to 1996. Average NGL sales volumes increased 841 MGal per day to 4,585 MGal per day for the year ended December 31, 1997 compared to 1996, largely due to an increase of approximately 800 MGal per day in the sale of NGLs purchased from third parties. Average NGL prices realized by the Company decreased $.05 per gallon to $.36 per gallon for the year ended December 31, 1997 compared to 1996. Included in the realized NGL price was approximately $5.2 million of gain recognized in the year ended December 31, 1997 related to futures positions on equity volumes. The Company has entered into futures positions for a portion of its equity production for 1998. See further discussion in "Liquidity and Capital Resources - Risk Management." Revenue associated with electric power marketing increased $28.8 million for the year ended December 31, 1997 compared to 1996, primarily because the Company had minimal transactions in this market during 1996. Due to a lack of profitability, the Company elected to discontinue trading electric power and began to evaluate its role in this emerging business, 16 during the second half of 1997. Accordingly, revenue in 1998 and future years will decrease compared to 1997. The increase in product purchases of $302.3 million to $2.1 billion for the year ended December 31, 1997 compared to 1996, is primarily a combination of higher gas prices and increased sales of NGLs purchased from third parties. Contributing to the increase in product purchases for the year ended December 31, 1997 compared to 1996 were higher payments to producers related to the Company's "keepwhole" contracts at its Granger facility. Under a "keepwhole" contract, the Company's margin is reduced when the value of NGLs declines relative to the value of gas. Also, contributing to the increases in product purchases for the year ended December 31, 1997 compared to 1996, were lower of cost or market write-downs of NGL and gas inventories of $1.1 million and $129,000, respectively. Plant operating expense increased approximately $5.0 million for the year ended December 31, 1997 compared to 1996. The increase was primarily due to additional compression costs associated with the MIGC pipeline. In addition, results of operations for the year ended December 31, 1997 were adversely affected by additional costs associated with the Bethel Treating facility. As a result of start-up costs associated with opening the facility and depreciation, the Bethel Treating facility did not contribute positively to earnings in 1997. Depreciation, depletion and amortization decreased $4.0 million for the year ended December 31, 1997 compared to 1996. The decrease was primarily due to decreases in produced volumes related to the Company's Black Lake facility which resulted in a decrease in the associated depletion. Interest expense decreased $7.0 million for the year ended December 31, 1997 compared to 1996. The decrease in interest expense was primarily due to lower average outstanding debt balances due to the use of the Company's net proceeds from the November 1996 public offering of 6,325,000 shares of Common Stock to reduce indebtedness under the Revolving Credit Facility. However, the Company's borrowings under its long-term debt agreements, as of December 31, 1997, are consistent with prior year balances, primarily due to costs associated with the construction of the Bethel Treating facility. A portion of the decrease in interest expense was also due to interest being capitalized related to the construction of the Bethel Treating facility. The Bethel Treating facility is expected to be substantially completed during the first quarter of 1998, at which time interest will no longer be capitalized to this project. Overall, profitability for the year ended December 31, 1997, was less than anticipated due to several factors. Combined product purchases as a percentage of gas, NGL and electric power sales increased from 91% to 92% for the year ended December 31, 1997 compared to 1996. Over the past several years, the Company has experienced narrowing margins related to the increasing competitiveness of the natural gas marketing industry. During the year ended December 31, 1997, the Company's marketing margins were reduced by approximately 50% compared to 1996. Included in the sale of gas and product purchases for the last half of 1997, is the sale of approximately 11.5 Bcf of gas, previously stored in the Katy Facility, at a margin of approximately $.20 per Mcf. 17 YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995 (000S, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
Year Ended December 31, ------------------------- Percent 1996 1995 Change ------------ ----------- ------ FINANCIAL RESULTS: Revenues....................................................... $2,091,009 $1,256,984 66 Gross profit................................................... 105,479 75,211 40 Net income (loss).............................................. 27,941 (6,108) - Earnings (loss) per share of common stock...................... .66 (.84) - Earnings (loss) per share of common stock - assuming dilution.. .66 (.84) - Net cash provided by operating activities...................... $ 168,266 $ 86,373 95 OPERATING DATA: Average gas sales (MMcf/D)..................................... 1,794 1,572 14 Average NGL sales (MGal/D)..................................... 3,744 2,890 30 Average gas prices ($/Mcf)..................................... $ 2.19 $ 1.53 43 Average NGL prices ($/Gal)..................................... $ .41 $ .31 32
Net income increased $34.0 million and net cash provided by operating activities increased $81.9 million for the year ended December 31, 1996 compared to 1995. The increase in net income for the year was partially due to a $12.4 million, after-tax, impairment loss recorded in 1995 in connection with the adoption of SFAS No. 121 and a $1.3 million, after-tax, restructuring charge the Company recorded in 1995 relating to its cost reduction program. In addition, net income was positively affected by higher revenues attributable to increases in prices and volumes, partially offset by higher product purchase costs associated with the Company's third-party gas sales. Revenues from the sale of gas increased approximately $564.5 million for the year ended December 31, 1996 compared to 1995. Average gas sales volumes increased 222 MMcf per day to 1,794 MMcf per day for the year ended December 31, 1996 compared to 1995, largely due to an increase of approximately 225 MMcf per day in the sale of gas purchased from third parties, partially offset by decreased sales at the Company's Black Lake facility. Average gas prices realized by the Company increased $.66 per Mcf to $2.19 per Mcf for the year ended December 31, 1996 compared to 1995. Included in the realized gas price was approximately $7.2 million of loss recognized in the year ended December 31, 1996 related to futures positions on equity volumes. Revenues from the sale of NGLs increased approximately $229.8 million for the year ended December 31, 1996 compared to 1995. Average NGL sales volumes increased 854 MGal per day to 3,744 MGal per day for the year ended December 31, 1996 compared to 1995, largely due to an increase of approximately 715 MGal per day in the sale of NGLs purchased from third parties. Average NGL prices realized by the Company increased $.10 per gallon to $.41 per gallon for the year ended December 31, 1996 compared to 1995. Included in the realized NGL price was approximately $11.6 million of loss recognized in the year ended December 31, 1996 related to futures positions on equity volumes. Revenue associated with electric power marketing was approximately $30.7 million; the Company entered this market at the end of 1995. Other net revenue increased approximately $5.5 million for the year ended December 31, 1996 compared to 1995. The increase was largely due to an increase of approximately $2.9 million in partnership income, primarily attributable to Redman Smackover, and a $1.9 million gain recognized on the sale of the Temple facility. The increase in product purchases corresponds to the increase in third-party product sales. Combined product purchases as a percentage of gas, NGL and electric power sales increased from 88% to 91% for the year ended December 31, 1996 compared to 1995. The increased product purchase percentage is a continuing trend based upon the growth of third-party sales, which typically have lower margins than sales of the Company's equity production. Over the past several years, the Company has experienced narrowing margins related to the increasing competitiveness of the natural gas marketing industry. 18 Selling and administrative expense increased $2.8 million for the year ended December 31, 1996 compared to 1995, primarily as a result of growth in the Company's marketing operations and higher benefit costs. Depreciation, depletion and amortization decreased $2.2 million for the year ended December 31, 1996 compared to the prior year. The decrease was attributable to decreases in production related to the Company's oil and gas properties, primarily at the Company's Black Lake facility. In addition, the Company recorded a $17.6 million write-down of certain oil and gas assets and plant facilities in the fourth quarter of 1995 in connection with its adoption of SFAS No. 121. The lower asset values contributed to the reduction in depreciation, depletion and amortization expense for the year ended December 31, 1996. These decreases were offset by increases related to various property additions. Interest expense decreased $2.7 million for the year ended December 31, 1996 compared to the prior year. The decrease was primarily due to the use of improved cash flows from operations and the use of the Company's net proceeds from the November 1996 public offering of 6,325,000 shares of Common Stock to reduce indebtedness under the Revolving Credit Facility. LIQUIDITY AND CAPITAL RESOURCES The Company's sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under its financing facilities and proceeds from offerings of equity securities. In the past, these sources have been sufficient to meet its needs and finance the growth of the Company's business. The Company can give no assurance that the historical sources of liquidity and capital resources will be available for future development and acquisition projects, and it may be required to seek alternative financing sources. Net cash provided by operating activities is primarily affected by product prices and sales of inventory, the Company's success in increasing the number and efficiency of its facilities and the volumes of natural gas processed by such facilities, as well as the margin on third-party product purchased for resale. The Company's continued growth will be dependent upon success in the areas of marketing, additions to dedicated plant reserves, acquisitions and new project development. Historically, oil prices have been volatile and subject to rapid price fluctuations. The oil and gas industry is currently experiencing significantly declining oil prices. Such prices have declined approximately 25% during the first quarter of 1998 to approximately $13.26 per barrell as of March 16, 1998. In addition, the start-up volumes associated with the Bethel Treating facility have been lower that anticipated. If the current price in of oil and associated NGLs continues or declines and volumes associated with the Bethel Treating facility do not increase, the Company is uncertain as to its ability to satisfy its interest coverage covenants under certain of its debt agreements during the last half of 1998. However, the Company believes it can obtain amendments or waivers from the necessary lenders. The Company believes that the amounts available to be borrowed under the Revolving Credit Facility, together with cash provided by operating activities, will provide it with sufficient funds to connect new reserves, maintain its existing facilities and complete its current capital expenditure program. Depending on the timing and the amount of the Company's future projects, it may be required to seek additional sources of capital. The Company's ability to secure such capital is restricted by its credit facilities, although it may request additional borrowing capacity from its lenders, seek waivers from its lenders to permit it to borrow funds from third parties, seek replacement credit facilities from other lenders, use stock as a currency for an acquisition, sell existing assets or a combination of such alternatives. While the Company believes that it would be able to secure additional financing, if required, no assurance can be given that it will be able to do so or as to the terms of any such financing. Despite the declining oil prices experienced in the first quarter of 1998, the Company also believes that cash provided by operating activities will be sufficient to meet its debt service and preferred stock dividend requirements in 1998. 19 The Company's sources and uses of funds for the year ended December 31, 1997 are summarized as follows (000s):
SOURCES OF FUNDS: Borrowings under revolving credit facility.. $1,894,950 Net cash provided by operating activities... 114,755 Other....................................... 20,273 ---------- Total sources of funds................... $2,029,978 ========== USES OF FUNDS: Payments related to long-term debt.......... $1,833,940 Capital expenditures........................ 198,901 Dividends paid.............................. 16,864 ---------- Total uses of funds...................... $2,049,705 ==========
Additional sources of liquidity available to the Company are volumes of gas and NGLs in storage facilities. The Company stores gas and NGLs primarily to ensure an adequate supply for long-term sales contracts and for resale during periods when prices are favorable. The Company held gas in storage and held imbalances for such purposes of approximately 6.0 Bcf at an average cost of $1.97 per Mcf at December 31, 1997 compared to 10.4 Bcf at an average cost of $1.84 per Mcf at December 31, 1996, at various storage facilities, including the Katy Facility. At December 31, 1997, the Company had hedging contracts in place for anticipated sales of approximately 4.8 Bcf of stored gas at a weighted average price of $2.28 per Mcf for the stored inventory. The Company held NGLs in storage of 14,400 MGal, consisting primarily of propane and normal butane, at an average cost of $.37 per gallon and 16,100 MGal at an average cost of $.42 per gallon at December 31, 1997 and December 31, 1996, respectively, at various third-party storage facilities. At December 31, 1997, the Company had hedging contracts in place for anticipated sales, consisting primarily of propane, at a weighted average price of $.36 per gallon for approximately 3,200 MGal of the stored NGLs in inventory. The Company has been successful overall in replacing production with new reserves. Historically, the Company has connected additional reserves that more than offset production from reserves dedicated to existing facilities. However, certain individual plants have experienced declines in dedicated reserves. In 1997, including the reserves associated with the Company's joint ventures and partnerships, the Company connected new reserves to its gathering systems to replace approximately 220% of 1997 production. On a Company-wide basis, dedicated reserves increased from approximately 2.8 Tcf as of December 31, 1996 to approximately 3.3 Tcf at December 31, 1997. 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 of $96.4 million were primarily used to reduce indebtedness under the Revolving Credit Facility. The Company has effective shelf registration statements filed with the Securities and Exchange 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. Risk Management Activities 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, NGL and power 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 20 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 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 creditworthy 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. As of December 31, 1997, the Company held a notional quantity of approximately 480 Bcf of natural gas futures, swaps and options, extending from January 1998 to December 1999 with a weighted average duration of approximately four months. This was comprised of approximately 230 Bcf of long positions and 250 Bcf of short positions in such instruments. As of December 31, 1997, the Company held a notional quantity of approximately 148,000 MGal of NGL futures, swaps and options, extending from January 1998 to December 1998 with a weighted average duration of approximately five months. This was comprised of approximately 93,000 MGal of long positions and 55,000 MGal of short positions in such instruments. As of December 31, 1996, the Company held a notional quantity of approximately 250 Bcf of natural gas futures, swaps and options, extending from January 1997 to October 1998 with a weighted average duration of approximately four months. This was comprised of approximately 120 Bcf of long positions and 130 Bcf of short positions in such instruments. As of December 31, 1996, the Company held a notional quantity of approximately 185,000 MGal of NGL futures, swaps and options, extending from January 1997 to December 1997 with a weighted average duration of approximately five months. This was comprised of approximately 55,000 MGal of long positions and 130,000 MGal of short positions in such instruments. As of December 31, 1997 and 1996, the Company did not have any material hedging contracts in place associated with electric power. The Company has hedged a portion of its equity volumes of gas and NGLs in 1998, particularly in the first quarter, at pricing levels in excess of its 1998 operating budget. The Company's hedging strategy establishes a minimum and maximum price to the Company while allowing market participation between these levels. As of March 4, 1998, the Company had hedged approximately 75% of its anticipated equity gas for 1998 at a weighted average NYMEX-equivalent minimum price of $2.19 per Mcf, including approximately 85% of first quarter anticipated equity volumes at a weighted average NYMEX-equivalent minimum price of $2.42 per Mcf. Additionally, the Company has hedged approximately 25% of its anticipated equity NGLs for 1998 at a weighted average composite Mont Belvieu and West Texas Intermediate Crude-equivalent minimum price of $.40 per gallon ($16.75 per barrel), including approximately 50% of first quarter anticipated equity volumes at a weighted average composite Mont Belvieu and West Texas Intermediate Crude- equivalent minimum price of $.36 per gallon ($15.20 per barrel). At December 31, 1997, the Company had $512,000 of losses deferred in inventory that will be recognized primarily during the first quarter of 1998 and are expected to be offset by margins from the Company's related forward fixed price hedges and physical sales. At December 31, 1997, the Company had unrecognized net losses of $2.0 million 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. 21 During 1996, the Company began to enter into physical gas transactions payable in Canadian dollars. The Company enters into forward purchases of Canadian dollars from time to time to fix the cost of its future Canadian dollar denominated natural gas purchase, 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 future payment obligation is made and the actual payment date of such obligation. As of December 31, 1997 the notional value of such contracts was approximately $5.5 million in Canadian dollars. As of December 31, 1996, the notional value of such contracts was immaterial. 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 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 from such speculative activities for the years ended December 31, 1997 and 1996 were not material. Capital Investment Program For the years ended December 31, 1997, 1996 and 1995 the Company expended $198.9 million, $74.6 million and $78.5 million, respectively, on new projects and acquisitions. For the year ended December 31, 1997, the Company's expenditures consisted of the following: (i) $133.2 million for new connects, system expansions, the Bethel Treating facility and asset consolidations; (ii) $12.1 million for maintaining existing facilities; (iii) $49.3 for exploration and production activities and acquisitions; (iv) $2.8 million related to the Katy Facility; and (v) $1.5 million of miscellaneous expenditures. Capital expenditures related to existing operations are expected to be approximately $129.4 million during 1998, consisting of the following: capital expenditures related to gathering, processing and pipeline assets are expected to be approximately $84.8 million, of which approximately $74.8 million is budgeted to be used for new connects, system expansions and asset consolidations and approximately $10.0 million for maintaining existing facilities. The Company expects capital expenditures on exploration and production activities, the Katy Facility and miscellaneous items to be approximately $40.2 million, $1.5 million and $2.9 million, respectively. The Company has initiated a comprehensive review of its computer systems to identify the systems that could be affected by the "Year 2000" issue and is in the process of making the appropriate modifications to its computer systems. The Company expects to incur internal staff costs as well as some consulting and other expenses in order to prepare the systems for the year 2000. A portion of these costs are not likely to be incremental costs to the Company, but rather will represent costs which will be recorded as assets and depreciated. Accordingly, the Company does not expect the amounts required to be expensed over the next year to have a material effect on its results of operations. Costs incurred during the year ended December 31, 1997 were immaterial. The Company anticipates its Year 2000 conversion project to be completed in a timely manner. However, there can be no assurance that the systems of other companies on which the Company relies, will also be converted in a timely manner or that any such failure to convert by another company would not have an adverse effect on the Company. In order to minimize this impact, the Company is in contact with its vendors and customers to work towards their compliance. Financing Facilities Revolving Credit Facility. The Company's unsecured variable rate Revolving Credit Facility, was restated and amended on May 30, 1997. The Revolving Credit Facility is with a syndicate of nine banks and provides for a maximum borrowing commitment of $300 million, $156.5 million of which was outstanding at December 31, 1997. The Revolving Credit Facility's commitment period will terminate on March 31, 2002. At that time, any amounts outstanding on the Revolving Credit Facility will become due and payable. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, at the Federal Funds rate plus .50%, or at 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 the Company's debt to capitalization ratio. At December 31, 1997, the spread was .35% over the Eurodollar rate and the facility fee was .175%. The rate payable, including the facility fee, on the Revolving Credit Facility at December 31, 1997 was 6.497%. The Company incurred approximately $425,000 during 1997 of fees in association with the restatement and amendment; such amounts were capitalized and will be amortized over the term of the agreement. Pursuant to the Revolving Credit Facility, the Company is required to maintain a debt to capitalization ratio (as defined therein) of not more than 60% as of the end of any fiscal quarter and a ratio of EBITDA (as defined therein) to interest and dividends on preferred stock as of the end of any fiscal quarter of not less than 2.75 to 1.0 through December 31, 1998, 3.0 to 1.0 from January 1, 1999 22 through December 31, 1999 and 3.25 to 1.0 thereafter. The Company generally utilizes excess daily funds to reduce any outstanding balances on the Revolving Credit Facility and associated interest expense and it intends to continue such practice. Master Shelf Agreement. In December 1991, the Company entered into a Master Shelf Agreement (as amended and restated, the "Master Shelf") with The Prudential Insurance Company of America ("Prudential"). The Master Shelf Agreement, as further restated and amended, is fully utilized, as indicated in the following table (000s):
Interest Final Issue Date Amount Rate Maturity Principal Payments Due - -------------------- -------- ----- ------------------ ----------------------------------------------- October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000 October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003 September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity 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 -------- $200,000 ========
Pursuant to the Master Shelf Agreement, the Company is required to maintain a current ratio (as defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal to the sum of $345 million plus 50% of consolidated net earnings earned from June 30, 1995 plus 75% of the net proceeds of any equity offerings after June 30, 1995, a debt to capitalization ratio (as defined therein) of no more than 55%, and an EBITDA (as defined therein) to interest ratio of not less than 3.25 to 1.0 through October 31, 1997 and 3.75 to 1.0 thereafter. The Company is prohibited from declaring or paying dividends on any capital stock on or after June 30, 1995, that in the aggregate exceed the sum of $50 million plus 50% of consolidated net earnings earned after June 30, 1995, plus the cumulative net proceeds received by the Company after June 30, 1995 from the sale of any equity securities. At December 31, 1997, $118.5 million was available under this limitation. The Company presently intends to finance the $8.3 million payment due on October 27, 1998 with amounts available under the Revolving Credit Facility. Term Loan Facility. The Company also had a Term Loan Facility with four banks which bore interest at 9.87% in 1997. In September 1997, the Company made the final payment on the Term Loan Facility with amounts available under the Revolving Credit Facility. 1993 Senior Notes. On April 28, 1993, the Company sold $50 million of 7.65% Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance companies. Annual principal payments of $7.1 million on the 1993 Senior Notes were and are due on April 30 of each year from 1997 through 2002, with any remaining principal and interest outstanding due on April 30, 2003. The Company financed the $7.1 million payment paid on April 30, 1997 with amounts available under the Revolving Credit Facility. The Company presently intends to finance the $7.1 million payment due on April 30, 1998 with amounts available under the Revolving Credit Facility. The 1993 Senior Notes are unsecured and contain certain financial covenants that substantially conform with those contained in the Master Shelf Agreement. 1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a group of insurance companies in the fourth quarter of 1995, with an interest rate of 8.16% per annum and principal due in a single payment in December 2005. The 1995 Senior Notes are unsecured and contain certain financial covenants that conform with those contained in the Master Shelf Agreement. Receivables Facility. In April 1995, the Company entered into an agreement with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America National Trust and Savings Association, as agent, pursuant to which the Company could sell to RCC at face value on a revolving basis an undivided interest in certain of the Company's trade receivables. Under the Receivables Facility, the Company sold $75 million of trade receivables at a rate equal to RCC's commercial paper rate plus .375%. Effective June 12, 1997, the Company elected to terminate the facility. All amounts then outstanding were repaid with amounts available under the Revolving Credit Facility. Covenant Compliance. At December 31, 1997, the Company was in compliance with all covenants in its loan agreements. Taking into account all the covenants contained in the Company's financing facilities and maturities of long-term debt during 1997, the Company had approximately $85 million of available borrowing capacity at December 31, 1997. Historically, oil prices have been volatile and subject to rapid price fluctuations. The oil and gas industry is currently experiencing significantly declining oil prices. Such prices have declined approximately 25% during the first quarter of 1998 to approximately $13.26 per barrel as of March 16, 1998. In addition, the start-up volumes associated with the Bethel Treating facility have been lower than anticipated. If the current pricing of oil and associated NGLs continues or declines and volumes associated with the Bethel Treating facility do not increase, the Company is uncertain as to its ability to satisfy its interest coverage covenants under certain of its debt agreements during the last half of 1998. However, the Company believes it can obtain amendments or waivers from the necessary lenders. 23 ENVIRONMENTAL The construction and operation of the Company's gathering lines, 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 the Company's facilities or at facilities to which the Company sends wastes for disposal. In most instances, the applicable regulatory requirements relate to water and air pollution control or waste management. The Company employs seven environmental engineers and six regulatory compliance specialists to monitor environmental compliance and potential liabilities at its facilities. Prior to consummating any major acquisition, the Company's environmental engineers perform audits on the facilities to be acquired. In addition, on an ongoing basis, the environmental engineers perform systematic environmental assessments of the Company's existing facilities. The Company believes that it is in substantial compliance with applicable material environmental laws and regulations. Environmental regulation can increase the cost of planning, designing, constructing and operating the Company's facilities. The Company believes that the costs for compliance with current environmental laws and regulations have not had and will not have a material effect on the Company's financial position or results of operations. In September 1997, the Texas Natural Resources Conservation Commission (the "TNRCC"), which has authority to regulate, among other things, stationary air emissions sources, created a committee to make recommendations to the TNRCC 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. The Company operates a number of such sources within the State of Texas, including its Edgewood plant, portions of its Midkiff plant and many of its compressors. The recommendations proposed by the committee would create a voluntary permitting program for grandfathered sources, including certain incentives to participate, such as the ability to operate in such a source in a flexible manner. It is not clear which of the committee's recommendations, if any, that the TNRCC will implement and it is not possible to assess the potential effect on the Company until final regulations are promulgated. The Company anticipates that it is reasonably likely that the trend in environmental legislation and regulation will continue to be towards stricter standards. The Company is unaware of future environmental standards that are reasonably likely to be adopted that will have a material effect on the Company's financial position or results of operations, but it cannot rule out that possibility. The Company is in the process of voluntarily cleaning up substances at certain facilities that it operates. The Company's expenditures for environmental evaluation and remediation at existing facilities have not been significant in relation to the results of operations of the Company and totaled approximately $1.4 million for the year ended December 31, 1997, including approximately $801,000 in air emissions fees to the states in which it operates. Although the Company anticipates that such environmental expenses will increase over time, the Company does not believe that such increases will have a material effect on the Company's financial position or results of operations. BUSINESS STRATEGY The Company's four-part business plan is designed to increase profitability through: (i) investing in projects that complement and extend its core gas gathering, processing and marketing business; (ii) creating ventures with producers who will dedicate additional acreage to the Company; (iii) expanding its energy sales volumes by maximizing its asset base, firm transportation and storage contracts and other contractual arrangements; and (iv) optimizing the profitability of existing operations. Expansion of Core Business The Company continually evaluates investments in projects that meet its objectives of complementing existing operations, expanding into new areas or providing enhanced marketing opportunities. These projects typically include gas gathering, treating, processing, transportation or storage assets, and NGL product upgrade equipment. See further discussion in "Business and Properties - Significant Acquisitions, Projects and Dispositions." Increase Dedicated Acreage The Company has entered and intends to continue to enter into agreements which will provide it with new acreage to replace declines in reserves and generate additional volumes for gathering and processing at its facilities and encourage expansion into basins where the Company's facilities are located. The Company believes that in order to secure additional gas supply for its facilities, it must be willing to increase its participation in exploration and production activities. However, the Company, where possible, has entered into agreements with third parties to reduce a portion of the risk associated with exploration and production activities. See further discussion in "Business and Properties - Significant Acquisitions, Projects and Dispositions." 24 Expand Energy Marketing Services and Volumes The Company is a full-service marketer primarily of gas and NGL products. The Company focuses on the individual needs of its customers, primarily in the Rocky Mountain region, and is committed to developing products and services that are tailored to meet their requirements. The Company plans to expand its energy marketing activities by: (i) maximizing profitability on volumes produced at the Company's facilities; (ii) efficient use of various firm transportation and storage contracts and other contractual arrangements to increase profitability while limiting carrying risk; (iii) continuing to pursue higher-margin, end-use markets, primarily in the Rocky Mountain region; and (iv) increasing third-party gas and NGL sales volumes. The Company believes it competes effectively with other marketers due to its national marketing presence and the marketing information gained thereby, the services it provides and its physical asset base. Optimize Profitability The Company seeks to optimize the profitability of its operations by: (i) maintaining or increasing natural gas throughput levels; (ii) increasing its efficiency through the consolidation of existing facilities; (iii) investing in assets that enhance NGL value; (iv) selling non-strategic assets; and (v) controlling operating and overhead expenses. In order to maximize its competitive advantages, the Company continually monitors the economic performance of each of its operating facilities to ensure that a desired cash flow objective and operating efficiency is achieved. 25 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Consolidated Financial Statements Western Gas Resources, Inc.'s Consolidated Financial Statements as of December 31, 1997 and 1996 and for each of the three years in the period ended December 31, 1997:
Page ---- Report of Management....................................... 27 Report of Independent Accountants.......................... 28 Consolidated Balance Sheets................................ 29 Consolidated Statement of Cash Flows....................... 30 Consolidated Statement of Operations....................... 31 Consolidated Statement of Changes in Stockholders' Equity.. 32 Notes to Consolidated Financial Statements................. 33
26 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 Price Waterhouse 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. Signature Title - --------- ----- /S/ L. F. Outlaw - ---------------- L. F. Outlaw President and Chief Operating Officer /S/ William J. Krysiak - ---------------------- William J. Krysiak Vice President - Finance (Principal Financial and Accounting Officer) 27 REPORT OF INDEPENDENT ACCOUNTANTS --------------------------------- To the Board of Directors and Stockholders of Western Gas Resources, Inc. In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of cash flows, of operations, and of changes in stockholders' equity present fairly, in all material respects, the financial position of Western Gas Resources, Inc. and its subsidiaries at December 31, 1997 and 1996, and the results of their cash flows and their operations for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. 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 generally accepted auditing standards 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. As discussed in Note 2 to the financial statements, the Company changed its method of accounting for the impairment of long-lived assets in 1995 to comply with the provisions of Statement of Financial Accounting Standards No. 121. PRICE WATERHOUSE LLP Denver, Colorado March 16, 1998 28
WESTERN GAS RESOURCES, INC. CONSOLIDATED BALANCE SHEET (000s, except share data) December 31, ----------------------- ASSETS 1997 1996 ------ ---------- ---------- Current assets: Cash and cash equivalents.................................................... $ 19,777 $ 39,504 Trade accounts receivable, net............................................... 258,791 338,708 Product inventory............................................................ 17,261 25,972 Parts inventory.............................................................. 9,405 2,599 Other........................................................................ 2,364 1,477 ---------- ---------- Total current assets........................................................ 307,598 408,260 ---------- ---------- Property and equipment: Gas gathering, processing, storage and transmission.......................... 1,050,676 938,902 Oil and gas properties and equipment......................................... 136,129 144,732 Construction in progress..................................................... 64,268 35,250 ---------- ---------- 1,251,073 1,118,884 Less: Accumulated depreciation, depletion and amortization................... (294,350) (252,571) ---------- ---------- Total property and equipment, net........................................... 956,723 866,313 ---------- ---------- Other assets: Gas purchase contracts (net of accumulated amortization of $27,554 and $24,552, respectively)...................................................... 43,687 46,689 Other........................................................................ 40,268 40,369 ---------- ---------- Total other assets.......................................................... 83,955 87,058 ---------- ---------- Total assets................................................................... $1,348,276 $1,361,631 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------ Current liabilities: Accounts payable............................................................. $ 326,696 $ 386,268 Accrued expenses............................................................. 27,151 28,670 Dividends payable............................................................ 4,217 4,215 ---------- ---------- Total current liabilities................................................... 358,064 419,153 Long-term debt................................................................. 441,357 379,500 Deferred income taxes payable, net............................................. 80,743 82,511 ---------- ---------- Total liabilities........................................................... 880,164 881,164 ---------- ---------- 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; 32,171,453 and 32,134,151 shares issued, respectively..................................... 3,217 3,213 Treasury stock, at cost; 25,016 shares in treasury........................... (788) (788) Additional paid-in capital................................................... 399,554 397,061 Retained earnings............................................................ 66,999 82,378 Notes receivable from key employees secured by common stock.................. (1,286) (1,813) ---------- ---------- Total stockholders' equity.................................................. 468,112 480,467 ---------- ---------- Total liabilities and stockholders' equity..................................... $1,348,276 $1,361,631 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements. 29 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (000s)
Year Ended December 31, -------------------------------------- 1997 1996 1995 ----------- ------------ ---------- Reconciliation of net income to net cash provided by operating activities: Net income (loss)........................................................... $ 1,487 $ 27,941 $ (6,108) Add income items that do not affect cash: Depreciation, depletion and amortization................................... 59,248 63,207 65,361 Deferred income taxes...................................................... 465 12,538 1,246 Distributions in excess of equity income, net.............................. 1,764 4,339 - Gain on the sale of property and equipment................................. (4,681) (2,747) (939) Loss on the impairment of property and equipment........................... 34,615 - 17,642 Other non-cash items, net.................................................. 3,250 336 (1,360) ----------- ----------- --------- 96,148 105,614 75,842 ----------- ----------- --------- Adjustments to working capital to arrive at net cash provided by operating activities: Decrease (increase) in trade accounts receivable........................... 79,963 (134,538) (69,982) Decrease in product inventory.............................................. 7,480 2,115 22,985 Increase in parts inventory................................................ (6,806) (172) (136) Increase in other current assets........................................... (1,027) (42) (157) Decrease (increase) in other assets and liabilities, net................... 257 (733) (391) (Decrease) increase in accounts payable.................................... (59,572) 186,758 54,269 (Decrease) increase in accrued expenses.................................... (1,688) 9,264 3,943 ----------- ----------- --------- Total adjustments......................................................... 18,607 62,652 10,531 ----------- ----------- --------- Net cash provided by operating activities................................... 114,755 168,266 86,373 ----------- ----------- --------- Cash flows from investing activities: Purchases of property and equipment, including acquisitions................ (196,293) (74,203) (56,138) Proceeds from the disposition of property and equipment.................... 20,034 7,656 13,328 Contributions to unconsolidated affiliates................................. (2,608) (352) (4,237) Distribution from unconsolidated affiliates................................ - 1,500 - Gas purchase contracts acquired............................................ - - (18,146) ----------- ----------- --------- Net cash used in investing activities....................................... (178,867) (65,399) (65,193) ----------- ----------- --------- Cash flows from financing activities: Net proceeds from issuance of common stock................................. - 96,376 - Net proceeds from exercise of common stock options......................... 239 62 117 Proceeds from issuance of long-term debt................................... - - 92,000 Payments on long-term debt................................................. (94,643) (12,500) (25,000) Borrowings under revolving credit facility................................. 1,894,950 1,035,377 625,400 Payments on revolving credit facility...................................... (1,738,450) (1,172,877) (655,900) Debt issue costs paid...................................................... (847) - (1,884) Dividends paid............................................................. (16,864) (15,596) (16,796) Redemption of preferred stock.............................................. - - (42,030) ----------- ----------- --------- Net cash provided by (used in) financing activities......................... 44,385 (69,158) (24,093) ----------- ----------- --------- Net (decrease) increase in cash............................................. (19,727) 33,709 (2,913) Cash and cash equivalents at beginning of period............................ 39,504 5,795 8,708 ----------- ----------- --------- Cash and cash equivalents at end of period.................................. $ 19,777 $ 39,504 $ 5,795 =========== =========== =========
The accompanying notes are an integral part of the consolidated financial statements. 30 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF OPERATIONS (000s, except share and per share amounts)
Year Ended December 31, ----------------------------------------- 1997 1996 1995 ----------- ------------ ------------ Revenues: Sale of gas............................................................ $ 1,657,479 $ 1,440,882 $ 876,399 Sale of natural gas liquids............................................ 611,969 561,581 331,760 Sale of electric power................................................. 59,477 30,667 - Processing, transportation and storage revenue......................... 40,906 44,943 41,358 Other, net............................................................. 15,429 12,936 7,467 ----------- ----------- ----------- Total revenues.................................................. 2,385,260 2,091,009 1,256,984 ----------- ----------- ----------- Costs and expenses: Product purchases...................................................... 2,146,430 1,844,151 1,040,265 Plant operating expense................................................ 78,113 73,116 71,030 Oil and gas exploration and production costs........................... 7,714 5,056 5,117 Depreciation, depletion and amortization............................... 59,248 63,207 65,361 Selling and administrative expense..................................... 29,446 29,411 26,610 Interest expense....................................................... 27,474 34,437 37,160 Restructuring charge................................................... - - 2,065 Loss on the impairment of property and equipment....................... 34,615 - 17,642 ----------- ----------- ----------- Total costs and expenses.......................................... 2,383,040 2,049,378 1,265,250 ----------- ----------- ----------- Income (loss) before income taxes........................................ 2,220 41,631 (8,266) Provision (benefit) for income taxes: Current........................................................... 268 1,152 (3,404) Deferred.......................................................... 465 12,538 1,246 ----------- ----------- ----------- Total provision (benefit) for income taxes........................ 733 13,690 (2,158) ----------- ----------- ----------- Net income (loss)........................................................ 1,487 27,941 (6,108) Preferred stock requirements............................................. (10,439) (10,439) (15,431) ----------- ----------- ----------- Income (loss) attributable to common stock............................... $ (8,952) $ 17,502 $ (21,539) =========== =========== =========== Earnings (loss) per share of common stock................................ $(.28) $.66 $(.84) =========== =========== =========== Weighted average shares of common stock outstanding...................... 32,134,011 26,519,635 25,753,738 =========== =========== =========== Earnings (loss) per share of common stock - assuming dilution............ $(.28) $.66 $(.84) =========== =========== =========== Weighted average shares of common stock outstanding - assuming dilution.. 32,137,803 26,541,565 25,788,955 =========== =========== ===========
The accompanying notes are an integral part of the consolidated financial statements. 31 WESTERN GAS RESOURCES, INC. CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY (000s, except share amounts)
Shares of 7.25% 7.25% Cumulative Shares of Cumulative Senior Shares of $2.625 Senior Perpetual $ 2.28 Cumulative Shares Perpetual $2.28 Convertible Cumulative Convertible Shares of Common Convertible Cumulative Preferred Preferred Preferred of Common Stock Preferred Preferred Stock Stock Stock Stock in Treasury Stock Stock --------- --------- --------- ---------- ----------- --------- --------- Balance at December 31, 1994.............. 400,000 1,400,000 2,760,000 25,712,301 25,016 $ 40 $ 140 Net loss, 1995............................ - - - - - - - Stock options exercised................... - - - 57,411 - - - Redemption of 7.25% cumulative senior..... perpetual convertible preferred stock... (400,000) - - - - (40) - Dividends declared on common stock........ - - - - - - - Dividends declared on 7.25% cumulative.... senior perpetual convertible preferred stock........................ - - - - - - - Dividends declared on $2.28 cumulative.... preferred stock......................... - - - - - - - Dividends declared on $2.625 cumulative... convertible preferred stock............. - - - - - - - --------- --------- --------- ---------- ----------- --------- --------- Balance at December 31, 1995.............. - 1,400,000 2,760,000 25,769,712 25,016 - 140 Net income, 1996.......................... - - - - - - - Stock options exercised................... - - - 14,423 - - - Loans forgiven............................ - - - - - - - Common stock offering..................... - - - 6,325,000 - - - 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, 1996.............. - 1,400,000 2,760,000 32,109,135 25,016 - 140 Net income, 1997.......................... - - - - - - - Stock options exercised................... - - - 37,302 - - - 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 ========= ========= ========= ========== =========== ========= ========= $2.625 Cumulative Notes Total Convertible Additional Receivable Stock- Preferred Common Treasury Paid-In Retained from Key holder's Stock Stock Stock Capital Earnings Employees Equity --------- --------- --------- ---------- ----------- --------- --------- Balance at December 31, 1994.............. $ 276 $ 2,574 $ (788) $ 338,926 $ 97,040 $ (1,525) $ 436,683 Net loss, 1995............................ - - - - (6,108) - (6,108) Stock options exercised................... - 6 - 514 - (356) 164 Redemption of 7.25% cumulative senior..... perpetual convertible preferred stock... - - - (38,206) (3,784) - (42,030) Dividends declared on common stock........ - - - - (5,153) - (5,153) Dividends declared on 7.25% cumulative.... senior perpetual convertible preferred.. stock................................... - - - - (1,208) - (1,208) 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, 1995.............. 276 2,580 (788) 301,234 70,348 (1,881) 371,909 Net income, 1996.......................... - - - - 27,941 - 27,941 Stock options exercised................... - 1 - 83 - (24) 60 Loans forgiven............................ - - - - - 92 92 Common stock offering..................... - 632 - 95,744 - - 96,376 Dividends declared on common stock........ - - - - (5,472) - (5,472) 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, 1996.............. 276 3,213 (788) 397,061 82,378 (1,813) 480,467 Net income, 1997.......................... - - - - 1,487 - 1,487 Stock options exercised................... - 4 - 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.............. $ 276 $ 3,217 $ (788) $ 399,554 $ 66,999 $ (1,286) $ 468,112 ========= ========= ========= ========== =========== ========= =========
The accompanying notes are an integral part of the consolidated financial statements. 32 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - NATURE OF ORGANIZATION - ------------------------------- Western Gas Resources, Inc. (the "Company") is an independent gas gatherer and processor and energy marketer providing a full range of services to its customers from the wellhead to the delivery point. The Company designs, constructs, owns and operates natural gas gathering, processing, treating and storage facilities in major gas-producing basins in the Rocky Mountain, Mid- Continent, Gulf Coast and Southwestern regions of the United States. The Company connects producers' wells to its gathering systems for delivery to its processing or treating plants, processes the natural gas to extract natural gas liquids ("NGLs") and treats the natural gas in order to meet pipeline specifications. The Company markets gas and NGLs nationwide and in Canada, providing risk management, storage, transportation, scheduling, peaking and other services to a variety of customers. The Company explores and develops certain producing properties, primarily in Wyoming, Louisiana and Texas, in support of its existing facilities and to expand into new producing areas. 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 is expanding its Powder River Basin coal bed methane natural gas gathering system and developing its own coal seam gas reserves in Wyoming. The Company has acquired drilling rights in the vicinity of known coal bed methane production. During the years ended December 31, 1997 and 1996, the Company has expended approximately $32.2 million and $6.9 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 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. In January 1998, the Company acquired an interest in approximately 25,000 acres. The Company's share of the purchase price was $6.4 million and is subject to certain adjustments. 33 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Southwest Wyoming 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 year ended December 31, 1997, the Company has expended approximately $6.2 million on this project. In February 1998, the Company sold a 50% undivided interest in a portion of the Granger gathering system for approximately $4.0 million. This amount approximated the Company's cost in such facilities. Bethel Treating Facility (Cotton Valley Pinnacle Reef) The Company is completing the construction of the Bethel Treating facility in East Texas that gathers gas from the Cotton Valley Pinnacle Reef trend. The Bethel Treating facility has been designed to accommodate incremental expansions, depending upon the success of continued development in the trend. Construction of the Bethel Treating facility began in September 1996. The Bethel Treating facility, including the sulfur recovery plant, is expected to cost approximately $97.0 million, of which approximately $90.5 million has been expended since inception through December 31, 1997. As of December 31, 1997 a portion of the Bethel Treating facility has been completed and placed in service. Midkiff/Benedum During 1997, the Company expanded the capacity at its Midkiff/Benedum processing plant to approximately 165 MMcf per day. The expansion was to accommodate increased drilling activity by Pioneer Natural Resources Company and other producers which supply natural gas to this facility. The Company's share of the expansion cost was approximately $4.3 million. Perkins In November 1997, the Company entered into an agreement to sell its Perkins facility. The sales price is $22.0 million, subject to certain adjustments, and is expected to result in a pre-tax gain of approximately $11.0 million. The sale is pending Federal Trade Commission approval. The Company expects to obtain such approval and for the sale to close during the first quarter of 1998. Northern Acquisition In July 1995, the Company entered into an agreement to purchase eight West Texas gathering systems, consisting of approximately 230 miles of gathering lines in the Permian Basin, from Transwestern Gathering Company and Enron Permian Gathering, Inc. The adjusted purchase price was $18.7 million. Redman Smackover Joint Venture Effective January 1, 1995, the Company entered into the Redman Smackover Joint Venture ("Redman Smackover") agreement with various third parties. Redman Smackover acquired working interests in three producing gas fields in East Texas in the Smackover formation for an adjusted purchase price of $11.0 million. 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. 34 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Principles of Consolidation The consolidated financial statements include the accounts of the Company and the Company's wholly owned subsidiaries. All material intercompany transactions have been eliminated in consolidation. The Company's interest in certain investments is accounted for by the equity method. Inventories For the year ended December 31, 1997, the cost of gas and NGL inventories is determined by the weighted average cost on a location-by-location basis. Prior to 1997, the cost of NGL inventories was determined by the last-in, first-out (LIFO) method, on a location-by-location basis. The change in accounting method from LIFO to weighted average cost was not material to any of the periods in the three years ended December 31, 1997. As a result, prior year financial statements were not restated. Residue and NGL inventory covered by hedging contracts is accounted for on a specific identification basis. Product inventory includes $11.9 million and $19.3 million of gas and $5.4 million and $6.7 million of NGLs at December 31, 1997 and 1996, respectively. During the year ended December 31, 1997, the Company recorded lower of cost or market write-downs of NGL and gas inventories of $1.1 million and $129,000, respectively. Property and Equipment Property and equipment is recorded at the lower of cost, including interest on funds borrowed to finance the construction of new projects, 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. Revenues associated with such activities are reflected in sales of gas and NGLs in the statement of operations. 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 Statement of Financial Accounting Standards ("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. Due to the limited operations of this subsidiary, translation adjustments were immaterial for the year ended December 31, 1997 and as a result, separate disclosure of such adjustments is not made in the Company's financial statements. 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. 35 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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 which are required to be reported as a separate component of stockholders' equity be reported in a separate financial statement. The Company's cumulative translation adjustments would be required to be reported separately in accordance with SFAS No. 130. However, as such adjustments were immaterial for the year ended December 31, 1997, separate reporting of such adjustments is not made in the Company's financial statements. Gas, NGL and Electric Power 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 are recognized in gas, NGL and electric power sales 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. Impairment of Long-Lived Assets The Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121"), which requires that an impairment loss be recognized when the carrying amount of an asset exceeds the fair market value or the expected future undiscounted net cash flows. This test is to be performed at the lowest level at which cash flows can be identified. Prior to October 1, 1995, the Company had performed this test for its oil and gas producing properties on a Company-wide basis. Upon adoption of SFAS No. 121, the Company reviewed its assets at the plant facility and oil and gas producing property levels. SFAS No. 121 also requires long-lived assets be reviewed whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. 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 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 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 $34.6 million and $17.6 million in accordance with SFAS No. 121 during the years ended December 31, 1997 and 1995, respectively. Earnings (Loss) Per Share of Common Stock In December 1997, the Company adopted 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, $10.4 million and $11.6 million for the years ended December 31, 1997, 1996 and 1995, respectively. For the year ended December 31, 1995, loss attributable to common stock was also reduced by a $2.0 million redemption premium and certain up-front costs of $1.8 million paid on the 7.25% Preferred Stock. 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, 21,930 and 35,217 shares for the years ended December 31, 1997, 1996 and 1995, respectively. 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 numerators and the denominators for the three years ended December 31, 1997 are not adjusted to reflect 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 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 36 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) comprising the Company's customer base and their dispersion across industries and geographic locations. At December 31, 1997, the Company believes it had no significant concentrations of credit risk. 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 Interest paid was $33.1 million, $36.7 million and $38.8 million, respectively, for the years ended December 31, 1997, 1996 and 1995. Capitalized interest associated with construction of new projects was $5.1 million, $1.7 million and $1.5 million, respectively, for the years ended December 31, 1997, 1996 and 1995. Income taxes paid were $2.6 million, $4.2 million and $1.6 million, respectively, for the years ended December 31, 1997, 1996 and 1995. Stock Compensation The Financial Accounting Standards Board issued SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123"), effective for fiscal years beginning after December 15, 1995. As permitted under 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 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 energy policy of the federal government and the availability of foreign oil and gas, none of which are within the Company's control. Segment Reporting In June 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosure about Segments of an Enterprise and Related Information" ("SFAS No. 131"), effective for fiscal years beginning after December 15, 1997. Under SFAS No. 131, the Company will be required to present certain information about operating segments, including profit or loss and segment assets. The Company will comply with the disclosure requirements of SFAS No. 131 as required under the pronouncement. 37 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Reclassifications Certain prior years' amounts in the consolidated financial statements and related notes have been reclassified to conform to the presentation used in 1997. NOTE 3 - RELATED PARTIES - ------------------------ 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. For the years ended December 31, 1997, 1996 and 1995, the Company had a 50% ownership interest in the Williston Gas Company ("Williston"), Westana Gathering Company ("Westana") and Redman Smackover. The Company acts as operator for Williston and Westana. The Company also has a 49% interest in the Sandia Energy Resources Joint Venture ("Sandia"), which was formed in March 1996. 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 are 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. In August 1996, substantially all of the assets associated with Williston were sold to a third party. The Company expects that Williston will be dissolved during 1998. At December 31, 1997, the Company's investment in Williston was $348,000. The Company performs various operational and administrative functions for Westana and charges a monthly overhead fee to cover such services. The Company records receivable and payable balances at the end of each accounting period related to transactions with Westana and Redman Smackover. At December 31, 1997, the Company's investments in Westana and Redman Smackover were $26.2 million and $4.3 million, respectively. The Company provides substantially all of the natural gas that Sandia markets and also provides various administrative services to Sandia. In addition, the Company purchases gas from Sandia. The Company records receivable and payable balances at the end of each accounting period related to the above referenced transactions. At December 31, 1997, the Company's investment in Sandia was $347,000. The following table summarizes account balances reflected in the financial statements (000s):
As of or for the Year Ended December 31, ---------------------------------------- 1997 1996 1995 ------------ ------------ ------------ Trade accounts receivable.. $ 4,295 $ 5,552 $ 1,549 ======= ======= ======= Accounts payable........... 7,246 11,041 4,979 ======= ======= ======= Sales of gas and NGLs...... 19,504 10,592 - ======= ======= ======= Processing revenue......... 336 256 273 ======= ======= ======= Product purchases.......... 59,082 57,675 28,196 ======= ======= ======= Administrative expense..... $ 421 $ 419 $ 665 ======= ======= =======
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 Plan and the $5.40 Stock Option Plan (See Note 10). The Company will forgive the loan and accrued interest if the employee has been continuously employed by the Company for periods specified under the agreements and Board of Directors' resolutions. As 38 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) of December 31, 1997 and 1996, loans totaling $1.3 million and $1.8 million, respectively, were outstanding to certain 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 1997 and 1996, the Board of Directors approved the forgiveness of loans to certain employees totaling approximately $552,000 and $92,000, respectively, in connection with these plans. NOTE 4 - RISK MANAGEMENT - ------------------------ Gas, NGL and Electric Power Hedges 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, NGL and power 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 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 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 creditworthy 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. As of December 31, 1997, the Company held a notional quantity of approximately 480 Bcf of natural gas futures, swaps and options, extending from January 1998 to December 1999 with a weighted average duration of approximately four months. This was comprised of approximately 230 Bcf of long positions and 250 Bcf of short positions in such instruments. As of December 31, 1997, the Company held a notional quantity of approximately 148,000 MGal of NGL futures, swaps and options, extending from January 1998 to December 1998 with a weighted average duration of approximately five months. This was comprised of approximately 93,000 MGal of long positions and 55,000 MGal of short positions in such instruments. As of December 31, 39 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 1996, the Company held a notional quantity of approximately 250 Bcf of natural gas futures, swaps and options, extending from January 1997 to October 1998 with a weighted average duration of approximately four months. This was comprised of approximately 120 Bcf of long positions and 130 Bcf of short positions in such instruments. As of December 31, 1996, the Company held a notional quantity of approximately 185,000 MGal of NGL futures, swaps and options, extending from January 1997 to December 1997 with a weighted average duration of approximately five months. This was comprised of approximately 55,000 MGal of long positions and 130,000 MGal of short positions in such instruments. As of December 31, 1997 and 1996, the Company did not have any material hedging contracts in place associated with electric power. The Company has hedged a portion of its equity volumes of gas and NGLs in 1998, particularly in the first quarter, at pricing levels in excess of its 1998 operating budget. The Company's hedging strategy establishes a minimum and maximum price to the Company while allowing market participation between these levels. As of March 4, 1998, the Company had hedged approximately 75% of its anticipated equity gas for 1998 at a weighted average NYMEX-equivalent minimum price of $2.19 per Mcf, including approximately 85% of first quarter anticipated equity volumes at a weighted average NYMEX-equivalent minimum price of $2.42 per Mcf. Additionally, the Company has hedged approximately 25% of its anticipated equity NGLs for 1998 at a weighted average composite Mont Belvieu and West Texas Intermediate Crude-equivalent minimum price of $.40 per gallon ($16.75 per barrel), including approximately 50% of first quarter anticipated equity volumes at a weighted average composite Mont Belvieu and West Texas Intermediate Crude- equivalent minimum price of $.36 per gallon ($15.20 per barrel). At December 31, 1997, the Company had $512,000 of losses deferred in inventory that will be recognized primarily during the first quarter of 1998 and are expected to be offset by margins from the Company's related forward fixed price hedges and physical sales. At December 31, 1997, the Company had unrecognized net losses of $2.0 million 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. During 1996, the Company began to enter into physical gas transactions payable in Canadian dollars. The Company enters into forward purchases of Canadian dollars from time to time to fix the cost of its future Canadian dollar denominated natural gas purchase, 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 future payment obligation is made and the actual payment date of such obligation. As of December 31, 1997 the notional value of such contracts was approximately $5.5 million in Canadian dollars. As of December 31, 1996, the notional value of such contracts was immaterial. 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 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 from such speculative activities for the years ended December 31, 1997 and 1996 were not material. 40 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 5 - DEBT - ------------- The following summarizes the Company's consolidated debt at the dates indicated (000s):
December 31, ------------------ 1997 1996 -------- -------- Master shelf and senior notes............ $284,857 $292,000 Variable rate revolving credit facility.. 156,500 - Receivables facility..................... - 75,000 Bank term loan facility.................. - 12,500 -------- -------- Total long-term debt....... $441,357 $379,500 ======== ========
Revolving Credit Facility. The Company's unsecured variable rate Revolving Credit Facility, was restated and amended on May 30, 1997. The Revolving Credit Facility is with a syndicate of nine banks and provides for a maximum borrowing commitment of $300 million, $156.5 million of which was outstanding at December 31, 1997. The Revolving Credit Facility's commitment period will terminate on March 31, 2002. At that time, any amounts outstanding on the Revolving Credit Facility will become due and payable. The Revolving Credit Facility bears interest at certain spreads over the Eurodollar rate, at the Federal Funds rate plus .50%, or at 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 the Company's debt to capitalization ratio. At December 31, 1997, the spread was .35% over the Eurodollar rate and the facility fee was .175%. The rate payable, including the facility fee, on the Revolving Credit Facility at December 31, 1997 was 6.497%. The Company incurred approximately $425,000 during 1997 of fees in association with the restatement and amendment; such amounts were capitalized and will be amortized over the term of the agreement. Pursuant to the Revolving Credit Facility, the Company is required to maintain a debt to capitalization ratio (as defined therein) of not more than 60% as of the end of any fiscal quarter and a ratio of EBITDA (as defined therein) to interest and dividends on preferred stock as of the end of any fiscal quarter of not less than 2.75 to 1.0 through December 31, 1998, 3.0 to 1.0 from January 1, 1999 through December 31, 1999 and 3.25 to 1.0 thereafter. The Company generally utilizes excess daily funds to reduce any outstanding balances on the Revolving Credit Facility and associated interest expense and it intends to continue such practice. Master Shelf Agreement. In December 1991, the Company entered into a Master Shelf Agreement (as amended and restated, the "Master Shelf") with The Prudential Insurance Company of America ("Prudential"). The Master Shelf Agreement, as further restated and amended, is fully utilized, as indicated in the following table (000s):
Interest Final Issue Date Amount Rate Maturity Principal Payments Due - -------------------- -------- ----- ------------------ ----------------------------------------------- October 27, 1992 $25,000 7.51% October 27, 2000 $8,333 on each of October 27, 1998 through 2000 October 27, 1992 25,000 7.99% October 27, 2003 $8,333 on each of October 27, 2001 through 2003 September 22, 1993 25,000 6.77% September 22, 2003 single payment at maturity 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 ------- $200,000 =======
Pursuant to the Master Shelf Agreement, the Company is required to maintain a current ratio (as defined therein) of at least 1.0 to 1.0, a minimum tangible net worth equal to the sum of $345 million plus 50% of consolidated net earnings earned from June 30, 1995 plus 75% of the net proceeds of any equity offerings after June 30, 1995, a debt to capitalization ratio (as defined therein) of no more than 55%, and an EBITDA (as defined therein) to interest ratio of not less than 3.25 to 1.0 through October 31, 1997 and 3.75 to 1.0 thereafter. The Company is prohibited from declaring or paying dividends on any capital stock on 41 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) or after June 30, 1995, that in the aggregate exceed the sum of $50 million plus 50% of consolidated net earnings earned after June 30, 1995, plus the cumulative net proceeds received by the Company after June 30, 1995 from the sale of any equity securities. At December 31, 1997, $118.5 million was available under this limitation. The Company presently intends to finance the $8.3 million payment due on October 27, 1998 with amounts available under the Revolving Credit Facility. Term Loan Facility. The Company also had a Term Loan Facility with four banks which bore interest at 9.87% in 1997. In September 1997, the Company made the final payment on the Term Loan Facility with amounts available under the Revolving Credit Facility. 1993 Senior Notes. On April 28, 1993, the Company sold $50 million of 7.65% Senior Notes ("1993 Senior Notes") due 2003 to a group of insurance companies. Annual principal payments of $7.1 million on the 1993 Senior Notes were and are due on April 30 of each year from 1997 through 2002, with any remaining principal and interest outstanding due on April 30, 2003. The Company financed the $7.1 million payment paid on April 30, 1997 with amounts available under the Revolving Credit Facility. The Company presently intends to finance the $7.1 million payment due on April 30, 1998 with amounts available under the Revolving Credit Facility. The 1993 Senior Notes are unsecured and contain certain financial covenants that substantially conform with those contained in the Master Shelf Agreement. 1995 Senior Notes. The Company sold $42 million of 1995 Senior Notes to a group of insurance companies in the fourth quarter of 1995, with an interest rate of 8.16% per annum and principal due in a single payment in December 2005. The 1995 Senior Notes are unsecured and contain certain financial covenants that conform with those contained in the Master Shelf Agreement. Receivables Facility. In April 1995, the Company entered into an agreement with Receivables Capital Corporation ("RCC"), as purchaser, and Bank of America National Trust and Savings Association, as agent, pursuant to which the Company could sell to RCC at face value on a revolving basis an undivided interest in certain of the Company's trade receivables. Under the Receivables Facility, the Company sold $75 million of trade receivables at a rate equal to RCC's commercial paper rate plus .375%. Effective June 12, 1997, the Company elected to terminate the facility. All amounts then outstanding were repaid with amounts available under the Revolving Credit Facility. Covenant Compliance. At December 31, 1997, the Company was in compliance with all covenants in its loan agreements. Taking into account all the covenants contained in the Company's financing facilities and maturities of long-term debt during 1997, the Company had approximately $85 million of available borrowing capacity at December 31, 1997. Historically, oil prices have been volatile and subject to rapid price fluctuations. The oil and gas industry is currently experiencing significantly declining oil prices. Such prices have declined approximately 25% during the first quarter of 1998 to approximately $13.26 per barrel as of March 16, 1998. In addition, the start-up volumes associated with the Bethel Treating facility have been lower than anticipated. If the current pricing of oil and associated NGLs continues or declines and volumes associated with the Bethel Treating facility do not increase, the Company is uncertain as to its ability to satisfy its interest coverage covenants under certain of its debt agreements during the last half of 1998. However, the Company believes it can obtain amendments or waivers from the necessary lenders. Approximate future maturities of long-term debt at the date indicated are as follows at December 31, 1997 (000s):
1998......................... $ 15,476 1999......................... 15,476 2000......................... 15,477 2001......................... 40,476 2002......................... 171,976 Thereafter................... 182,476 -------- Total........................ $441,357 ========
42 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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, 1997 December 31, 1996 ------------------- ------------------- Carrying Fair Carrying Fair Value Value Value Value -------- --------- -------- --------- (000s) (000s) Cash and cash equivalents.. $ 19,777 $ 19,777 $ 39,504 $ 39,504 Trade accounts receivable.. 258,791 258,170 338,708 338,708 Accounts payable........... 326,696 326,696 386,268 386,268 Long-term debt............. 441,357 442,232 379,500 376,076 Risk management contracts.. $ - $ (2,189) $ - $(11,460)
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 - --------------------- The provision (benefit) for income taxes for the years ended December 31, 1997, 1996 and 1995 is comprised of (000s):
1997 1996 1995 ----- ------- -------- Current: Federal..................................... $ 268 $ 1,152 $(3,404) State....................................... - - - ----- ------- ------- Total Current....................... 268 1,152 (3,404) ----- ------- ------- Deferred: Federal..................................... 448 12,071 1,192 State....................................... 17 467 54 ----- ------- ------- Total Deferred...................... 465 12,538 1,246 ----- ------- ------- Total tax provision (benefit).. $ 733 $13,690 $(2,158) ===== ======= =======
43 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Temporary differences and carryforwards which give rise to the deferred tax liabilities (assets) at December 31, 1997 and 1996 are as follows (000s):
1997 1996 --------- --------- Property and equipment......................................... $158,258 $145,802 Differences between the book and tax basis of acquired assets.. 15,334 16,286 -------- -------- Total deferred income tax liabilities................... 173,592 162,088 -------- -------- Alternative Minimum Tax ("AMT") credit carryforwards........... (26,849) (26,581) Net Operating Loss ("NOL") carryforwards....................... (66,000) (52,996) -------- -------- Total deferred income tax assets........................ (92,849) (79,577) -------- -------- Net deferred income taxes............................... $ 80,743 $ 82,511 ======== ========
The change in the net deferred income taxes in 1997 includes a $2.2 million tax benefit associated with the exercise of non-qualified stock options. The Company expects to realize such tax benefit. The differences between the provision (benefit) for income taxes at the statutory rate and the actual provision (benefit) for income taxes for the years ended December 31, 1997, 1996 and 1995 are summarized as follows (000s):
1997 % 1996 % 1995 % ------ ----- -------- ----- -------- ------ Income tax (benefit) at statutory rate...... $ 777 35.0 $14,570 35.0 $(2,893) (35.0) State income taxes, net of federal benefit.................................... 31 1.4 562 1.4 (99) (1.2) Permanent differences on asset write-downs.. - - - - 1,173 14.2 Reduction of deferred income taxes to reflect adjustment in acquired NOL carryforward............................... - - (900) (2.2) - - Adjustment to prior year income taxes....... - - (383) (.9) (300) (3.6) Other....................................... (75) (3.4) (159) (.4) (39) (.5) ----- ---- ------- ---- ------- ----- Total...................................... $ 733 33.0 $13,690 32.9 $(2,158) (26.1) ===== ==== ======= ==== ======= =====
44 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) At December 31, 1997 the Company had NOL carryforwards for Federal and state income tax purposes and AMT credit carryforwards for Federal income tax purposes of approximately $181.6 million and $26.8 million, respectively. These carryforwards expire as follows (000s): Expiration Dates NOL AMT ----------------------------------- -------- ------- 2003............................... $ 170 $ - 2004............................... 847 - 2005............................... 943 - 2006............................... 478 - 2007............................... 919 - 2008............................... 15,877 - 2009............................... 56,308 - 2010............................... 59,857 - 2011............................... 16,221 - 2012............................... 29,972 - No expiration...................... - 26,849 -------- ------- Total........................... $181,592 $26,849 ======== ======= The Company believes that the NOL carryforwards and AMT credit carryforwards will be utilized prior to their expiration because they are substantially offset by existing taxable temporary differences reversing within the carryforward 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. 45 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 8 - COMMITMENTS AND CONTINGENT LIABILITIES - ------------------------------------------------ JN Exploration and Production Litigation JN Exploration and Production ("JN") is a producer of oil and natural gas that sold unprocessed natural gas to the Company on a percentage-of-proceeds basis. The Company processed the natural gas at its Teddy Roosevelt Plant, which is no longer in operation. In JN Exploration and Production v. Western Gas Resources, ------------------------------------------------------- Inc. United States District Court for the District of North Dakota, - ---- Southwestern Division, Civil Action Nos. A1-93-53 and 903-CV-60, JN sued the Company, alleging that JN was entitled to a portion of a $15 million amendment fee the Company received in the years 1987 through 1989 from Williston Basin Interstate Pipeline Company ("WBI"), which had an agreement with the Company to purchase natural gas. On April 15, 1996, the Court issued a Memorandum and Order granting JN's summary judgment motion on the issue of liability. On July 11, 1996, the Court issued a Memorandum and Order setting forth the manner in which damages are to be calculated. On September 17, 1996, the Court entered a final judgment against the Company in the amount of $421,000 (including pre- judgment interest). The Company has filed a Notice of Appeal with the United States Court of Appeals for the Eighth Circuit and an order granting a stay of execution of the judgment until the appeal is resolved was granted by the Court on November 29, 1996. The case has been briefed and argued to the Court and the company is presently awaiting the Court's decision. The Company believes that there are meritorious grounds to reverse the trial court's decision. One other producer has filed a similar claim. If JN were to prevail on appeal, other producers who sold natural gas which was processed at the Teddy Roosevelt Plant during the time period in question may be able to assert similar claims. The Company believes that it has meritorious defenses to such claims and, if sued, the Company would defend vigorously against any such claims. At the present time, it is not possible to predict the outcome of this litigation or any other producer litigation that might raise similar issues or to estimate the amount of potential damages. Internal Revenue Service The Internal Revenue Service ("IRS") has completed its examination of the Company's returns for the years 1990 and 1991 and has proposed adjustments to taxable income reflected in such returns that would shift the recognition of certain items of income and expense from one year to another ("Timing Adjustments"). To the extent taxable income in a prior year is increased by proposed Timing Adjustments, taxable income may be reduced by a corresponding amount in other years. However, the Company would incur an interest charge as a result of such adjustment. The Company currently is protesting certain of these proposed adjustments. In the opinion of management, any proposed adjustments for the additional income taxes and interest that may result would not be material. However, it is reasonably possible that the ultimate resolution could result in an amount which differs materially from management's estimates. 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 the Company's financial position or results of operations. NOTE 9 - 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 46 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) and provides for a match of 25% 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 by the Company were $1.9 million, $1.7 million and $1.3 million, for the years ended December 31, 1997 1996 and 1995, respectively. The matching contributions were $310,000, $256,000 and $183,000 for the years ended December 31, 1997, 1996 and 1995, 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 will terminate 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 1997, the Board of Directors voted to extend the maturity for each of the loan increments by three years for the first series of maturities and by two years for all other maturities. 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, 1997 and 1996, loans related to 112,500 and 118,750 shares of Common Stock, respectively, totaling $1.2 million and $1.3 million, respectively, were outstanding under these terms. 1993 and 1997 Stock Option Plans The 1993 Stock Option Plan ("1993 Plan") became effective on May 24, 1993 and the 1997 Stock Option Plan ("1997 Plan") became effective on May 21, 1997 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. The 1993 Plan and the 1997 Plan will terminate on the earlier of March 28, 2003 and May 20, 2007, respectively, or the date on which all options granted under each of the plans have been exercised in full. Under both 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 reissuance 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 fair market value of the stock at the time such option is granted. 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 Plan, the Board of Directors has the authority to set the vesting schedule from 20% per year to 33 1/3%. Under both plans, the employee must exercise the option within five years of the date each portion vests. $5.40 Stock Option Plan In April 1987 and amended in February 1994, the Partnership 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 47 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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, 1997 and 1996, loans related to 15,000 and 102,123 shares of Common Stock, respectively, totaling $81,000 and $551,000, respectively, 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:
Key Employee Directors' $5.40 Plan Plan Plan 1993 Plan 1997 Plan ---------- ------ ------ --------- ---------- EXERCISABLE: December 31, 1995.. 47,571 37,500 9,750 170,344 - December 31, 1996.. 33,148 56,250 11,000 288,438 - December 31, 1997.. - 75,000 12,250 448,171 - AVAILABLE FOR GRANT: December 31, 1995.. - 31,250 1,250 309,872 - December 31, 1996.. - 31,250 1,250 4,734 - December 31, 1997.. - 31,250 1,250 9,382 828,900
The following table summarizes the stock option activity under the Company's benefit plans:
Number of Shares Per Share ------------------------------------------------------------------- Price Key Employee Directors' Range $5.40 Plan Plan Plan 1993 Plan 1997 Plan --------------- ----------------- ------------- ---------- ---------- --------- Balance 12/31/94 75,348 106,250 13,500 637,586 - Granted................ $16.13 - $23.50 - - - 137,567 - Exercised.............. 5.40 - 15.00 (26,161) (31,250) - - - Forfeited or canceled.. 5.40 - 35.00 (1,616) - - (87,092) - -------- ------- ---------- ------- --------- Balance 12/31/95 47,571 75,000 13,500 688,061 - Granted................ 13.88 - 18.63 - - - 351,733 - Exercised.............. 5.40 (14,423) - - - - Forfeited or canceled.. 13.25 - 35.00 - - - (46,595) - -------- ------- ---------- ------- --------- Balance 12/31/96 33,148 75,000 13,500 993,199 - Granted................ 17.75 - 24.00 - - - 64,654 171,100 Exercised.............. 5.40 - 23.50 (32,077) - - (5,225) - Forfeited or canceled.. $ 5.40 - $34.13 (1,071) - - (69,302) - -------- ------- ---------- ------- --------- Balance 12/31/97 - 75,000 13,500 983,326 171,100 ======== ======= ========== ======= =========
48 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table summarizes the weighted average option exercise price information under the Company's benefit plans:
Key Employee Directors' $5.40 Plan Plan Plan 1993 Plan 1997 Plan ---------- ------ ------ --------- ---------- Balance 12/31/94................. $5.40 $24.49 $14.13 $26.40 - Granted................ - - - 20.68 - Exercised.............. 5.40 10.71 - - - Forfeited or canceled.. 5.40 - - 27.53 - Balance 12/31/95................. 5.40 30.23 14.13 25.11 - Granted................ - - - 14.63 - Exercised.............. 5.40 - - - - Forfeited or canceled.. - - - 27.05 - Balance 12/31/96................. 5.40 30.23 14.13 21.31 - Granted................ - - - 19.71 19.63 Exercised.............. 5.40 - - 16.91 - Forfeited or canceled.. 5.40 - - 25.54 - Balance 12/31/97................. $ - $30.23 $14.13 $20.93 $19.63
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 presented. Such information was only calculated for the options granted under the 1993 Plan and the 1997 Plan as there were no grants under any other plans. The weighted average fair value of options granted under the 1993 Plan of $10.54, $10.18 and $6.03 for the years ended December 31, 1997, 1996 and 1995, respectively, and the weighted average fair value of options granted under the 1997 Plan of $12.66 was estimated using the Black-Scholes option-pricing model with the following assumptions:
1993 Plan 1997 Plan ------------------------------ ---------- 1997 1996 1995 1997 ---------- ------ ---------- ------ Risk-free interest rate......... 6.1% 6.35% 5.65% 6.1% Expected life (in years)........ 6 7 8 10 Expected volatility............. 42% 37% 32% 42% Expected dividends (quarterly).. $ .05 $ .05 $ .05 $ .05
Had compensation expense for the Company's 1997, 1996 and 1995 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):
1997 1996 1995 ------------ ----------- --------- As Reported Pro forma As Reported Pro forma As Reported Pro forma ------------ ---------- ----------- --------- ------------ ---------- Net income (loss).................... $ 1,487 $ 941 $27,941 $27,891 $ (6,108) $ (6,108) Net income (loss) attributable to common stock................ (8,952) (9,498) 17,502 17,452 (21,539) (21,539) Earnings (loss) per share of common stock....................... $ (.28) $ (.30) $ .66 $ .66 $ (.84) $ (.84) Earnings (loss) per share of common stock - assuming dilution.. $ (.28) $ (.30) $ .66 $ .66 $ (.84) $ (.84)
49 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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% for the 1997 Plan. All options granted in 1997 will vest at the rate of 20% per year. 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 this vesting period for purposes of calculating compensation expense. In the initial years of implementation of SFAS No. 123, the pro forma compensation expense will not be representative of future pro forma expense. NOTE 10 - SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - ---------------------------------------------------------------------- (UNAUDITED): - ------------ Costs The following tables set forth capitalized costs at December 31, 1997, 1996 and 1995 and costs incurred for oil and gas producing activities for the years ended December 31, 1997, 1996 and 1995 (000s):
1997 1996 1995 --------- --------- --------- Capitalized costs: Proved properties......................................... $134,102 $140,871 $136,499 Unproved properties....................................... 18,464 8,064 6,279 -------- -------- -------- Total............................................................ 152,566 148,935 142,778 Less accumulated depletion................................ (61,766) (58,548) (46,792) -------- -------- -------- Net capitalized costs............................................ $ 90,800 $ 90,387 $ 95,986 ======== ======== ======== The Company's share of Redman Smackover's net capitalized costs.. $ 3,845 $ 4,385 $ 5,216 ======== ======== ======== Costs incurred: Acquisition of properties Proved.................................................... $ 7,499 $ 242 $ 1,591 Unproved.................................................. 10,457 909 128 Development costs................................................ 13,134 3,893 3,035 Exploration costs................................................ 1,322 2,581 1,102 -------- -------- -------- Total costs incurred............................................. $ 32,412 $ 7,625 $ 5,856 ======== ======== ======== The Company's share of Redman Smackover's costs incurred......... $ 236 $ 8 $ 5,540 ======== ======== ========
50 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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, 1997, 1996 and 1995 are as follows (000s):
1997 1996 1995 --------- --------- --------- Revenues from sale of oil and gas: Sales.......................................... $ 5,970 $ 1,821 $ 2,490 Transfers...................................... 25,571 31,733 29,739 -------- -------- -------- Total........................................ 31,541 33,554 32,229 Production costs...................................... (6,900) (4,256) (4,160) Exploration costs..................................... (1,439) (898) (956) Depreciation, depletion and amortization.............. (11,549) (11,756) (15,081) Impairment of oil and gas properties.................. (19,615) - - Income tax benefit (expense).......................... 2,986 (6,261) (4,429) -------- -------- -------- Results of operations................................. $ (4,976) $ 10,383 $ 7,603 ======== ======== ======== The Company's share of Redman Smackover's operations.. $ 1,265 $ 1,745 $ 324 ======== ======== ========
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 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. 51 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table sets forth information for the years ended December 31, 1997, 1996 and 1995 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, 1994.................................... 134,541 478 Revisions of previous estimates...................... (8,846) 437 Production........................................... (16,875) (200) ------- ---- December 31, 1995.................................... 108,820 715 Revisions of previous estimates...................... (2,147) 286 Purchases of reserves in place....................... 2,372 - Production........................................... (13,014) (158) ------- ---- 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 ======= ==== The Company's share of Redman Smackover's proved reserves: December 31, 1995.................................... 12,647 - ======= ==== December 31, 1996.................................... 10,811 - ======= ==== December 31, 1997.................................... 10,218 - ======= ====
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. Future price changes are considered only to the extent provided by contractual arrangements, including futures contracts, in existence at year end. 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. 52 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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 pretax 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, 1997, 1996 and 1995 is as follows (000s):
1997 1996 1995 ---------- ---------- --------- Future cash inflows................................................................. $ 352,491 $ 305,095 $230,986 Future production costs............................................................. (118,056) (54,306) (52,442) Future development costs............................................................ (28,803) (1,728) (3,564) Future income tax expense........................................................... (32,614) (37,870) (18,386) --------- --------- -------- Future net cash flows............................................................... 173,018 211,191 156,594 10% annual discount for estimated timing of cash flows.............................. (73,445) (100,474) (74,832) --------- --------- -------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves............................................... $ 99,573 $ 110,717 $ 81,762 ========= ========= ======== 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 $ 5,684 $ 4,665 ========= ========= ========
Principal changes in the Company's estimated discounted future net cash flows for the years ended December 31, 1997, 1996 and 1995 are as follows (000s):
1997 1996 1995 -------------- ---------------- ------------- January 1.............................................. $ 110,717 $ 81,762 $ 95,731 Sales and transfers of oil and gas produced, net of production costs.................................... (24,650) (29,298) (28,069) Net changes in prices and production costs related to future production................................ (168,927) 61,888 10,788 Development costs incurred during the period......... 13,134 3,893 3,035 Changes in estimated future development costs........ (27,075) (2,057) 2,631 Changes in extensions and discoveries................ 171,109 - - Revisions of previous quantity estimates............. (31,597) 2,554 (12,147) Purchases of reserves in place....................... 50,148 5,266 - Accretion of discount................................ 11,072 8,176 9,573 Net change in income taxes........................... (5,255) (19,484) (1,603) Other, net........................................... 897 (1,983) 1,823 ---------- -------- -------- December 31............................................ $ 99,573 $110,717 $ 81,762 ========== ======== ========
53 WESTERN GAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 11 - 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 ---------- ---------- --------- --------------- ---------------- 1997 quarter ended: March 31.............................................. $ 635,538 $ 30,847 $10,608 $ .25 $ .25 June 30............................................... 463,575 15,508 878 (.05) (.05) September 30.......................................... 555,888 20,757 4,997 .07 .07 December 31........................................... 730,259 26,643 (14,996)(b) (.55) (.55) ---------- -------- -------- ----- ----- $2,358,260 $ 93,755 $ 1,487 $(.28) $(.28) ========== ======== ======= ===== ===== 1996 quarter ended: March 31.............................................. $ 480,714 $ 33,223 $10,233 $ .30 $ .30 June 30............................................... 446,223 24,029 5,432 .11 .11 September 30.......................................... 467,721 19,275 2,881 .01 .01 December 31........................................... 696,351 28,952 9,395 .24 .24 ---------- -------- ------- ----- ----- $2,091,009 $105,479 $27,941 $ .66 $ .66 ========== ======== ======= ===== =====
(a) Excludes selling and administrative, interest and income tax expenses and loss on the impairment of property and equipment. (b) Includes an after-tax, non-cash expense resulting from the evaluation of property and equipment in accordance with SFAS No. 121 of $34.6 million. 54 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 22, 1998 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 23 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). 55 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). 3.6 Amended and restated of the By-laws of Western Gas Resources, Inc. as adopted by the Board of Directors on September 6, 1996. (Filed as exhibit 3.9 to Western Gas Resources, Inc.'s Form 10-Q for the nine months ended September 30, 1996 and incorporated herein by reference). 3.7 Amendment of the Bylaws of Western Gas Resources, Inc. adopted by the Board of Directors on March 21, 1997. (Filed as exhibit 3.7 to Western Gas Resources, Inc.'s Form 10-Q for the three months ended March 31, 1997 and incorporated herein by reference). 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). 56 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). 10.15 Joint Venture Agreement of Redman Smackover Joint Venture. (Filed as exhibit 10.42 to Western Gas Resources, Inc.'s Form 10-Q for the six months ended June 30, 1995 and incorporated herein by reference). 57 10.16 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). 10.17 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). 10.18 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). 10.19 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). 58 10.20 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. 21.1 List of Subsidiaries of Western Gas Resources, Inc. 23.1 Consent of Price Waterhouse LLP, independent accountants. (b) Reports on Form 8-K: A report on Form 8-K was filed on November 18, 1997 to notify the Securities and Exchange Commission and the Company's stockholders of agreements between the Company and Ultra Resources, Inc. and RIS Resources (USA) Inc. (c) Exhibits required by Item 601 of Regulation S-K. See (a) (3) above. 59 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 16, 1998. WESTERN GAS RESOURCES, INC. --------------------------- (Registrant) By: /s/ Brion G. Wise --------------------------------- Brion G. Wise Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /s/ Brion G. Wise Chairman of the Board, Chief Executive March 16, 1998 - ----------------------------------- Officer and Director Brion G. Wise /s/ Walter L. Stonehocker Vice Chairman of the Board and Director March 16, 1998 - ----------------------------------- Walter L. Stonehocker /s/ Bill M. Sanderson Director March 16, 1998 - ----------------------------------- Bill M. Sanderson /s/ Richard B. Robinson Director March 16, 1998 - ----------------------------------- Richard B. Robinson /s/ Dean Phillips Director March 16, 1998 - ----------------------------------- Dean Phillips Director March 16, 1998 - ----------------------------------- Ward Sauvage /s/ James A. Senty Director March 16, 1998 - ----------------------------------- James A. Senty Director March 16, 1998 - ----------------------------------- Joseph E. Reid /s/ William J. Krysiak Vice President - Finance (Principal March 16, 1998 - ----------------------------------- Financial and Accounting Officer) William J. Krysiak
60 EX-11.1 2 COMPUTATION OF PER SHARE EARNINGS EXHIBIT 11.1 WESTERN GAS RESOURCES, INC. COMPUTATION OF PER SHARE EARNINGS DECEMBER 31, 1997
Weighted Average Shares Of Earnings Common Per Share Stock Net Of Common Outstanding Income Stock ------------- ----------- ---------- Net income................................................. $ 1,487,000 Weighted average shares of common stock outstanding........ $ 32,134,011 Less preferred stock dividends: $2.28 cumulative preferred stock........................ (3,194,000) $2.625 cumulative convertible preferred stock........... (7,245,000) ------------- ----------- 32,134,011 $(8,952,000) ============= =========== Basic earnings per share of common stock................... $ (.28) ========= (Assume no conversion of anti-dilutive convertible preferred stock) Assume exercise of common stock equivalents: Weighted average shares of common stock outstanding..... 32,134,011 (Anti-dilutive common stock equivalents are not used in this calculation) $5.40 employee stock options............................... 3,792 ------------- ----------- 32,137,803 $(8,952,000) ============= =========== Fully diluted earnings per share of common stock........... $ (.28) =========
EX-21.1 3 SUBSIDIARIES OF WESTERN GAS RESOURCES, INC. 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 Storage, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 5) Western Gas Resources - Oklahoma, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 6) Mountain Gas Resources, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 7) Western Power Services, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 8) Pinnacle Gas Treating, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 9) WGR Canada, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 10) Lance Oil & Gas Company, Inc. Wholly-owned subsidiary of Western Gas Resources, Inc. 11) Mountain Gas Transportation, Inc. Wholly-owned subsidiary of Mountain 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 14) Redman Smackover Joint Venture 50%-owned joint venture of Western Gas Resources, Inc.
Exhibit 21.1 EX-23.1 4 CONSENT OF PRICE WATERHOUSE LLP Consent of Independent Accountants We hereby consent to the incorporation by reference in the Prospectus constituting part of the Registration Statements on Form S-3 (No. 33-66516, No. 33-54741, No. 333-00903 and No. 333-13099) and in the Registration Statements on Form S-8 (No. 33-67834 and No. 333-29711) of Western Gas Resources, Inc. of our report dated March 16, 1998 appearing on page 28 of this Form 10-K. PRICE WATERHOUSE LLP Denver, Colorado March 16, 1998 Exhibit 23.1 EX-27 5 FINANCIAL DATA SCHEDULE
5 1,000 12-MOS DEC-31-1997 DEC-31-1997 19,777 0 258,791 0 26,666 307,598 1,251,073 (294,350) 1,348,276 358,064 441,357 0 416 3,217 464,479 1,348,276 2,369,831 2,385,260 2,146,430 2,146,430 209,136 0 27,474 2,220 733 1,487 0 0 0 1,487 (.28) (.28)
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