-----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, LkYB3d6a8QmV658GerDwFpOid6c6a8jZJ15BHOLR59ilhfcP047cR73wbw5zf7qa bk1cu+fxr7T6gTzZ3GgCMg== 0000883953-99-000002.txt : 19990325 0000883953-99-000002.hdr.sgml : 19990325 ACCESSION NUMBER: 0000883953-99-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990324 FILER: COMPANY DATA: COMPANY CONFORMED NAME: HALLWOOD CONSOLIDATED RESOURCES CORP CENTRAL INDEX KEY: 0000883953 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841176750 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-19931 FILM NUMBER: 99571897 BUSINESS ADDRESS: STREET 1: 4582 S ULSTER ST PKWY STREET 2: STE 1700 CITY: DENVER STATE: CO ZIP: 80237 BUSINESS PHONE: 3038507373 MAIL ADDRESS: STREET 1: 4582 SOUTH ULSTER STREET PKWY STE 1700 CITY: DENVER STATE: CO ZIP: 80237 10-K 1 HALLWOOD CONSOLIDATED RESOURCES 1998010-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, 1998 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-19931 HALLWOOD CONSOLIDATED RESOURCES CORPORATION (Exact name of registrant as specified in its charter) Delaware 84-1176750 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 4582 South Ulster Street Parkway Suite 1700 Denver, Colorado 80237 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (303) 850-7373 Securities Registered Pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered None None Securities Registered Pursuant to Section 12(g) of the Act: Common Stock, $.01 par value 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 [ ] Indicate by check mark if disclosure of delinquent filers pursuant 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. [ ] The aggregate market value of the voting stock held by nonaffiliates of the registrant as of March 24, 1999 was approximately $17,249,000. Shares of Common Stock outstanding at March 24, 1999: 3,007,852 shares. PART 1 ITEM 1 - BUSINESS Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a Delaware corporation engaged in the development, production and sale of oil and gas, and in the acquisition, exploration, development and operation of oil and gas properties. The principal objective of HCRC is to maximize shareholder value by increasing its reserves, production and cash flow through a balanced program of development and high potential exploration drilling, as well as selective acquisitions. The Company's properties are primarily located in West Texas, South Louisiana, New Mexico and Kansas. HCRC does not engage in any other line of business. HCRC does not have any employees. Hallwood Petroleum, Inc. ("HPI"), an affiliate of HCRC, operates the properties and administers the day to day activities of HCRC and its affiliates. On March 24, 1999, HPI had 108 employees. Marketing The oil and gas produced from the properties owned by HCRC has typically been marketed through normal channels for such products. Oil is generally sold to purchasers at field prices posted by the principal purchasers of crude oil in the areas where the producing properties are located. In response to the volatility in the oil markets, HCRC has entered into financial contracts for hedging the price of 4% of its estimated oil production for 1999. All of HCRC's gas production is sold on the spot market or in short-term contracts and is transported in intrastate and interstate pipelines. HCRC has entered into financial contracts for hedging the price of between 32% and 42% of its estimated gas production for 1999 through 2002. The purpose of the hedges is to provide protection against price decreases and to provide a measure of stability in the volatile environment of oil and natural gas spot pricing. The amounts received or paid upon settlement of these contracts are recognized as increases or decreases in revenue at the time the hedged volumes are sold. Both oil and natural gas are purchased by refineries, major oil companies, public utilities, industrial customers and other users and processors of petroleum products. HCRC is not confined to, nor dependent upon, any one purchaser or small group of purchasers. Accordingly, the loss of a single purchaser, or a few purchasers, would not materially affect HCRC's business because there are numerous other purchasers in the areas in which HCRC sells it production. However, for the years ended December 31, 1998, 1997 and 1996, purchases by the following companies exceeded 10% of the total oil and gas revenues of HCRC. 1998 1997 1996 ------ ------ ----- El Paso Field Services 17% 17% 11% Williams Gas Marketing 13% 13% Koch Oil Company 12% 23% Conoco Inc. 12% 13% Scurlock Permian Corporation 14% Factors, if they were to occur, which might adversely affect HCRC include decreases in oil and gas prices, the reduced availability of a market for production, rising operating costs of producing oil and gas, compliance with and changes in environmental control statutes and increasing costs and difficulties of transportation. Competition HCRC encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. The Company's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling income programs. As described under "Marketing," production is sold on the spot market, thereby reducing sales competition. Moreover, oil and gas must compete with coal, atomic energy, hydro-electric power and other forms of energy. Regulation Production and sale of oil and gas are subject to federal and state governmental regulations in a variety of ways including environmental regulations, labor laws, interstate sales, excise taxes and federal and Indian lands royalty payments. Failure to comply with these regulations may result in fines, cancellation of licenses to do business and cancellation of federal, state or Indian leases. The production of oil and gas is subject to regulation by the state regulatory agencies in the states in which HCRC does business. These agencies make and enforce regulations to prevent waste of oil and gas and to protect the rights of owners to produce oil and gas from a common reservoir. The regulatory agencies regulate the amount of oil and gas produced by assigning allowable production rates to wells capable of producing oil and gas. Environmental Considerations The exploration for, and development of, oil and gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or can cause environmental pollution problems. In light of the current interest in environmental matters, HCRC cannot predict the effect of possible future public or private action on its business. HCRC is continually taking actions it believes are necessary in its operations to ensure conformity with applicable federal, state and local environmental regulations. As of December 31, 1998, HCRC has not been fined or cited for any environmental violations which would have a material adverse effect upon capital expenditures, earnings or the competitive position of HCRC in the oil and gas industry. Insurance Coverage HCRC is subject to all the risks inherent in the exploration for, and development of, oil and gas, including blowouts, fires and other casualties. HCRC maintains insurance coverage as is customary for entities of a similar size engaged in operations similar to that of HCRC, but losses can occur from uninsurable risks or in amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact upon HCRC's earnings, cash flows and financial position. Issues Related to the Year 2000 General. The following Year 2000 statements constitute a Year 2000 Readiness Disclosure within the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998. The Year 2000 problem has arisen because many existing computer programs use only the last two digits to refer to a year. Therefore, these computer programs do not properly recognize and process date-sensitive information beyond 1999. In general, there are two areas where Year 2000 problems may exist for the Company: information technology such as computers, programs and related systems ("IT") and non-information technology systems such as embedded technology on a silicon chip ("Non IT"). The Plan. The Company's Year 2000 Plan (the "Plan") has four phases: (i) assessment, (ii) inventory, (iii) remediation, testing and implementation and (iv) contingency plans. Approximately twelve months ago, the Company began its phase one assessment of its particular exposure to problems that might arise as a result of the new millennium. The assessment and inventory phases have been substantially completed and have identified the Company's IT systems that must be updated or replaced in order to be Year 2000 compliant. In particular, the software used by the Company for reservoir engineering must be updated or replaced. Remediation, testing and implementation are scheduled to be completed by June 30, 1999, and the contingency plans phase of the Plan is scheduled to be completed by September 30, 1999. However, the effects of the Year 2000 problem on IT systems are exacerbated because of the interdependence of computer systems in the United States. The Company's assessment of the readiness of third parties whose IT systems might have an impact on the Company's business has thus far not indicated any material problems; responses have been received to approximately 50% of the 172 inquiries made. With regard to the Company's Non IT systems, the Company believes that most of these systems can be brought into compliance on schedule. The Company's assessment of third party readiness is not yet completed. Because the potential problem with Non IT systems involves embedded chips, it is difficult to determine with complete accuracy where all such systems are located. As part of its Plan, the Company is making formal and informal inquiries of its vendors, customers and transporters in an effort to determine the third party systems that might have embedded technology requiring remediation. Estimated Costs. Although it is difficult to estimate the total costs of implementing the Plan through January 1, 2000 and beyond, the Company's preliminary estimate is that such costs will not be material. To date, the Company has determined that its IT systems are either compliant or can be made compliant for less than $150,000. However, although management believes that its estimates are reasonable, there can be no assurance, for the reasons stated in the next paragraph, that the actual cost of implementing the Plan will not differ materially from the estimated costs. Potential Risks. The failure to correct a material Year 2000 problem could result in an interruption in, or a failure of, certain normal business activities or operations. This risk exists both as to the Company's IT and Non IT systems, as well as to the systems of third parties. Such failures could materially and adversely affect the Company's results of operations, cash flow and financial condition. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from the uncertainty of the Year 2000 readiness of third party suppliers, vendors and transporters, the Company is unable to determine at this time whether the consequences of Year 2000 failures will have a material impact on the Company's results of operations, cash flow or financial condition. Although the Company is not currently able to determine the consequences of Year 2000 failures, its current assessment is that its area of greatest potential risk in its third party relationships is in connection with the transporting and marketing of the oil and gas produced by the Company. The Company is contacting the various purchasers and pipelines with which it regularly does business to determine their state of readiness for the Year 2000. Although the purchasers and pipelines will not guaranty their state of readiness, the responses received to date have indicated no material problems. The Company believes that in a worst case scenario, the failure of its purchasers and transporters to conduct business in a normal fashion could have a material adverse effect on cash flow for a period of six to nine months. The Company's Year 2000 Plan is expected to significantly reduce the Company's level of uncertainty about the compliance and readiness of these material third parties. The evaluation of third party readiness will be followed by the Company's development of contingency plans. Cautionary Statement Regarding Forward-Looking Statements. In addition, the dates for completion of the phases of the Year 2000 Plan are based on the Company's best estimates, which were derived using numerous assumptions of future events. Due to the general uncertainty inherent in the Year 2000 problem, resulting in part from the uncertainty of the Year 2000 readiness of third-parties and the interconnection of computer systems, the Company cannot ensure its ability to timely and cost-effectively resolve problems associated with the Year 2000 issue that may affect its operations and business. Accordingly, shareholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected, estimated or predicted. ITEM 2 - PROPERTIES Exploration and Development Projects and Acquisitions In 1998, HCRC incurred $37,565,000 in direct property additions, development, exploitation and exploration costs. The costs were comprised of $28,182,000 for property acquisitions and approximately $9,383,000 for domestic exploration and development. The expenditures resulted in the drilling, recompletion, or workover of 41 development wells and 34 exploration wells. HCRC completed 37 development wells (90%) and 18 exploration wells (53%) for an overall completion rate of 73%. HCRC's 1998 capital program led to the replacement, including revisions to prior year reserves, of 120% of 1998 production using year-end prices of $10.00 per bbl and $1.85 per mcf. Using five year average price of $16.64 per bbl and $1.78 per mcf, HCRC's reserve replacement for 1998 would have been 200% of 1998 production. Management utilizes average price reserves internally because it believes these prices more accurately reflect the value to be achieved over time. Excluded from these calculations are sales of reserves in place in 1998, which were approximately 3% of 1998 production. In 1998, HCRC expended approximately $1,672,000 for land and seismic costs, which HCRC anticipates will yield prospects for 1999 and subsequent years. Property Sales During 1998, HCRC received approximately $107,000 for the sale of 67 nonstrategic properties located in eight states. Regional Area Descriptions and 1998 Capital Budget The following discussion of HCRC's properties and capital projects contains forward-looking statements that are based on current expectations, estimates and projections about the oil and gas industry, management's beliefs and assumptions made by management. Words such as "projects," "believes," "expects," "anticipates," "estimates," "plans," "could," variations of such words and similar expressions are intended to identify such forward-looking statements. Please refer to the section entitled "Cautionary Statement Regarding Forward-Looking Statements" for a discussion of factors which could affect the outcome of the forward-looking statements. Greater Permian Region HCRC has significant interests in the Greater Permian Region, which includes West Texas and Southeast New Mexico. In this region, HCRC has interests in 537 productive oil and gas wells (423 of which are operated), 38 operated shut-in oil and gas wells and 17 (15 operated) salt water disposal wells or injection wells. In 1998, HCRC expended approximately $11,685,000 (31%) of its capital budget on projects in this area. HCRC spent approximately $2,200,000 for drilling, recompletion, or workover of 23 development wells and for drilling 18 exploration wells. Seventy-eight percent of the wells drilled or recompleted are producing. The following is a description of the significant areas and 1998 capital projects within the Greater Permian Region. Arcadia Acquisition. In October 1998, HCRC purchased for $8,200,000 oil and gas properties, including interests in approximately 570 wells located primarily in Texas, numerous proven and unproven drilling locations, exploration acreage, and 3-D seismic data. HPI operates approximately 85% of the proven property value. The acquisition added estimated proven reserves of approximately 576,000 barrels of oil and 5.5 billion cubic feet of natural gas at five-year average prices, and approximately 473,000 barrels of oil and 5.5 billion cubic feet of natural gas at year-end pricing. HCRC's estimated proven reserve addition of 9.0 bcfe represents approximately 61% of HCRC's 1998 production at five-year average prices, and 56% of HCRC's 1998 production at year-end prices. HCRC estimates that gross 1999 production from the properties could be approximately 1.1 bcfe. In 1999, HCRC plans to divest approximately 400 of the wells acquired from Arcadia. The wells to be sold are nonstrategic, nonoperated, and represent only 6% of the acquisition's production and 4% of its average price value. During 1999 HCRC plans to study areas for future development project implementation. Carlsbad/Catclaw Area. HCRC's interests in the Carlsbad/Catclaw Area as of December 31, 1998 consisted of 93 producing wells that produce primarily natural gas and are located on the northwestern edge of the Delaware Basin in Lea, Eddy and Chaves Counties, New Mexico. HPI operates 37 of these wells. The wells produce at depths ranging from approximately 2,500 feet to 14,000 feet from the Delaware, Atoka, Bone Springs and Morrow formations. In 1998, HCRC spent approximately $488,000 recompleting or drilling eight producing development wells and drilling one unsuccessful exploration well. HCRC expects to continue operated development drilling in the Hat Mesa Field. East Keystone Area. HCRC's interest in the East Keystone Area as of December 31, 1998 consisted of 55 producing wells, 37 of which are operated by HPI, in Winkler County, Texas. The primary focus of this area is the development of the Holt and San Andreas formations at a depth of 5,100 feet. During 1998, HCRC had eight development projects, of which seven were successful. HCRC's future development plans include a total of three projects for this area. Merkle Area. HCRC's interest in the Merkle Area as of December 31, 1998 consists of 29 producing wells, 16 of which are operated by HPI in Taylor and Nolan Counties, Texas. HCRC's nonoperated interest in the Merkle Area includes 10 square miles of proprietary seismic data in Jones, Nolan and Taylor Counties, Texas, which was acquired in 1995. Based on its initial success in the nonoperated Merkle Area, HCRC acquired 74 additional miles of proprietary 3-D seismic data adjacent to the nonoperated area. HCRC's focus in this area is exploration of the Canyon, Strawn, Flippen, Tannehill and Ellenberger formations at depths of 2,500 to 6,500 feet. In 1998, HCRC drilled 11 exploration wells and one development well, nine of which were completed. HCRC incurred approximately $1,054,000 in costs in 1998 for the 12 wells drilled. HCRC owns an average 28.5% working interest in the wells. Even with current low crude oil prices, continued drilling in this area is economic, and HCRC anticipates additional 1999 drilling to continue to exploit the reef structures. Griffin Project. In 1998, HCRC purchased land for $105,000 and incurred costs of approximately $452,000 to drill three exploration wells and one development well in Gaines County, Texas. None of the four nonoperated 7,500 foot Leonardian sand wells was successful. Due to limited delineation drilling potential in this area and low oil prices, HCRC will delay future drilling and evaluate the viability of the remaining exploration projects. HCRC owns an average 25% working interest in the prospect area. Spraberry Area. HCRC's interests in the Spraberry Area consist of 360 producing wells, 13 salt water disposal wells and 36 shut-in wells in Dawson, Upton, Reagan and Irion Counties, Texas. HPI operates 380 of these wells. Most of the current production from the wells is from the Upper and Lower Spraberry, Clearfork Canyon, Dean and Fusselman formations at depths ranging from 5,000 feet to 9,000 feet. During 1998, HCRC drilled or recompleted three wells, all of which are producing. As a result of low crude oil prices, HCRC abandoned twenty-three wells in this area in 1998. During 1999, HCRC plans to shut-in 29 uneconomic wells and has scheduled 25 additional wells for abandonment. The wells scheduled for shut-in produce, in total, only 40 mcfe per day, net to HCRC, and were operating at a net loss to HCRC of $65,000 per year. Future plans for this area include eight development wells and workovers and additional projects contingent upon future evaluation. The price of crude oil must increase before these projects can be considered viable. Gulf Coast Region HCRC has significant interests in the Gulf Coast Region in Louisiana and South and East Texas. HCRC's most significant interest in the Gulf Coast Region consists of 23 producing gas wells and six salt water disposal wells located in Lafayette Parish, Louisiana. The wells produce principally from the Bol Mex formations at 13,500 to 14,500 feet and 11 are operated by HPI. The two most significant wells in the area are the A.L. Boudreaux #1 and the G.S. Boudreaux Estate #1. In South and East Texas, HCRC has interests in 203 wells, 65 of which are operated by HPI and produce primarily from the Austin Chalk, Paluxy, Lower Frio and Cotton Valley formations at depths from 7,000 to 13,000 feet. During 1998, HCRC expended approximately $4,240,000 (11%) of its capital budget in this region in Louisiana and South and East Texas. The following discussion relates to major 1998 capital projects within the region. Bell Project. HCRC has a 30% working interest in an operated project to evaluate the Buda, Carrizo, Woodbine, and Dexter sands in Houston County, Texas. HCRC's drilling costs in 1998 for a 9,200-foot horizontal well were approximately $615,000. The well encountered Buda pay and sales of production began in December 1998, after gas processing equipment was installed. The well primarily produces oil. HCRC achieved gross sustained production rates of 8.2 mmcfe per day; however, due to current low oil prices, flowing rates have been reduced to approximately 4 mmcfe per day. HCRC also incurred $375,000 in 1998 for land and leasehold costs relating to the project. HCRC plans additional delineation drilling in 1999. HCRC anticipates that single or multi-lateral horizontal drilling will be the principal drilling practice used in this area. The gross targeted potential for the project could be 2.4 bcfe per well. There can be no assurance, however, that any well drilled will be successful. Bison Prospect. HCRC participated in a nonoperated 18,000 foot exploratory well in Lafayette Parish, Louisiana targeting a large Klump sands structure. Drilling problems prevented the well from reaching total depth and testing the primary target horizon in the prospect; however, the secondary target horizon was tested and found to be non-productive. The well was plugged and abandoned. Total land and drilling costs incurred by HCRC during 1998 for its 2.5% working interest were approximately $217,000. Blue Moon Project. During 1998, HCRC entered into a farmout arrangement under which it contributed acreage to a project drilled in Lafayette Parish, Louisiana. A well was recently completed and tested over 14 mmcfe of gas per day. HCRC's after payout working interest in the well depends on unit boundary determinations, but HEP anticipates that its working interest will be between 5% and 7%. HCRC paid no capital costs for its interest in the well, and payout is expected to occur during the second quarter of 1999. East Smith Point. In 1998, HCRC participated in a Frio sand recompletion and a 3-D seismic review of the deep Vicksburg in Chambers County, Texas. HCRC owns a 49% working interest in the project and spent approximately $305,000 for drilling costs and approximately $426,000 for land and geologic and geophysical data. In 1998, the first 14,000-foot recompletion was unsuccessful. HCRC does not plan additional activity in this area. Esperanza Project. HCRC owns a 7.9% working interest in a nonoperated 15,400-foot directional exploration discovery in the Wilcox formation in LaVaca County, Texas. The natural gas prospect was developed using proprietary 3-D seismic data, and the prospect could have a gross target of 60 bcf. The initial well has been completed and showed gross production rates of 10 mmcfd at a flowing tubing pressure of 9,000 psi. HCRC spent approximately $365,000 in 1998 for its share of costs. HCRC plans to participate in additional wells in 1999 to further exploit this discovery. There can be no assurance, however, that any well drilled will be successful. Intercoastal Prospect. In 1998, HPI took over operation of a well in which it did not own an interest in Vermilion Parish, Louisiana. The Planulina sands were faulted out in the original wellbore, and HCRC sidetracked the well at a depth of 14,467 feet to test the sands. The well was drilled and logged, and the objective sands, although well-developed, were found to contain water. The well was plugged and abandoned. HCRC spent $263,000 to test the concept. Mirasoles Project. In 1998, HCRC spent approximately $430,000 for land costs related to the Mirasoles project in Kenedy County, Texas. HCRC owns an interest in 63 square miles of proprietary 3-D seismic data which defines a large structural prospect that could have a gross potential of 395 bcfe. HCRC spent approximately $941,000 in 1998 for its 17.5% working interest share of the cost of drilling a 17,000-foot Frio formation exploration well. The exploratory well is being completed, and depending upon test results, additional delineation and development drilling could be required to properly exploit the structure. There can be no assurance, however, that any well drilled will be successful. Rocky Mountain Region HCRC has significant interests in the Rocky Mountain Region, which include producing properties in Colorado, Montana, North Dakota and Northwest New Mexico. HCRC has interests in 207 producing oil and gas wells, 168 of which are operated by HPI, 27 shut-in wells, 25 of which are operated by HPI, and five salt water disposal wells. HCRC expended approximately $20,669,000 (55%) of its 1998 capital budget in this area. Approximately $17,291,000 of the capital budget was used for the purchase of the volumetric production payment discussed below. In 1998, HCRC spent approximately $2,215,000 to recomplete or drill 13 development wells and to drill three exploration wells. Thirteen of the wells were completed. A discussion of the major projects in the region follows. Cajon Lake Field. In 1998, HCRC sidetracked a 6,000-foot Ismay formation exploration well in San Juan County, Utah. HCRC developed the prospect from proprietary 3-D seismic data and HPI is the operator of the project. HCRC owns an approximate 15% working interest in the project and spent approximately $120,000 to complete the exploration well in 1998. Sales of crude oil production began in November; however, production will be significantly curtailed until a natural gas pipeline is constructed to eliminate flaring. HCRC projects that the fully developed prospect could have 6 bcfe gross potential. There can no assurance, however, that any well drilled will be successful. Despite low oil prices, additional delineation drilling is anticipated in 1999. Colorado Western Slope Project. HCRC drilled and completed two 5,500 foot Dakota formation wells in the Piceance Basin in Western Colorado. HCRC owns an average 51% working interest in the wells. The wells had a combined initial production rate of 1.5 mmcf per day, and both wells began sales of production in the third quarter of 1998. In 1998, HCRC also recompleted an additional well. Total costs in 1998 for the three wells were approximately $565,000. HCRC has identified fourteen additional development locations. HCRC projects that the total project area could have gross potential reserves of 0.8 bcfe, which is the typical reserve potential for this area. There can no assurance, however, that any well drilled will be successful. Toole County Area. HCRC's interests in the Toole County Area consist of 61 producing wells and 17 shut-in wells, 66 of which are operated by HPI. The oil wells produce from the Nisku formation at depths of approximately 3,000 feet, and the gas wells produce from the Bow Island formation at depths of 900 to 1,200 feet. In 1998, HCRC drilled three horizontal wells in the East Kevin Field to the Nisku formation. Two of the oil wells were completed and had combined initial production rates of 1.3 mmcfe per day. HCRC has a 50% working interest in the project and spent approximately $728,000 in 1998. Because of current low oil prices in this sour, lower gravity crude area, HCRC has halted the drilling of additional development wells and has postponed the re-entry and sidetrack of the remaining well drilled in 1998. San Juan Basin Project - Colorado. In July 1996, HCRC and its affiliate Hallwood Energy Partners, L.P. ("HEP") acquired interests in 34 wells in LaPlata County, Colorado producing from the Fruitland Coal formation at approximately 3,000 feet. An unaffiliated large East Coast financial institution formed an entity to utilize tax credits generated from the wells. All production from the wells generates an additional payment of approximately $.68 per mcf. An affiliate of Enron Corp. financed the project through a volumetric production payment ("VPP"). During May 1998, a limited liability company owned equally by HCRC and HEP, purchased the VPP from the affiliate of Enron Corp. HCRC funded its $17,291,000 share of the acquisition price from operating cash flow and borrowings under its Credit Agreement. As a result of the acquisition, HCRC replaced the higher cost and administratively burdensome VPP financing with lower cost conventional borrowings under its line of credit. At the time of the purchase, HCRC entered into a financial contract to hedge the volumes subject to the production payment at an average price of $2.11 per mmbtu. Under the terms of the original 1996 transaction, HCRC and HEP were already responsible for costs associated with the wells. HPI has managed and operated the wells since July 1996, and has increased the wells' gross production from 14 mmcf to approximately 23.5 mmcf per day through workovers and gas gathering facilities improvement programs. The acquisition increased HCRC's current average daily production by 6.25 mmcf per day. San Juan Basin Project - New Mexico. HCRC's interest in the San Juan Basin consists of 51 producing gas wells and 10 shut-in wells located in San Juan County, New Mexico. HPI operates all 51 producing wells in New Mexico, 31 of which produce from the Fruitland Coal formation at approximately 2,200 feet and 20 of which produce from the Pictured Cliffs, Mesa Verde and Dakota formations at 1,200 to 7,000 feet. The expansion of the gathering system significantly increased gas gathering, processing and compression capacity for the associated properties, which resulted in gross production increases of 3.0 mmcf per day in 1998. In addition to proceeds from the sale of gas, HCRC also receives a payment of $.36 per mcf for tax credits generated by production from the coalbed methane wells. Other HCRC owns various other interests in properties in Kansas, Oklahoma, California and South Central Texas. The remaining $971,000 of HCRC's 1998 capital expenditures were incurred in this area. The costs include $325,000 for an unsuccessful exploration project in Carter County, Oklahoma, $157,000 for the completion of an exploration well in Canadian County, Oklahoma and for drilling four unsuccessful exploration wells in Yolo County, California and other miscellaneous projects. During 1998, HCRC also participated in two nonoperated 3-D seismic projects in nearby Solano and Colusa Counties, California. HCRC is in the process of divesting its interests in California projects. As a result of low oil prices and high lifting costs, HCRC plan to shut-in 35 uneconomic wells and to outsource its field workforce in 1999. These cost reduction measures are projected to save $230,000 per year in net operating expenses. Peru Block Z-3 Project. HCRC's partner on the Peruvian offshore Z-3 Block completed 1,200 miles of 2-D seismic data acquisition to supplement existing seismic data. Data interpretation is in progress, and it will be reviewed by HCRC in the first quarter of 1999. HCRC has a 7.5% working interest in the project, but it will not incur capital costs until actual drilling operations begin. Although the production-sharing contract provides that drilling operations must begin no later than January 2002, it is anticipated that the Peruvian government will enact legislation to extend the period for all drilling commitments by one year. For 1999, HCRC's capital budget, which will be paid from cash generated from operations and cash on hand, has been set at $5,152,000. HCRC has budgeted continued low oil prices for 1999 which significantly impacts cash generated from operations. Consequently, the capital budget has been set at a lower amount than the budget for past years. The capital budget for 1999 will be reduced if HCRC is required to make a principal payment on its debt and if oil and gas prices decrease further. Company Reserves, Production and Discussion by Significant Regions The following table presents the December 31, 1998 reserve data by significant regions.
Present Value of Proved Reserve Quantities Estimated Future Net Cash Flows Proved Proved Mcf of Gas Bbls of Oil Undeveloped Developed Total (In thousands) Greater Permian Region 10,980 1,950 $11,480 $11,480 Gulf Coast Region 14,574 840 $1,735 19,027 20,762 Rocky Mountain Region 60,226 706 48,009 48,009 Mid-Continent Region 1,087 517 1,710 1,710 Other 140 20 45 1,994 2,039 -------- ------- -------- ------ ------ 87,007 4,033 $1,780 $82,220 $84,000 ====== ===== ===== ====== ======
The following table presents the oil and gas production for significant regions.
Production for the Production for the Year Ended 1998 Year Ended 1997 --------------- --------------- Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil ---------- ----------- ---------- ----------- (In thousands) Greater Permian Region 1,705 318 1,719 308 Gulf Coast Region 2,481 75 1,875 64 Rocky Mountain Region 5,983 104 3,977 107 Mid-Continent Region 214 201 234 214 Other 172 18 158 18 --------- ----- ------- ----- 10,555 716 7,963 711 ====== === ===== ===
The following table presents the Company's extensions and discoveries by significant regions.
For the Year Ended 1998 For the Year Ended 1997 Mcf of Gas Bbls of Oil Mcf of Gas Bbls of Oil (In thousands) Greater Permian Region 217 207 529 238 Gulf Coast Region 998 186 295 21 Rocky Mountain Region 91 96 1,756 234 Mid-Continent Region 53 1 43 Other 4 314 26 ------- ----- ------ ----- 1,363 490 2,894 562 ===== === ===== ===
Average Sales Prices and Production Costs The following table presents the average oil and gas sales price and average production costs per equivalent mcf computed at the ratio of six mcf of gas to one barrel of oil.
1998 1997 1996 ---- ---- ---- Average sales price (including effects of hedging): Oil and condensate (per bbl) $13.12 $18.87 $20.13 Natural gas (per mcf) 1.91 2.17 1.99 Production costs (per equivalent mcf) .78 .84 .78
Productive Oil and Gas Wells The following table summarizes the productive oil and gas wells as of December 31, 1998 attributable to HCRC's direct interests. Productive wells are producing wells and wells capable of production. Gross wells are the total number of wells in which HCRC has an interest. Net wells are the sum of HCRC's fractional interests owned in the gross wells. Gross Net Productive Wells Oil 1,209 104 Gas 319 65 ------- ---- 1,528 169 ===== === Oil and Gas Acreage The following table sets forth the developed and undeveloped leasehold acreage held directly by HCRC as of December 31, 1998. Developed acres are acres which are spaced or assignable to productive wells. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Gross acres are the total number of acres in which HCRC has a working interest. Net acres are the sum of HCRC's fractional interest owned in the gross acres. Gross Net Developed acreage 91,436 28,728 Undeveloped acreage 306,437 73,727 ------- -------- Total 397,873 102,455 ======= ======= HCRC holds undeveloped acreage in Texas, Louisiana, Montana, Wyoming, New Mexico, Kansas, Colorado and North Dakota. Drilling Activity The following table sets forth the number of wells attributable to HCRC's direct interest drilled in the most recent three years.
Year Ended December 31, --------------------------- 1998 1997 1996 ---- ---- ---- Gross Net Gross Net Gross Net Development Wells: Productive 11 3.4 23 4.0 29 6.2 Dry 5 1.5 4 1.0 4 1.0 -- --- -- --- -- --- Total 16 4.9 27 5.0 33 7.2 == === == === == === Exploratory Wells: Productive 17 4.9 14 2.7 1 .1 Dry 16 3.3 22 4.2 4 .6 -- --- -- --- -- --- Total 33 8.2 36 6.9 5 .7 == === == === == ===
Office Space HCRC is guarantor of 40% of the obligation under the Denver, Colorado office leases which are in the name of HPI. Hallwood Energy Partners, L.P. ("HEP") is guarantor of the remaining 60% of the obligation. HPI's current lease, for approximately $600,000 per year, expires in June 1999. During February 1999, HPI entered into another office lease for approximately $600,000 per year. The new lease commences upon occupancy, which is expected to be in June or July 1999, and terminates in seven and one-half years. ITEM 3 - LEGAL PROCEEDINGS See Notes 14 and 15 to the financial statements included in Item 8 - Financial Statements and Supplementary Data. ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 1998. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS HCRC's common stock has traded over the counter on the NASDAQ National Market System under the symbol "HCRC," since June 4, 1992. As of March 24, 1999, there were 2,123 holders of record of HCRC's common stock. The following table sets forth, for the periods indicated, the high and low closing bid quotations for the common stock as reported by the National Quotation Bureau. HCRC did not pay a dividend during the periods shown. During the third quarter of 1997, the stockholders of HCRC approved a three-for-one split of HCRC's common stock. The stock split was effected by issuing, as a stock dividend, two additional shares of Common Stock for each share outstanding. The stock dividend was paid on August 11, 1997 to shareholders of record on August 4, 1997. The stockholders also approved an increase in the number of authorized shares of common stock from 2,000,000 shares to 10,000,000 shares. HCRC Common Stock High Low First quarter 1997 30 1/6 22 3/4 Second quarter 1997 25 15 Third quarter 1997 30 1/2 20 Fourth quarter 1997 26 21 1/4 First quarter 1998 21 9/16 14 1/4 Second quarter 1998 16 15/16 14 3/8 Third quarter 1998 17 3/8 12 Fourth quarter 1998 15 9 1/2 All share and per share information has been retroactively restated for the three-for-one stock split effective August 11, 1997. ITEM 6 - SELECTED FINANCIAL DATA The following table sets forth selected financial data regarding HCRC's financial position and results of operations as of the dates indicated. All per share information has been restated to reflect the three-for-one stock split, which was effective August 11, 1997.
Hallwood Consolidated Resources Corporation As of and for the Year Ended December 31, 1998 1997 1996 1995 1994 ---- ---- ---- ---- ---- (In thousands except per share) Summary of Operations Oil and gas revenues and pipeline operations $ 32,230 $ 32,258 $ 34,308 $ 25,349 $ 20,459 Total revenue 32,410 32,411 34,445 25,484 20,644 Production operating expense 11,642 10,218 10,383 8,514 8,367 Depreciation, depletion and amortization 11,463 8,605 9,246 8,206 7,340 Impairment 19,600 9,277 4,721 General and administrative expense 4,451 4,884 4,011 4,630 3,842 Net income (loss) (20,279) 5,585 8,210 (4,670) (2,974) Net income (loss) per share - basic (7.38) 2.05 3.00 (1.48) (.93) Net income (loss) per share - diluted (7.38) 1.97 2.91 (1.48) (.93) Balance Sheet Working capital (deficit) $ (5,696) $ 4,867 $ (47) $ (7,202) $ 430 Property, plant and equipment, net 87,322 76,031 67,285 65,433 55,011 Total assets 101,167 92,371 78,468 73,939 62,125 Noncurrent liabilities 53,316 32,678 24,558 21,790 11,890 Stockholders' equity 29,589 48,686 43,061 36,635 43,589
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS During 1998, HCRC had a net loss of $20,279,000, compared to a net income of $5,585,000 for 1997. The 1998 period includes noncash charges in the second, third and fourth quarters totaling $19,600,000 for property impairments which were taken to lower the capitalized cost of HCRC's properties to an amount equal to the present value, discounted at 10%, of the future net revenues attributable to those properties. HCRC's 1998 property impairments were recorded pursuant to ceiling test limitations required by the Securities and Exchange Commission for companies using the full cost method of accounting. The total impairment was primarily attributable to the decline in commodity prices and the write-off of certain unproved acreage. The weighted average prices received by HCRC for oil and gas have declined in each of the last four quarters. HCRC's hedges mitigated the price reductions by increasing the average oil and gas prices by 3% and 2%, respectively. HCRC's weighted average oil and gas prices, when the effects of hedging are considered, were 30% and 12% lower, respectively, for 1998 compared to 1997. Although HCRC's production for 1998 was 21% greater than the prior year, and operating and general and administrative expenses were lower on a unit of production basis, net income was lower because of low commodity prices and costs associated with the resolution of litigation. In December 1998 HCRC announced a proposal to consolidate HCRC with HEP and the energy interests of Hallwood Group into a new corporation called Hallwood Energy Corporation. The consolidation proposal was approved by the Board of Directors of HCRC and the general partner of HEP in December 1998. Because of the larger size of the new corporation, HCRC anticipates that the new company will have the ability to take advantage of opportunities that are unavailable to smaller entities such as HCRC and will have a better ability to raise capital. Hallwood Energy Corporation will focus on reserve growth. A Joint Proxy Statement/Prospectus for the consolidation was filed with the Securities Exchange Commission on December 30, 1998 and is proceeding through the usual SEC comment process. It is presently anticipated that the Joint Proxy Statement/Prospectus will be mailed to shareholders of HCRC and unitholders of HEP in April and that the consolidation will be concluded in May 1999. There can be no assurance, however, that all conditions to the consolidation will be satisfied by that time. Liquidity and Capital Resources Cash Flow HCRC generated $6,130,000 of cash flow from operating activities during 1998. The other primary cash inflows were: o $25,500,000 from borrowings under long-term debt and o $2,792,000 in distributions received from affiliates. Cash was primarily used for: o $37,565,000 for property additions, exploration and development costs and o $1,045,000 for payments on contract settlement obligation. When combined with miscellaneous other cash activity during the year, the result was a decrease in HCRC's cash and cash equivalents of $3,941,000 for the year, from $4,492,000 at December 31, 1997 to $551,000 at December 31, 1998. Property Purchases, Sales and Capital Budget In 1998, HCRC incurred $37,565,000 in direct property additions, development, exploitation and exploration costs. The costs were comprised of $28,182,000 for property acquisitions and approximately $9,383,000 for domestic exploration and development. HCRC's 1998 capital program led to the replacement, including revisions to prior year reserves, of 120% of 1998 production using year-end prices of $10.00 per bbl and $1.85 per mcf. In the Greater Permian Region, HCRC expended $8,385,000 acquiring oil and gas properties, including interests in approximately 570 wells, numerous proven and unproven drilling locations, exploration acreage, and 3-D seismic data. Additionally, HCRC spent approximately $488,000 to recomplete or drill nine producing development wells and one unsuccessful exploration well in the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico. Also, approximately $1,066,000 was spent to drill 11 exploration wells and one development well, nine of which were completed in the Merkle Project. HCRC incurred approximately $452,000 drilling three exploration wells and one development well in the Griffin area, all of which were unsuccessful. In the Gulf Coast Region, HCRC spent approximately $430,000 for land and $941,000 to drill one Mirasoles exploration well in Kenedy County, Texas, which is currently in the completion phase. HCRC incurred approximately $365,000 to drill one successful exploration well relating to the Esperanza project in LaVaca County, Texas. Approximately $375,000 was incurred by HCRC for land and leasehold costs and an additional $615,000 for costs associated with drilling one successful exploration well in Bell County, Texas. 1998 costs relating to the East Smith Point project in Chambers County, Texas were approximately $426,000 for land and geologic and geophysical data and an additional $305,000 to drill one unsuccessful exploration well in the area. In addition approximately $217,000 was incurred in 1998 by HCRC to drill one well now plugged and abandoned as part of the Bison project in Lafayette Parish, Louisiana. HCRC's significant property acquisition in the Rocky Mountain Region was approximately $17,291,000 for the purchase of a volumetric production payment in the Colorado San Juan Basin. Additionally, HCRC's significant exploration and development expenditures in the Rocky Mountain Region included approximately $120,000 to complete a successful exploration well within the Cajon Lake Field in Utah; approximately $565,000 to drill three successful wells in the Colorado Western Slope area; approximately $245,000 to drill an unsuccessful exploration well in the West Sioux area of Montana; and approximately $728,000 to drill three horizontal wells in Toole County, Montana, two of which were successful. See Item 2 - Properties, for further discussion of HCRC's exploration and development projects. Long-lived assets, other than oil and gas properties, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. To date, the Company has not recognized any impairment losses on long-lived assets other than oil and gas properties. The Company made an offer to repurchase odd lot holdings of 99 or fewer shares from its stockholders of record as of November 30, 1995. The offer was initially for the period from November 30, 1995 through January 5, 1996 and was subsequently extended through January 26, 1996. The Company repurchased a total of 296,607 shares through the January 26, 1996 closing date for $2,382,000 at a purchase price of $8.03 per share, of which $1,312,000 was expended during 1996. On April 1, 1996, HCRC made another offer to purchase holding of 99 or fewer shares from its stockholders of record as of March 25, 1996. The offer was for the period from April 1, 1996 through May 3, 1996. The Company repurchased a total of 77,790 shares at a price of $11.33 per share. HCRC resold 38,895 of these shares to HEP at the price paid by HCRC for such shares, resulting in a net repurchase cost to HCRC of $438,000. Financing On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes ("Subordinated Notes") due December 23, 2007 to The Prudential Insurance Company of America ("Prudential"). HCRC also sold Warrants to Prudential to purchase 98,599 shares of Common Stock at an exercise price of $28.99 per share. The Subordinated Notes bear interest at the rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual principal payments of $5,000,000 are due on each of December 23, 2003 through December 23, 2007. The proceeds from the Subordinated Notes were allocated to the Subordinated Notes and to the Warrants based upon the relative fair values of the Subordinated Notes without the Warrants and of the Warrants themselves at the time of issuance. The allocated value of the Warrants of $1,032,000 was recorded as paid-in-capital. The discount on the Subordinated Notes is being amortized over the term of the Subordinated Notes using the interest method of amortization. Because of the substantial property impairments taken in 1998, HCRC's net worth at December 31, 1998, was less than the amount required under the terms of its Subordinated Note agreement. At December 31, 1998, HCRC was not in compliance with the net worth covenant under the Subordinated Note agreement and under its Credit Agreement. HCRC has obtained a waiver of compliance with the covenants from both the Subordinated Note holder and HCRC's lenders under its Credit Agreement. In March 1999, the Subordinated Note agreement was amended to reduce the net worth requirement to $25,000,000 until the earlier of March 31, 2000 or the last day of the fiscal quarter immediately before the consolidation with HEP. During 1997, the Company and its banks amended their Credit Agreement to extend the term date of the line of credit to May 31, 1999. The banks are Morgan Guaranty Trust Company, First Union National Bank and NationsBank of Texas. Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. As of December 31, 1998, the Company had amounts outstanding of $25,500,000. HCRC's unused borrowing base totaled $1,000,000 at March 24, 1999. Borrowings against the Credit Agreement bear interest, at the option of the Company, at either (i) the banks' Certificate of Deposit rate plus from 1.375% to 1.875%, (ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the prime rate of Morgan Guaranty Trust or the sum of one-half of 1% and the Federal funds rate, plus .75%. The applicable interest rate was 6.75% at December 31, 1998. Interest is payable at least quarterly, and quarterly principal payments of $1,594,000 commence May 31, 1999. The Credit Agreement is secured by a first lien on approximately 80% in value of the Company's oil and gas properties. The borrowing base for the Credit Agreement is redetermined semiannually, and the next redetermination is scheduled for the second quarter of 1999. HCRC anticipates that, because of low oil and gas prices, its lenders will reduce the borrowing base and that HCRC will be required to make a principal payment on its debt. Any required principal payment will reduce the amount available for HCRC's capital budget. As part of its risk management strategy, HCRC enters into financial contracts to hedge the interest payments related to a portion of its outstanding borrowings under its Credit Agreement. HCRC does not use the hedges for trading purposes, but rather to protect against the variability of cash flows under its Credit Agreement, which has a floating interest rate. The amounts received or paid upon settlement of these transactions are recognized as interest expense at the time the interest payments are due. As of March 24, 1999, HCRC was a party to six contracts with three counterparties. The following table provides a summary of the Company's financial contracts. Average Amount of Contract Period Debt Hedged Floor Rate 1999 $13,000,000 5.70% 2000 15,000,000 5.65% 2001 12,000,000 5.23% 2002 12,500,000 5.23% 2003 12,500,000 5.23% 2004 2,000,000 5.23% Stock Split During July 1997, the stockholders of HCRC approved an increase in the number of authorized shares of its Common Stock from 2,000,000 shares to 10,000,000 shares. HCRC also declared a three-for-one split of its outstanding, Common Stock. The stock split was effected by issuing, as a stock dividend, two additional shares of Common Stock for each share outstanding. The stock dividend was paid on August 11 to shareholders of record on August 4. All share and per share information has been restated to reflect the three-for-one stock split. Stock Option Plans During 1995, the Company adopted a stock option plan covering 159,000 shares of Common Stock and granted options for all of the shares under the plan. The options were granted effective July 1, 1995 at an exercise price of $6.67 per share, which was equal to the fair market value of the Common Stock on the date of grant. The options expire on July 1, 2005, unless sooner terminated pursuant to the provisions of the plan. During 1997, options to purchase 9,200 shares were exercised, and during 1998 options to purchase 21,040 shares were exercised. During the second quarter of 1997, the Company adopted a stock option plan covering 159,000 shares of Common Stock and granted options for all of the shares under the plan. The terms of this plan are generally consistent with the terms of the Company's existing 1995 Stock Option Plan. The options were granted effective June 17, 1997 at an exercise price of $20.33 per share, which was equal to the fair market value of the Common Stock on the date of grant. The options expire on June 17, 2007, unless sooner terminated pursuant to the provisions of the plan. The options are exercisable one-third on June 17, 1997, an additional one-third June 17, 1998, and the remaining one-third on June 17, 1999. In addition, the plan provides that vesting of the options may be accelerated under certain conditions. On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock under its 1997 Stock Option Plan at an exercise price of $15.75 which was equal to the fair market value of the Common Stock on the date of grant. One-third of the options vest immediately, and the remainder vest one-half on the first anniversary of the date of grant and one-half on the second anniversary of the date of grant. On May 5, 1998, HCRC also granted options to purchase 9,540 shares of Common Stock at an exercise price of $15.75 per share which was equal to the fair market value of the Common Stock on the date of grant. These options were not granted pursuant to a previously existing plan, but are subject to terms and conditions identical to those in HCRC's 1995 Stock Option Plan. One-third of the options vest immediately, and the remainder vest one-half on the first anniversary of the date of grant and one-half on the second anniversary of the date of grant. Gas Balancing HCRC uses the sales method to account for gas balancing. Under this method, HCRC recognizes revenue on all of its sales of production, and any over-production or under-production is recovered at a future date. As of December 31, 1998, HCRC had a net over-produced position of 347,000 mcf ($642,000 valued at year-end prices). The management of HCRC believes that this imbalance can be made up with production from existing wells or from wells which will be drilled as offsets to current producing wells and that this imbalance will not have a material effect of HCRC's results of operations, liquidity and capital resources. The reserves discussed in Item 2 and Item 8 have been reduced by 347,000 mcf in order to reflect HCRC's gas balancing position. Recently Issued Accounting Pronouncements In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS 130"). SFAS 130 established standards for reporting and display of comprehensive income and its components (revenues, expenses, gains, and losses) in a full set of general-purpose financial statements. SFAS 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. Reclassification of financial statements for earlier periods provided for comparative purposes is required. The Company adopted SFAS 130 on January 1, 1998. The Company does not have any items of other comprehensive income for the years ended December 31, 1998, 1997 and 1996. Therefore, total comprehensive income (loss) is the same as net income (loss) for those years. In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards for reporting selected information about operating segments and related disclosures about products and services, geographic areas, and major customers. SFAS 131 requires that an entity report financial and descriptive information about its operating segments which are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. HCRC adopted FAS 131 in 1998. The Company engages in the development, production and sale of oil and gas, and the acquisition, exploration, development and operation of oil and gas properties in the continental United States. These activities exhibit similar economic characteristics and involve the same products, production processes, class of customers, and methods of distribution. Management of the Company evaluates its performance as a whole rather than by product or geographically. As a result, HCRC's operations consist of one reportable segment. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. The Company is required to adopt SFAS 133 on January 1, 2000. The Company has not completed the process of evaluating the impact that will result from adopting SFAS 133. Cautionary Statement Regarding Forward-Looking Statements In the interest of providing the shareholders with certain information regarding the Company's future plans and operations, certain statements set forth in this Form 10-K relate to management's future plans and objectives. Such statements are forward-looking statements within the meanings of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Although any forward-looking statements contained in this Form 10-K or otherwise expressed by or on behalf of the Company are, to the knowledge and in the judgment of the officers and directors of the Company, expected to prove true and come to pass, management is not able to predict the future with absolute certainty. Forward-looking statements involve known and unknown risks and uncertainties which may cause the Company's actual performance and financial results in future periods to differ materially from any projection, estimate or forecasted result. These risks and uncertainties include, among others: Volatility of oil and gas prices. It is impossible to predict future oil and gas price movements with certainty. Declines in oil and gas prices may materially adversely affect HCRC's financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and gas prices may also reduce the amount of oil and gas that HCRC can produce economically. HCRC's revenues, profitability, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, will be substantially dependent upon prevailing prices of oil and gas. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond HCRC's control. Competition from larger, more established oil and gas companies. HCRC encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. HCRC's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than HCRC's and, in many instances, have been engaged in the oil and gas business for a much longer time than HCRC. Those companies may be able to pay more for exploratory prospects and productive oil and gas properties, and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than HCRC's financial or human resources permit. HCRC's ability to explore for oil and gas prospects and to acquire additional properties in the future will be dependent upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in highly competitive environments. Risks of drilling activities. HCRC's success will be materially dependent upon the continued success of its drilling program. HCRC's future drilling activities may not be successful and, if drilling activities are unsuccessful, such failure will have an adverse effect on HCRC's future results of operations and financial condition. Oil and gas drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered, even if the reserves targeted are classified as proved. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. Although HCRC has identified numerous drilling prospects, there can be no assurance that such prospects will be drilled or that oil or gas will be produced from any such identified prospects or any other prospects. Risks relating to the acquisition of oil and gas properties. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact and their accuracy inherently uncertain. In connection with such an assessment, HCRC will perform a review of the subject properties that it believes to be generally consistent with industry practices. This usually includes on-site inspections and the review of reports filed with various regulatory entities. Such a review, however, will not reveal all existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of these problems. There can be no assurances that any acquisition of property interests by HCRC will be successful and, if an acquisition is unsuccessful, that the failure will not have an adverse effect on HCRC's future results of operations and financial condition. Hazards relating to well operations and lack of insurance. The oil and gas business involves certain hazards such as well blowouts; craterings; explosions; uncontrollable flows of oil, gas or well fluids; fires; formations with abnormal pressures; pollution; and releases of toxic gas or other environmental hazards and risks, any of which could result in substantial losses to HCRC. In addition, HCRC may be liable for environmental damages caused by previous owners of property purchased or leased by HCRC. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of HCRC's properties. While HCRC believes that it maintains all types of insurance commonly maintained in the oil and gas industry, it does not maintain business interruption insurance. In addition, HCRC cannot predict with certainty the circumstances under which an insurer might deny coverage. The occurrence of an event not fully covered by insurance could have a materially adverse effect on HCRC's financial condition and results of operations. Future oil and gas production depends on continually replacing and expanding reserves. In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. HCRC's future oil and gas production is, therefore, highly dependent upon its ability to economically find, develop or acquire additional reserves in commercial quantities. Except to the extent HCRC acquires properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of HCRC will decline as reserves are produced. The business of exploring for, developing or acquiring reserves is capital-intensive. To the extent cash flow from operations is reduced, and external reserves of capital become limited or unavailable, HCRC's ability to make the necessary capital investments to maintain or expand its asset base of oil and gas reserves would be impaired. In addition, there can be no assurance that HCRC's future exploration, development and acquisition activities will result in additional proved reserves or that HCRC will be able to drill productive wells at acceptable costs. Furthermore, although HCRC's revenues could increase if prevailing prices for oil and gas increase significantly, HCRC's finding and development costs could also increase. Estimates of reserves and future cash flows are imprecise. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies, and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineers but at different times, may vary substantially, and such reserve estimates may be subject to downward or upward adjustment based upon such factors. In addition, the status of the exploration and development program of any oil and gas company is ever-changing. Consequently, reserve estimates also vary over time. Actual production, revenues and expenditures with respect to HCRC's reserves will likely vary from estimates, and such variances may be material. Inflation and Changing Prices Prices obtained for oil and gas production depend upon numerous factors that are beyond the control of HCRC, including the extent of domestic and foreign production, imports of foreign oil, market demand, domestic and worldwide economic and political conditions and government regulations and tax laws. Prices for both oil and gas have fluctuated from 1996 through 1998, with a distinct downward trend in both oil and gas prices occurring in the calendar year 1998. HCRC anticipates that both oil and gas prices will remain low throughout 1999. In preparing its 1999 budget, HCRC has estimated that the weighted average oil price (for barrels not hedged) will be $11.00 per barrel, and the weighted average price of natural gas (for mcf not hedged) will be $1.70 per mcf for the year. There can be no assurance that HCRC's forecast is accurate. If prices decrease further, it can be expected that the results of operations and cash flow will be affected, and HCRC's capital budget will decrease. The following table presents the weighted average prices received per year by HCRC, and the effects of the hedging transactions discussed below.
Oil Oil Gas Gas (excluding the effects (including the effects (excluding the effects (including the effects of hedging of hedging of hedging of hedging transactions ) transactions ) transactions ) transactions ) ------------------- ------------------- ------------------- ------------------- (Bbl) (Bbl) (Mcf) (Mcf) 1998 $12.75 $13.12 $1.87 $1.91 1997 19.13 18.87 2.39 2.17 1996 20.96 20.13 2.11 1.99
As part of its risk management strategy, HCRC enters into financial contracts to hedge the price of its oil and natural gas. The purpose of the hedges is to provide protection against price decreases and to provide a measure of stability in the volatile environment of oil and natural gas spot pricing. The amounts received or paid upon settlement of the hedge contracts are recognized as increases or decreases in oil or gas revenue at the time the hedged volumes are sold. During 1998, HCRC did not enter into additional oil price hedges for future years because hedge contracts at prices HCRC considers advantageous are not available. The financial contracts used by HCRC to hedge the price of its oil and natural gas production are swaps, collars and participating hedges. Under the swap contracts, HCRC sells its oil and gas production at spot market prices and receives or makes payments based on the differential between the contract price and a floating price which is based on spot market indices. As of March 24, 1999, HCRC was a party to 18 financial contracts with three different counterparties. The following table provides a summary of the Company's financial contracts: Oil Percent of Direct Production Contract Period Hedged Floor Price (per bbl) 1999 4% $14.88 All of the oil volumes hedged are subject to participating hedges whereby HCRC will receive the contract price if the posted futures price is lower than the contract price, and will receive the contract price plus 25% of the difference between the contract price and the posted futures price if the posted futures price is greater than the contract price. All of the volumes hedged are subject to a collar agreement whereby HCRC will receive the contract price if the spot price is lower than the contract price, the cap price if the spot price is higher than the cap price, and the spot price if that price is between the contract price and the cap price. The cap prices range from $16.50 to $18.35 per barrel. Gas Percent of Direct Production Contract Period Hedged Floor Price (per mcf) 1999 42% $1.95 2000 33% 1.95 2001 33% 1.92 2002 32% 1.98 During the first quarter through March 24, 1999, the weighted average oil price (for barrels not hedged) was approximately $10.95 per barrel, and the weighted average price of natural gas (for mcfs not hedged) was approximately $1.65 per mcf. Inflation Inflation did not have a material impact on the Company in 1998, 1997 and 1996 and is not anticipated to have a material impact in 1999. Results of Operations The following tables are presented to contrast HCRC's revenue, expense and earnings for discussion purposes. Significant fluctuations are discussed in the accompanying narrative. The "direct owned" column represents HCRC's direct royalty and working share interests in oil and gas properties. The "HEP" column represents HCRC's share of the results of operations of HEP; HCRC owned approximately 19% of the outstanding limited partner units of HEP during 1996, 1997 and 1998.
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION (In thousands except price) For the Year Ended December 31, 1998 For the Year Ended December 31, 1997 ------------------------------------ ------------------------------------ Direct Direct Owned HEP Total Owned HEP Total Gas production (mcf) 8,139 2,416 10,555 5,951 2,012 7,963 Oil production (bbl) 576 140 716 576 135 711 Average gas price $ 1.87 $ 2.04 $ 1.91 $ 2.14 $ 2.25 $ 2.17 Average oil price $12.97 $13.71 $13.12 $18.84 $19.00 $18.87 Gas revenue $15,222 $4,920 $20,142 $12,719 $4,532 $17,251 Oil revenue 7,473 1,919 9,392 10,851 2,565 13,416 Pipeline and other 1,947 749 2,696 1,035 556 1,591 Interest income 112 68 180 84 69 153 ------- ------- ------- -------- ------- --------- Total revenue 24,754 7,656 32,410 24,689 7,722 32,411 Production operating 9,349 2,293 11,642 8,108 2,110 10,218 General and administrative 3,535 916 4,451 3,908 976 4,884 Interest 3,634 526 4,160 1,675 583 2,258 Depreciation, depletion, and amortization 8,948 2,515 11,463 6,621 1,984 8,605 Impairment of oil and gas properties 19,600 19,600 Litigation 827 260 1,087 ------- ------ ------- ----------- --------- ------- 45,893 6,510 52,403 20,312 5,653 25,965 INCOME (LOSS) BEFORE INCOME TAXES (21,139) 1,146 (19,993) 4,377 2,069 6,446 ------- ----- ------- ------- ----- ------- PROVISION (BENEFIT) FOR INCOME TAXES: Current (164) (164) 961 961 Deferred 450 450 (100) (100) --------- --------- -------- -------- 286 286 861 861 --------- --------- -------- -------- NET INCOME (LOSS) $(21,425) $1,146 $(20,279) $ 3,516 $2,069 $ 5,585 ======= ===== ======= ======= ===== =======
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION (In thousands except price) For the Year Ended December 31, 1996 Direct Owned HEP Total Gas production (mcf) 6,134 2,146 8,280 Oil production (bbl) 668 169 837 Average gas price $ 1.93 $ 2.15 $ 1.99 Average oil price $20.17 $19.98 $20.13 Gas revenue $11,826 $4,620 $16,446 Oil revenue 13,476 3,376 16,852 Pipeline and other 510 500 1,010 Interest income 28 109 137 ---------- ------ -------- Total revenue 25,840 8,605 34,445 Production operating 8,203 2,180 10,383 General and administrative 3,186 825 4,011 Interest 1,800 730 2,530 Depreciation, depletion, and amortization 7,050 2,196 9,246 Other 24 90 114 ---------- ------- -------- 20,263 6,021 26,284 INCOME BEFORE INCOME TAXES 5,577 2,584 8,161 ------- ----- ------- PROVISION (BENEFIT) FOR INCOME TAXES: Current 301 301 Deferred (350) (350) ------- ------- (49) (49) -------- -------- NET INCOME $5,626 $2,584 $8,210 ===== ===== =====
1998 Compared to 1997 Gas Revenue Gas revenue increased $2,891,000 during 1998 compared with 1997. The increase is comprised of an increase in production from 7,963,000 mcf in 1997 to 10,555,000 mcf in 1998 partially offset by a decrease in the average gas price from $2.17 per mcf in 1997 to $1.91 per mcf in 1998. Production increased because two temporarily shut-in wells were back on line. The two wells were temporarily shut-in during the second quarter of 1997 while workover procedures were performed. The increase in gas production is also due to an expansion of the gathering system in San Juan County, New Mexico during 1998. The effect of HCRC's hedging activity was to increase HCRC's average price from $1.87 per mcf to $1.91 per mcf, resulting in a $422,000 increase in revenue. Oil Revenue Oil revenue decreased $4,024,000 during 1998 compared with 1997. The decrease in revenue is primarily due to a decrease in price from $18.87 per barrel in 1997 to $13.12 per barrel in 1998, partially offset by an increase in production from 711,000 barrels in 1997 to 716,000 barrels in 1998. Production increased slightly because two temporarily shut-in wells were back on line. The two wells were temporarily shut-in during the second quarter of 1997 while workover procedures were performed. This increase in production was partially offset by normal production declines. The effect of HCRC's hedging transactions was to increase HCRC's average oil price from $12.75 per barrel to $13.12 per barrel, resulting in a $265,000 increase in revenue. Pipeline and Other Pipeline and other revenue consists of revenue derived from saltwater disposal, incentive and tax credit payments from certain coalbed methane wells, and other miscellaneous revenue. Pipeline and other revenue increased $1,105,000 during 1998 compared to 1997, primarily due to increased incentive payment income resulting from HCRC's acquisition of a volumetric production payment during May 1998. Interest Income Interest income increased $27,000 during 1998 compared with 1997 primarily due to an increase in the average cash balance during 1998. Production Operating Expense Production operating expense increased $1,424,000 during 1998 compared to 1997. The increase is due to increased operating costs resulting from the drilling projects completed during 1997 as well as the additional operating expenses related to the properties acquired in the Arcadia acquisition during October 1998. General and Administrative Expense General and administrative expense includes costs incurred for direct administrative services such as legal, audit and reserve reports as well as allocated internal overhead incurred by HPI on behalf of the Company. These costs decreased $433,000 during 1998 compared to 1997, primarily as a result of decreased performance based compensation during 1998. Interest Expense Interest expense increased $1,902,000 in 1998 compared to 1997, primarily as a result of a higher average debt balance during 1998. Depreciation, Depletion and Amortization Expense Depreciation, depletion and amortization expense associated with proved oil and gas properties increased $2,858,000 during 1998 compared with 1997. This increase is due to a higher depletion rate resulting from the increased production discussed above, as well as higher capitalized costs during 1998. Impairment of Oil and Gas Properties Impairment of oil and gas properties during 1998 represents the impairments recorded during 1998 because capitalized costs exceeded the present value (discounted at 10%) of estimated future net revenues from proved oil and gas reserves at June 30, 1998, September 30, 1998 and December 31, 1998, based on prices of $13.00 per barrel of oil and $1.90 per mcf of gas, $12.75 per barrel of oil and $1.80 per mcf of gas and $10.00 per barrel of oil and $1.85 per mcf of gas, respectively. Litigation Litigation expense during 1998 is comprised of the costs related to the Arcadia arbitration described in Item 8, Note 14. 1997 Compared to 1996 Gas Revenue Gas revenue increased $805,000 during 1997 as compared with 1996. The increase is comprised of an increase in the average gas price from $1.99 per mcf in 1996 to $2.17 per mcf in 1997, partially offset by a decrease in production from 8,280,000 mcf in 1996 to 7,963,000 mcf in 1997. The decrease in production is due to the temporary shut-in of two wells in Louisiana during the second quarter of 1997 while workover procedures were performed and to normal production declines. The effect of HCRC's hedging activity was to decrease HCRC's average gas price from $2.39 per mcf to $2.17 per mcf, resulting in a $1,752,000 decrease in revenue. Oil Revenue Oil revenue decreased $3,436,000 during 1997 as compared with 1996. The decrease in revenue is comprised of a decrease in price from $20.13 per barrel in 1996 to $18.87 per barrel in 1997 and a 15% decrease in oil production from 837,000 barrels in 1996 to 711,000 barrels in 1997. The decrease in production is due to the temporary shut-in of two wells in Louisiana during the second quarter of 1997 while workover procedures were performed and to normal production declines. The effect of HCRC's hedging transactions was to decrease HCRC's average oil price from $19.13 per barrel to $18.87 per barrel, resulting in a $185,000 decrease in revenue. Pipeline and Other Pipeline and other revenue increased $581,000 during 1997 as compared to 1996, primarily due to the receipt of insurance proceeds during 1997, which reimbursed a portion of expense incurred in a prior period to settle certain litigation. Production Operating Expense Production operating expense decreased $165,000 during 1997 as compared to 1996. The decrease is the result of lower production taxes due to the decrease in production discussed above. General and administrative Expense General and administrative expense increased $873,000 during 1997 as compared to 1996, primarily as a result of increased performance based compensation during 1997. Interest Expense Interest expense decreased $272,000 in 1997 as compared to 1996, primarily as a result of a lower average debt balance during 1997. Depreciation, Depletion and Amortization Expense Depreciation, depletion and amortization expense decreased $641,000 during 1997 as compared with 1996. This decrease is due to a lower depletion rate resulting from the decreased production discussed above. Other Other expense for 1996 is comprised of numerous miscellaneous items, none of which is individually significant. ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK HCRC's primary market risks relate to changes in interest rates and in the prices received from sales of oil and natural gas. HCRC's primary risk management strategy is to partially mitigate the risk of adverse changes in its cash flows caused by increases in interest rates on its variable rate debt, and decreases in oil and natural gas prices, by entering into derivative financial and commodity instruments, including swaps, collars and participating commodity hedges. By hedging only a portion of its market risk exposures, HCRC is able to participate in the increased earnings and cash flows associated with decreases in interest rates and increases in oil and natural gas prices; however, it is exposed to risk on the unhedged portion of its variable rate debt and oil and natural gas production. Historically, HCRC has attempted to hedge the exposure related to its variable rate debt and its forecasted oil and natural gas production in amounts which it believes are prudent based on the prices of available derivatives and, in the case of production hedges, the Company's deliverable volumes. HCRC attempts to manage the exposure to adverse changes in the fair value of its fixed rate debt agreements by issuing fixed rate debt only when business conditions and market conditions are favorable. HCRC does not use or hold derivative instruments for trading purposes nor does it use derivative instruments with leveraged features. HCRC's derivative instruments are designated and effective as hedges against its identified risks, and do not of themselves expose HCRC to market risk because any adverse change in the cash flows associated with the derivative instrument is accompanied by an offsetting change in the cash flows of the hedged transaction. Notes 1 and 4 to the financial statements provide further disclosure with respect to derivatives and related accounting policies. All derivative activity is carried out by personnel who have appropriate skills, experience and supervision. The personnel involved in derivative activity must follow prescribed trading limits and parameters that are regularly reviewed by the Board of Directors and by senior management. HCRC uses only well-known, conventional derivative instruments and attempts to manage its credit risk by entering into financial contracts with reputable financial institutions. Following are disclosures regarding HCRC's market risk sensitive instruments by major category. Investors and other users are cautioned to avoid simplistic use of these disclosures. Users should realize that the actual impact of future interest rate and commodity price movements will likely differ from the amounts disclosed below due to ongoing changes in risk exposure levels and concurrent adjustments to hedging positions. It is not possible to accurately predict future movements in interest rates and oil and natural gas prices. Interest Rate Risks (non trading) - HCRC uses both fixed and variable rate debt to partially finance operations and capital expenditures. As of December 31, 1998, HCRC's debt consists of $25.5 million in borrowings under its Credit Agreement which bear interest at a variable rate, and $25 million in borrowings under its 10.32% Senior Subordinated Notes which bear interest at a fixed rate. HCRC hedges a portion of the risk associated with its variable rate debt through derivative instruments, which consist of interest rate swaps and collars. Under the swap contracts, HCRC makes interest payments on its Credit Agreement as scheduled and receives or makes payments based on the differential between the fixed rate of the swap and a floating rate plus a defined differential. These instruments reduce HCRC's exposure to increases in interest rates on the hedged portion of its debt by enabling it to effectively pay a fixed rate of interest or a rate which only fluctuates within a predetermined ceiling and floor. A hypothetical increase in interest rates of two percentage points would cause a loss in income and cash flows of $510,000 during 1999, assuming that outstanding borrowings under the Credit Agreement remain at current levels. This loss in income and cash flows would be offset by a $201,500 increase in income and cash flows associated with the interest rate swap and collar agreements that are in effect for 1999. A hypothetical decrease in interest rates of two percentage points would cause an increase in the fair value of $2,282,000 in HCRC's Senior Subordinated Notes from their fair value at December 31, 1998. Commodity Price Risk (non trading) - HCRC hedges a portion of the price risk associated with the sale of its oil and natural gas production through the use of derivative commodity instruments, which consist of swaps, collars and participating hedges. These instruments reduce HCRC's exposure to decreases in oil and natural gas prices on the hedged portion of its production by enabling it to effectively receive a fixed price on its oil and natural gas sales or a price that only fluctuates between a predetermined floor and ceiling. HCRC's participating hedges also enable HCRC to receive 25% of any increase in prices over the fixed prices specified in the contracts. As of March 24, 1999, HCRC had entered into derivative commodity hedges covering an aggregate of 23,000 barrels of oil and 11,787,000 mcf of gas that extend through 2002. Under the these contracts, HCRC sells its oil and natural gas production at spot market prices and receives or makes payments based on the differential between the contract price and a floating price which is based on spot market indices. The amount received or paid upon settlement of these contracts is recognized as oil or natural gas revenues at the time the hedged volumes are sold. A hypothetical decrease in oil and natural gas prices of 10% from the prices in effect as of December 31, 1998 would cause a loss in income and cash flows of $2,890,000 during 1999, assuming that oil and gas production remain at 1998 levels. This loss in income and cash flows would be offset by a $705,000 increase in income and cash flows associated with the oil and natural gas derivative contracts that are in effect for 1999. ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page FINANCIAL STATEMENTS: Independent Auditors' Report 31 Consolidated Balance Sheets at December 31, 1998 and 1997 32-33 Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996 34 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1998, 1997 and 1996 35 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 36 Notes to Consolidated Financial Statements 37-49 SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) 50-53
INDEPENDENT AUDITORS' REPORT To the Stockholders of Hallwood Consolidated Resources Corporation: We have audited the consolidated financial statements of Hallwood Consolidated Resources Corporation as of December 31, 1998 and 1997 and for each of the three years in the period ended December 31, 1998, listed in the accompanying index at Item 8. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Hallwood Consolidated Resources Corporation at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Denver, Colorado March 24, 1999
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands except shares) December 31, 1998 1997 CURRENT ASSETS Cash and cash equivalents $ 551 $ 4,492 Accrued oil and gas revenue 3,053 4,266 Due from affiliates 4,246 2,418 Prepaid and other assets 285 115 Current assets of affiliates 4,431 3,854 --------- --------- Total current assets 12,566 15,145 -------- -------- PROPERTY, PLANT AND EQUIPMENT, at cost Oil and gas properties (full cost method) Proved oil and gas properties 336,713 294,922 Unproved mineral interests - domestic 2,813 2,250 --------- --------- Total 339,526 297,172 Less - accumulated depreciation, depletion, amortization and impairment (252,204) (221,141) ------- ------- Net property, plant and equipment 87,322 76,031 -------- -------- OTHER ASSETS Deferred expenses 1,201 729 Deferred tax asset 450 Noncurrent assets of affiliate 78 16 ----------- ----------- Total other assets 1,279 1,195 --------- --------- TOTAL ASSETS $101,167 $ 92,371 ======= ======== (Continued on the following page)
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands except shares) December 31, 1998 1997 CURRENT LIABILITIES Accounts payable and accrued liabilities $ 3,886 $ 3,087 Current portion of long-term debt 4,781 Current portion of contract settlement obligation 1,039 Current liabilities of affiliates 9,595 6,881 --------- --------- Total current liabilities 18,262 11,007 -------- -------- NONCURRENT LIABILITIES Long-term debt 44,774 25,000 Long-term obligations of affiliates 8,482 7,589 Deferred liability 60 89 ---------- ---------- Total noncurrent liabilities 53,316 32,678 -------- -------- Total liabilities 71,578 43,685 -------- -------- COMMITMENTS AND CONTINGENCIES (NOTE 11) STOCKHOLDERS' EQUITY Common stock, par value $.01 per share; 10,000,000 shares authorized; 3,007,852 shares issued in 1998 and 2,986,812 shares issued in 1997 30 30 Additional paid-in capital 81,283 80,111 Accumulated deficit (47,860) (27,581) Treasury stock - 258,395 shares in 1998 and 259,278 shares in 1997 (3,864) (3,874) --------- --------- Stockholders' equity - net 29,589 48,686 --------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $101,167 $ 92,371 ======= ======== The accompanying notes are an integral part of the consolidated financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands except per share) For the Year Ended December 31, 1998 1997 1996 REVENUES: Gas revenue $ 20,142 $ 17,251 $ 16,446 Oil revenue 9,392 13,416 16,852 Pipeline and other 2,696 1,591 1,010 Interest 180 153 137 --------- --------- --------- 32,410 32,411 34,445 ------- ------- ------- EXPENSES: Production operating 11,642 10,218 10,383 General and administrative 4,451 4,884 4,011 Interest 4,160 2,258 2,530 Depreciation, depletion and amortization 11,463 8,605 9,246 Impairment of oil and gas properties 19,600 Litigation 1,087 Other 114 ----------- ----------- -------- 52,403 25,965 26,284 ------- ------- ------- INCOME (LOSS) BEFORE INCOME TAXES (19,993) 6,446 8,161 ------- -------- -------- PROVISION (BENEFIT) FOR INCOME TAXES: Current (164) 961 301 Deferred 450 (100) (350) -------- -------- -------- 286 861 (49) -------- -------- --------- NET INCOME (LOSS) $(20,279) $ 5,585 $ 8,210 ======= ======== ======== NET INCOME (LOSS) PER SHARE - BASIC $ (7.38) $ 2.05 $ 3.00 ========= ========= ========= NET INCOME (LOSS) PER SHARE - DILUTED $ (7.38) $ 1.97 $ 2.91 ========= ========= ========= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 2,747 2,719 2,733 ======== ======== ======== The accompanying notes are an integral part of the consolidated financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (In thousands) Additional Common Paid-in Accumulated Treasury Stock Capital Deficit Stock Total Balance, December 31, 1995 $ 30 $ 81,811 $(41,376) $ (3,830) $ 36,635 Repurchase and retirement of common stock (1,750) (1,750) Exercise of common stock options 10 10 Increase in treasury shares (44) (44) Net income 8,210 8,210 ------ ---------- -------- --------- -------- Balance, December 31, 1996 30 80,071 (33,166) (3,874) 43,061 Exercise of common stock options 61 61 Other (21) (21) Net income 5,585 5,585 ----- ---------- -------- ---------- -------- Balance, December 31, 1997 30 80,111 (27,581) (3,874) 48,686 Exercise of common stock options 140 140 Allocated value of common stock warrants 1,032 1,032 Decrease in treasury shares 10 10 Net loss (20,279) (20,279) ----- ---------- -------- ---------- -------- Balance, December 31, 1998 $ 30 $ 81,283 $(47,860) $ (3,864) $ 29,589 ===== ======= ======= ======= ======= The accompanying notes are an integral part of the consolidated financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) For the Year Ended December 31, 1998 1997 1996 OPERATING ACTIVITIES: Net income (loss) $ (20,279) $ 5,585 $ 8,210 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 11,463 8,605 9,246 Impairment of oil and gas properties 19,600 Amortization of deferred loan costs and debt discount 203 Deferred income tax (benefit) expense 450 (100) (350) Noncash interest expense 6 91 83 Recoupment of take-or-pay liability (29) (28) (110) Undistributed earnings of affiliates (5,040) (3,843) (5,173) Changes in operating assets and liabilities provided (used) cash net of noncash activity: Accrued oil and gas revenue 1,213 542 (2,134) Due from affiliates (1,498) (1,569) (1,071) Prepaid and other assets (286) 378 (382) Deferred expenses (472) (729) Accounts payable and accrued liabilities 799 814 (1,402) ---------- --------- -------- Net cash provided by operating activities 6,130 9,746 6,917 -------- -------- -------- INVESTING ACTIVITIES: Additions to oil and gas properties (28,182) (2,822) (2,182) Exploration and development costs incurred (9,383) (9,284) (7,578) Proceeds from oil and gas property sales 107 40 1,368 Distributions received from affiliates 2,792 1,144 1,144 Investment in Spraberry properties (6,338) ------------- ------------- --------- Net cash used in investing activities (34,666) (10,922) (13,586) -------- -------- -------- FINANCING ACTIVITIES: Proceeds from long-term debt 25,500 29,000 10,000 Payments of long-term debt (24,000) (2,000) Repurchase and retirement of common stock (1,750) Payments on contract settlement obligation (1,045) (118) Exercise of stock options 140 61 10 Other financing activities (21) 16 ------------- ---------- ---------- Net cash provided by financing activities 24,595 5,040 6,158 -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (3,941) 3,864 (511) CASH AND CASH EQUIVALENTS: BEGINNING OF YEAR 4,492 628 1,139 -------- -------- -------- END OF YEAR $ 551 $ 4,492 $ 628 ========= ======== ======== The accompanying notes are an integral part of the consolidated financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a Delaware corporation engaged in the development, production, and sale of oil and gas, and in the acquisition, exploration, development and operation of oil and gas properties. The Company's properties are primarily located in the Rocky Mountain, Mid-Continent, Greater Permian and Gulf Coast regions of the United States. The principal objective of the Company is to maximize shareholder value by increasing its reserves, production and cash flow through a balanced program of development and high potential exploration drilling, as well as selective acquisitions. Accounting Policies Consolidation HCRC accounts for its interest in affiliated oil and gas partnerships and limited liability companies using the proportionate consolidation method of accounting. The accompanying financial statements include the activities of HCRC and its pro rata share of the activities of Hallwood Energy Partners, L.P. ("HEP"). Property, Plant and Equipment The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized in a single cost center ("full cost pool") and are amortized over the productive life of the underlying proved reserves using the units of production method. Proceeds from property sales are generally credited to the full cost pool. Capitalized costs of oil and gas properties may not exceed an amount equal to the present value discounted at 10% of estimated future net revenues from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying year-end prices of oil and gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. During the second, third and fourth quarters of 1998, using oil and gas prices of $13.00 per barrel of oil and $1.90 per mcf of gas, $12.75 per barrel of oil and $1.80 per mcf of gas and $10.00 per barrel of oil and $1.85 per mcf of gas, respectively, HCRC recorded oil and gas property impairment expense totaling $19,600,000. The Company does not accrue costs for future site restoration, dismantlement and abandonment costs related to proved oil and gas properties because the Company estimates that such costs will be offset by the salvage value of the equipment sold upon abandonment of such properties. The Company's estimates are based upon its historical experience and upon review of current properties and restoration obligations. Unproved properties are withheld from the amortization base until such time as they are either developed or abandoned. These properties are evaluated periodically for impairment. Long-lived assets other than oil and gas properties which are evaluated for impairment as described above, are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. To date, the Company has not recognized any impairment losses on long-lived assets other than oil and gas properties. Derivatives As of March 24, 1999, HCRC was a party to 18 financial contracts to hedge the price of its oil and natural gas. The purpose of the hedges is to provide protection against price decreases and to provide a measure of stability in the volatile environment of oil and natural gas spot pricing. The amounts received or paid upon settlement of these contracts are recognized as increases or decreases in oil or gas revenue at the time the hedged volumes are sold. As of March 24, 1999, HCRC was a party to six financial contracts to hedge the interest payments under its Credit Agreement. The purpose of the hedges is to protect against the variability of the cash flows under its Credit Agreement which has a floating interest rate. The amounts received or paid upon settlement of these transactions are recognized as interest expense at the time the interest payments are due. Gas Balancing HCRC uses the sales method to account for gas balancing. Under this method, HCRC recognizes revenue on all of its sales of production and any over-production or under-production is recovered or repaid at a future date. As of December 31, 1998, HCRC had a net over-produced position of 347,000 mcf ($642,000 valued at year-end prices). Current imbalances can be made up with production from existing wells or from wells which will be drilled as offsets to current producing wells. HCRC's oil and gas reserves as of December 31, 1998 have been reduced by 347,000 mcf in order to reflect HCRC's gas balancing position. Stock Split During July 1997, the stockholders of HCRC approved an increase in the number of authorized shares of its Common Stock from 2,000,000 shares to 10,000,000 shares. HCRC also declared a three-for-one split of its outstanding Common Stock. The stock split was effected by issuing, as a stock dividend, two additional shares of Common Stock for each share outstanding. The stock dividend was paid on August 11, 1997 to shareholders of record on August 4, 1997. All share and per share information has been restated to reflect the three-for-one stock split. Cash and Cash Equivalents All highly liquid investments purchased with an original maturity of three months or less are considered to be cash equivalents. Use of Estimates The preparation of the financial statements for the Company in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Computation of Net Income (Loss) Per Share Basic income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares. Diluted income per share includes the potential dilution that could occur upon exercise of the options to acquire common stock described in Note 10, computed using the treasury stock method which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period). The warrants described in Note 6 have been ignored in the computation of diluted net income (loss) per share in all periods and the stock options have been ignored in the computation of diluted loss per share in 1998 because their inclusion would be antidilutive. All share and per share information has been restated to reflect the three-for-one stock split. The following table reconciles the number of shares outstanding used in the calculation of basic and diluted income (loss) per share.
Income (Loss) Shares Per Share (In thousands except per Share) For the Year Ended December 31, 1998 Net loss per share - basic $(20,279) 2,747 $(7.38) ------ ------ ===== Net loss per share - diluted $(20,279) 2,747 $(7.38) ======= ====== ===== For the Year Ended December 31, 1997 Net income per share - basic $ 5,585 2,719 $2.05 ==== Effect of Options 116 ---------- ------- Net income per share - diluted $ 5,585 2,835 $1.97 ====== ===== ==== For the Year Ended December 31, 1996 Net income per share - basic $ 8,210 2,733 $3.00 ==== Effect of Options 87 ---------- -------- Net income per share - diluted $ 8,210 2,820 $2.91 ====== ===== ====
Treasury Stock At December 31, 1998 and 1997, the Company owns approximately 19% of the outstanding units of HEP, which owns approximately 46% of the Company's shares; consequently, the Company has an interest in 258,395 and 259,278 of its own shares at December 31, 1998 and 1997, respectively. These shares are treated as treasury stock in the accompanying financial statements. Significant Customers Both oil and natural gas are purchased by refineries, major oil companies, public utilities, industrial customers and other users and processors of petroleum products. HCRC is not confined to, nor dependent upon, any one purchaser or small group of purchasers. Accordingly, the loss of a single purchaser, or a few purchasers, would not materially affect HCRC's business because there are numerous other purchasers in the areas in which HCRC sells it production. However, for the years ended December 31, 1998, 1997 and 1996, purchases by the following companies exceeded 10% of the total oil and gas revenues of the Company: 1998 1997 1996 ---- ---- ---- El Paso Field Services 17% 17% 11% Williams Gas Marketing 13% 13% Koch Oil Company 12% 23% Conoco Inc. 12% 13% Scurlock Permian Corporation 14% Environmental Concerns The Company is continually taking actions it believes are necessary in its operations to ensure conformity with applicable federal, state and local environmental regulations. As of December 31, 1998, the Company has not been fined or cited for any environmental violations which would have a material adverse effect upon capital expenditures, earnings, cash flows or the competitive position of the Company in the oil and gas industry. Recently Issued Accounting Pronouncements In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting and display of comprehensive income and its components (revenues, expenses, gains, and losses) in a full set of general-purpose financial statements. SFAS 130 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. Reclassification of financial statements for earlier periods provided for comparative purposes is required. The Company adopted SFAS 130 on January 1, 1998. The Company does not have any items of other comprehensive income for the years ended December 31, 1998, 1997 and 1996. Therefore, total comprehensive income (loss) is the same as net income (loss) for those years. In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards for reporting selected information about operating segments and related disclosures about products and services, geographic areas, and major customers. SFAS 131 requires that an entity report financial and descriptive information about its operating segments which are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. HCRC adopted FAS 131 in 1998. The Company engages in the development, production and sale of oil and gas, and the acquisition, exploration, development and operation of oil and gas properties in the continental United States. These activities exhibit similar economic characteristics and involve the same products, production processes, class of customers, and methods of distribution. Management of the Company evaluates its performance as a whole rather than by product or geographically. As a result, HCRC's operations consist of one reportable segment. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities. SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The accounting for changes in the fair value of a derivative (gains and losses) depends on the intended use of the derivative and the resulting designation. The Company is required to adopt SFAS 133 on January 1, 2000. The Company has not completed the process of evaluating the impact that will result from adopting SFAS 133. Reclassifications Certain reclassifications have been made to prior years' amounts to conform to the classifications used in the current year. NOTE 2 - OIL AND GAS PROPERTIES The following table summarizes cost information related to the Company's oil and gas activities, including its pro rata share of HEP's oil and gas activities. The Company has no material long-term supply agreements, and all reserves are located within the United States.
For the Year Ended December 31, 1998 1997 1996 (In thousands) Property acquisition costs $32,172 $ 3,350 $ 2,830 Development costs 6,904 6,531 8,617 Exploration costs 6,552 8,064 2,206 ------- ------- ------- Total $45,628 $17,945 $13,653 ====== ====== ======
Depreciation, depletion, amortization and property impairment related to proved oil and gas properties per equivalent mcf of production for the years ended December 31, 1998, 1997 and 1996 was $2.09, $.70 and $.70, respectively. At December 31, unproved properties consist of the following: 1998 1997 ---- ---- (In thousands) Texas $2,004 $ 935 North Dakota 499 314 California 447 Other 310 554 ------- ------- $2,813 $2,250 ===== ===== NOTE 3 - PRINCIPAL ACQUISITIONS AND SALES As a result of the arbitration discussed in Note 14, HCRC completed an $8,200,000 acquisition of properties located primarily in Texas during October 1998. The acquisition included interests in 570 wells, numerous proven and unproven drilling locations, exploration acreage and 3-D seismic data. In July 1996, HCRC and its affiliate, HEP, acquired interests in 38 wells located primarily in LaPlata County, Colorado. An unaffiliated large East Coast financial institution formed an entity to utilize the tax credits generated from the wells. The project was financed by an affiliate of Enron Corp. through a volumetric production payment. During May 1998, a limited liability company owned equally by HCRC and HEP purchased the volumetric production payment from the affiliate of Enron Corp. HCRC funded its $17,257,000 share of the acquisition price from operating cash flow and borrowings under its Credit Agreement. During 1997, HCRC had no individually significant property acquisitions or sales. NOTE 4 - DERIVATIVES As part of its risk management strategy, HCRC enters into financial contracts to hedge the price of its oil and natural gas. HCRC does not use these hedges for trading purposes, but rather for the purpose of providing protection against price decreases and to provide a measure of stability in the volatile environment of oil and natural gas spot pricing. The amounts received or paid upon settlement of these contracts is recognized as oil or gas revenue at the time the hedged volumes are sold. The financial contracts used by HCRC to hedge the price of its oil and natural gas production are swaps, collars and participating hedges. Under the swap contracts, HCRC sells its oil and gas production at spot market prices and receives or makes payments based on the differential between the contract price and a floating price which is based on spot market indices. As of March 24, 1999, HCRC was a party to 18 financial contracts with three different counterparties. The following table provides a summary of HCRC's financial contracts: Oil Quantity of Production Contract Period Hedged Floor Price (bbls) (per bbl) 1996 219,000 $18.47 1997 262,000 17.88 1998 82,000 14.07 1999 23,000 14.88 All of the oil volumes hedged in 1999 are subject to participating hedges whereby HCRC will receive the contract price if the posted futures price is lower than the contract price, and will receive the contract price plus 25% of the difference between the contract price and the posted futures price if the posted futures price is greater than the contract price. All of the volumes hedged in 1999 are subject to a collar agreement whereby HCRC will receive the contract price if the spot price is lower than the contract price, the cap price if the spot price is higher than the cap price, and the spot price if that price is between the contract price and the cap price. The cap prices range from $16.50 to $18.35 per barrel. Gas Quantity of Production Contract Period Hedged Floor Price (mcf) (per mcf) 1996 2,429,000 $1.77 1997 2,413,000 1.89 1998 3,545,000 1.96 1999 4,237,000 1.95 2000 2,923,000 1.95 2001 2,503,000 1.92 2002 2,124,000 1.98 In the event of nonperformance by the counterparties to the financial contracts, HCRC is exposed to credit loss, but has no off-balance sheet risk of accounting loss. The Company anticipates that the counterparties will be able to satisfy their obligations under the contracts because the counterparties consist of well-established banking and financial institutions which have been in operation for many years. Certain of HCRC's hedges are secured by the lien on HCRC's oil and gas properties which also secures HCRC's Credit Agreement described in Note 6. NOTE 5 - RELATED PARTY TRANSACTIONS Hallwood Petroleum, Inc. ("HPI"), an affiliated entity, manages and operates certain oil and gas properties on behalf of other joint interest owners and the Company. In such capacity, HPI pays all costs and expenses of operations and distributes all revenues associated with such properties. The Company had receivables from HPI of $4,246,000 and $2,418,000 and as of December 31, 1998 and 1997, respectively. The amounts consist primarily of revenues net of operating costs and expenses. The Company reimburses HPI for actual costs and expenses, which include office rent, salaries and associated overhead for personnel of HPI engaged in the acquisition and evaluation of oil and gas properties (technical expenditures which are capitalized as costs of oil and gas properties) and general and administrative and lease operating expenditures necessary to conduct the business of the Company (nontechnical expenditures which are expensed as general and administrative or production operating expense). Reimbursements during 1998, 1997 and 1996 were as follows (in thousands): Technical Nontechnical Expenditures Expenditures 1998 $984 $1,392 1997 856 1,225 1996 823 1,293 Included in the nontechnical allocation from HPI attributable to the Company's direct interest is approximately $241,000 during the years ended December 31, 1998 and 1997 and $115,000 during the year ended December 31, 1996 of consulting fees under a contract with The Hallwood Group Incorporated ("Hallwood"), an affiliated company. Also included in the nontechnical allocation is $246,000, $232,000 and $234,000 in 1998, 1997 and 1996, respectively, representing costs incurred by Hallwood and its affiliates on behalf of the Company. During the third quarter of 1994, HPI entered into a consulting agreement with its Chairman of the Board to provide advisory services regarding the international activities of its affiliates. The amount of consulting fees allocated to the Company under this agreement was $125,000 in 1996. The agreement terminated effective December 31, 1996. NOTE 6 - DEBT On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes ("Subordinated Notes") due December 23, 2007 to The Prudential Insurance Company of America ("Prudential"). HCRC also sold Warrants to Prudential to purchase 98,599 shares of Common Stock at an exercise price of $28.99 per share. The Subordinated Notes bear interest at the rate of 10.32% per annum on the unpaid balance, payable quarterly. Annual principal payments of $5,000,000 are due on each of December 23, 2003 through December 23, 2007. The proceeds from the Subordinated Notes were allocated to the Subordinated Notes and to the Warrants based upon the relative fair values of the Subordinated Notes without the Warrants and of the Warrants themselves at the time of issuance. The allocated value of the Warrants of $1,032,000 was recorded as paid-in-capital. The discount on the Subordinated Notes is being amortized over the term of the Subordinated Notes using the interest method of amortization. At December 31, 1998, HCRC was not in compliance with one of the debt covenants in its Subordinated Note agreement which requires HCRC to maintain a minimum level of consolidated net worth. This also resulted in noncompliance with a covenant under HCRC's Credit Agreement. HCRC received waivers of compliance with this covenant as of December 31, 1998 from the Subordinated Note holder and from HCRC's lenders under its Credit Agreement. The Subordinated Note agreement was amended to reduce the required level of net worth. As a result, the obligations under these agreements have been classified as noncurrent liabilities as of December 31, 1998. During 1997, the Company and its banks amended their Credit Agreement to extend the term date of the line of credit to May 31, 1999. The banks are Morgan Guaranty Trust Company, First Union National Bank and NationsBank of Texas. Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. As of December 31, 1998, the Company had amounts outstanding of $25,500,000. HCRC's unused borrowing base totaled $1,000,000 at March 24, 1999. Borrowings against the Credit Agreement bear interest, at the option of the Company, at either (i) the banks' Certificate of Deposit rate plus from 1.375% to 1.875%, (ii) the Euro-Dollar rate plus from 1.25% to 1.75% or (iii) the higher of the prime rate of Morgan Guaranty Trust or the sum of one-half of 1% and the Federal funds rate, plus .75%. The applicable interest rate was 6.75% at December 31, 1998. Interest is payable at least quarterly, and quarterly principal payments of $1,594,000 commence May 31, 1999. The Credit Agreement is secured by a first lien on approximately 80% in value of the Company's oil and gas properties. The borrowing base for the Credit Agreement is redetermined semiannually, and the next redetermination is scheduled for the second quarter of 1999. HCRC anticipates that, because of low oil and gas prices, its lenders will reduce the borrowing base and that HCRC will be required to make a principal payment on its debt. Any required principal payment will reduce the amount available for HCRC's capital budget. At December 31, 1998, HCRC's debt maturity schedule is as follows. (In thousands) 1999 $ 4,781 2000 6,375 2001 6,375 2002 6,375 2003 6,594 Thereafter 19,055 ------ Total $49,555 As part of its risk management strategy, HCRC enters into contracts to hedge its interest rate payments related to a portion of its outstanding borrowings under its Credit Agreement. HCRC does not use the hedges for trading purposes, but rather to protect against the volatility of the cash flows under its Credit Agreement, which has a floating interest rate. The amounts received or paid upon settlement of these transactions are recognized as interest expense at the time the interest payments are due. Approximately one third of the debt hedged in 1998 was subject to a collar agreement with a floor rate of 7.55% and a ceiling rate of 9.85%. All other contracts are interest rate swaps with fixed rates. As of March 24, 1999, HCRC was a party to six contracts with three different counterparties. The following table provides a summary of HCRC's financial contracts. Amount of Contract Period Debt Hedged Floor Rate 1996 $ 7,000,000 7.00% 1997 10,000,000 6.84% 1998 10,000,000 7.00% 1999 13,000,000 5.70% 2000 15,000,000 5.65% 2001 12,000,000 5.23% 2002 12,500,000 5.23% 2003 12,500,000 5.23% 2004 2,000,000 5.23% NOTE 7 - CONTRACT SETTLEMENT OBLIGATION In March 1989, the Company received $2,877,000 as a recoupable take-or-pay settlement on a contract with a gas pipeline. The settlement was recoupable monthly in cash or gas volumes, from April 1992 through March 1996 with a balloon payment due during the first quarter of 1998. A liability was recorded equal to the present value of the settlement discounted at 10.68%, HCRC's estimated borrowing rate at the time of the settlement. At December 31, 1997, the current portion of contract settlement balance consisted of a payment of $1,045,000 net of unaccreted discount of $6,000, which was paid during February 1998. NOTE 8 - STATEMENT OF CASH FLOWS Cash paid for interest during 1998, 1997 and 1996 was $3,292,000, $1,434,000 and $1,374,000, respectively. A net cash refund of income tax expense of $336,000 was received during 1998. Cash paid for income taxes during 1997 and 1996 was $1,416,000 and $185,000, respectively. NOTE 9 - INCOME TAXES The following is a summary of the income tax provision (benefit):
For the Year Ended December 31, 1998 1997 1996 (In thousands) State $ 13 $ 369 $ 236 Federal - Current (177) 592 65 Deferred 450 (100) (350) ---- ---- ---- Total $ 286 $ 861 $ (49) ==== ==== =====
Reconciliations of the expected tax at the statutory tax rate to the effective tax are as follows:
For the Year Ended December 31, 1998 1997 1996 (In thousands) Expected tax expense (benefit) at the statutory rate $(6,797) $ 2,192 $ 2,775 State taxes net of federal benefit 8 243 156 Change in valuation allowance 6,859 (1,444) (3,739) Other 216 (130) 759 ------ ------ ------ Effective tax expense (benefit) $ 286 $ 861 $ (49) ====== ====== =======
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amount used for income tax purposes. The tax effects of significant items comprising the Company's deferred tax assets and liabilities as of December 31, 1998 and 1997 are as follows: 1998 1997 ---- ---- Deferred tax assets: Net operating loss carryforward $ 5,187 $ 2,835 Capital loss carryforward 1,763 1,889 Temporary differences between book and tax basis of property 4,110 461 Minimum tax credit carryforward 534 --------- Total 11,594 5,185 Valuation allowance (11,594) (4,735) ------ ------ Net deferred tax asset $ -0- $ 450 ========== ======= The Company's net operating loss carryforwards expire between 2008 and 2013. NOTE 10 - EMPLOYEE INCENTIVE PLANS Every year beginning in 1992, the Company's Board of Directors has adopted an incentive plan. Each year the Board of Directors determines the percentage of HCRC's interest in the cash flow from certain wells drilled, recompleted or enhanced during the year allocated to the incentive plan for that year. The specified percentage was 2.75% for 1998 and 2.4% for 1997 and 1996. The specified percentage of cash flow is allocated among certain key employees who are participants in the plan for that year. Each award under the plan (with regard to domestic properties) represents the right to receive for five years a portion of the specified share of the cash flow attributable to qualifying wells included in the plan for that year. In the sixth year after the award, the participants are each paid a share of an amount equal to a specified percentage (80% for 1998, 1997 and 1996) of the remaining net present value of the qualifying wells, and the award for that year terminates. The expenses attributable to the plans were $123,000 in 1998, $400,000 in 1997 and $119,000 in 1996 and are included in general and administrative expense in the accompanying financial statements. During 1995, the Company adopted a stock option plan covering 159,000 shares of Common Stock and granted options for all of the shares under the plan. The options were granted effective July 1, 1995 at an exercise price of $6.67 per share, which was equal to the fair market value of the Common Stock on the day preceding the date of grant. The options expire on July 1, 2005, unless sooner terminated pursuant to the provisions of the plan. During the years ended December 31, 1998, 1997 and 1996, options to purchase 21,040, 9,270 and 1,500 shares, respectively, were exercised. During the second quarter of 1997, the Company adopted a stock option plan covering 159,000 shares of Common Stock and granted options for all of the shares under the plan. The terms of this plan are generally consistent with the terms of the Company's existing 1995 Stock Option Plan. The options were granted effective June 17, 1997 at an exercise price of $20.33 per share, which was equal to the fair market value of the Common Stock on the date of grant. The options expire on June 17, 2007, unless sooner terminated pursuant to the provisions of the plan. The options are exercisable one-third on June 17, 1997, an additional one-third June 17, 1998, and the remaining one-third on June 17, 1999. In addition, the Plan provides that vesting of the options may accelerate under certain conditions. On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock under its 1997 Stock Option Plan at an exercise price of $15.75 which was equal to the fair market value of the Common Stock on the date of grant. One-third of the options vest immediately, and the remainder vest one-half on the first anniversary of the date of grant and one-half on the second anniversary of the date of grant. On May 5, 1998, HCRC also granted options to purchase 9,540 shares of Common Stock at an exercise price of $15.75 per share which was equal to the fair market value of the Common Stock on the date of grant. These options were not granted pursuant to a previously existing plan, but are subject to terms and conditions identical to those in HCRC's 1995 Stock Option Plan. One-third of the options vest immediately, and the remainder vest one-half on the first anniversary of the date of grant and one-half on the second anniversary of the date of grant. A summary of options to purchase HCRC's common stock and the changes therein for the years ended December 31, 1998, 1997 and 1996 follows:
1998 1997 1996 ---- ---- ---- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Outstanding at beginning of year 307,230 $13.74 157,500 $ 6.67 159,000 $ 6.67 Granted 19,080 15.75 159,000 20.33 Expired (9,540) 20.33 Exercised (21,040) 6.67 (9,270) 6.67 (1,500) 6.67 -------- ------ -------- ------ -------- ----- Outstanding at end of year 295,730 $10.54 307,230 $13.74 157,500 $ 6.67 ======= ===== ======= ===== ======= ===== Options exercisable at year end 233,190 $19.40 201,230 $10.26 104,500 $ 6.67 ======= ===== ======= ===== ======= =====
The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Accordingly, no compensation cost has been recognized for options granted by the Company. Had compensation expense for the options granted been determined based on the fair value at the grant dates, consistent with the provisions of SFAS 123, HCRC's net income (loss) and net income (loss) per share would have been changed to the pro forma amounts indicated below:
1998 1997 1996 ---- ---- ---- Net income (loss): as reported $(20,279,000) $5,585,000 $8,210,000 pro forma (20,789,000) 4,627,000 8,025,000 Net income (loss) per share - basic: as reported $(7.38) $2.05 $3.00 pro forma (7.57) 1.70 2.94 Net income (loss) per share - diluted: as reported $(7.38) $1.97 $2.91 pro forma (7.57) 1.63 2.85
The fair value of the options for disclosure purposes was estimated on the date of the grant using the Black-Scholes Model with the following assumptions:
1995 Options 1997 Options 1998 Options ------------ ------------ ------------ Expected dividend yield 0% 0% 0% Expected price volatility 40% 33% 29% Risk-free interest rate 6.2% 6.35% 6.4% Expected life of options 10 years 6 years 10 years
NOTE 11 - COMMITMENTS The Company is a guarantor of 40% of the obligation under the Denver, Colorado office leases which are in the name of HPI. HEP is guarantor of the remaining 60% of the obligation. HPI leases office facilities under an operating lease which expires in June 1999 for approximately $600,000 per year. During February 1999, HPI entered into another lease, for approximately $600,000 per year. The new lease commences upon occupancy, which is expected to be in June or July 1999, and terminates in seven and one-half years. NOTE 12 - ODD LOT REPURCHASE The Company made an offer to repurchase odd lot holdings of 99 or fewer shares from its stockholders of record as of November 30, 1995. The offer was initially for the period from November 30, 1995 through January 5, 1996 and was subsequently extended through January 26, 1996. The Company repurchased a total of 296,607 shares through the January 26, 1996 closing date. The repurchase price was $8.03 per share. On April 1, 1996, HCRC made another offer to purchase holdings of 99 or fewer shares from its stockholders of record as of March 25, 1996. The offer was for the period from April 1, 1996 through May 3, 1996. The Company repurchased a total of 77,790 shares at a purchase price of $11.33 per share. HCRC resold 38,895 of these shares to HEP at the price paid by HCRC for such shares. NOTE 13 - INVESTMENT IN AFFILIATED ENTITIES HCRC accounts for its 19% investment in HEP using the pro rata method of accounting. The following presents summarized financial information for HEP as of and for the years ended December 31, 1998, 1997 and 1996. HEP 1998 1997 1996 --- ---- ---- ---- (In thousands) Current assets $ 23,518 $ 22,142 $ 20,380 Noncurrent assets 115,573 109,461 102,412 Current liabilities 32,240 23,115 21,735 Noncurrent liabilities 41,431 36,166 33,506 Minority interest 2,788 3,258 3,336 Revenue 43,586 45,103 51,066 Net income (loss) (13,895) 12,803 15,726 No other individual entity in which HCRC owns an interest comprises in excess of 10% of the revenues, net income (loss) or assets of HCRC. NOTE 14 - ARBITRATION In connection with the Demand for Arbitration filed by Arcadia Exploration and Production Company ("Arcadia") with the American Arbitration Association against Hallwood Consolidated Resources Corporation, Hallwood Energy Partners, L.P., E.M. Nominee Partnership Company and Hallwood Consolidated Partners, L.P. (collectively referred to as "Hallwood"), the arbitrators ruled that the original agreement entered into in August 1997 to purchase oil and gas properties should proceed, with a reduction in the total purchase price of approximately $2,500,000 for title defects. The arbitrators also ruled that Arcadia was not entitled to enforce its claim that Hallwood was required to purchase an additional $8,000,000 in properties and denied Arcadia's claim for attorneys fees. The arbitrators granted Arcadia prejudgment interest on the adjusted purchase price, but an issue exists between Hallwood and Arcadia as to the proper calculation of the limitation which the panel placed on the amount of prejudgment interest. The parties plan to ask the arbitrators to rule on this issue. The Company has accrued $452,000 in its financial statements as of December 31, 1998 in connection with this dispute. In October 1998, HCRC and its affiliate, HEP, closed the acquisition of oil and gas properties from Arcadia pursuant to the ruling, which included interests in approximately 570 wells, numerous proven and unproven drilling locations, exploration acreage, and 3-D seismic data. HCRC's share of the purchase price was $8,200,000. NOTE 15 - LEGAL PROCEEDINGS On April 23, 1992, a lawsuit was filed in the Chancery Court for New Castle County, Delaware, styled Tappe v. Hallwood Consolidated Resources Corporation, Hallwood Consolidated Partners, L. P., Hallwood Oil and Gas, Inc., Hallwood Energy Partners, L. P., and Hallwood Petroleum, Inc. (C. A. No 12536). The lawsuit sought to rescind the conversion of Hallwood Consolidated Partners, L.P. ("HCP") into the Company ("Conversion") and to recover damages in unspecified amounts. In January 1999, the plaintiff and the defendants entered into a joint stipulation of dismissal, with prejudice as to the plaintiff only. The court approved the dismissal. The Company is involved in other legal proceedings and claims which have arisen in the ordinary course of its business and have not been finally adjudicated. The Company believes that its liability, if any, as a result of such proceedings and claims will not materially affect its financial condition or operations. NOTE 16 - ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, "Disclosures about Fair Value of Financial Instruments." The estimated fair value amounts have been determined by the Company, using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts. December 31, 1998 Carrying Estimated Fair Amount Value (In thousands) Assets (Liabilities): Oil and gas hedge contracts $ -0- $ 1,921 Interest rate hedge contracts -0- (404) Long-term debt (49,555) (47,659) The estimated fair value of the oil and gas hedge contracts is determined by multiplying the difference between contract termination prices for oil and gas and the hedge contract price by the quantities under contract. This amount has been discounted using an interest rate that could be available to the Company. The estimated fair value of the interest rate hedge contracts is computed by the difference between the quoted contract termination interest rate and the contract interest rate by the amounts under contract. This amount has been discounted using an interest rate that could have been available to the Company. The estimated fair value of long-term debt is computed using interest rates that could be available to the Company for similar instruments with similar terms. The fair value estimates presented herein are based on pertinent information available to management as of December 31, 1998. Although management is not aware of any factors that would significantly affect the estimated fair value amounts, such amounts have not been comprehensively revalued for purposes of these financial statements since that date, and current estimates of fair value may differ significantly from the amounts presented herein. HALLWOOD CONSOLIDATED RESOURCES CORPORATION SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited) The following reserve quantity and future net cash flow information for the Company represents proved reserves which are located in the United States. The reserve estimates presented have been prepared by in-house petroleum engineers, and a majority of these reserves has been reviewed by independent petroleum engineers. The determination of oil and gas reserves is based on estimates which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available. The standardized measure of discounted future net cash flows provides a comparison of the Company's proved oil and gas reserves from year to year. No consideration has been given to future income taxes as of December 31, 1998 because the tax basis of HCRC's oil and gas properties and net operating loss carryforwards exceed future net cash flows. Under the guidelines set forth by the Securities and Exchange Commission, the calculation is performed using year end prices. The oil and gas prices used at December 31, 1998, 1997 and 1996 were $10.00 per bbl and $1.85 per mcf, $16.77 per bbl and $2.20 per mcf and $23.96 per bbl and $3.75 per mcf, respectively, for the Company, including its interest in HEP. Future production costs are based on year end costs and include severance taxes. The present value of future cash inflows is based on a 10% discount rate. The reserve calculations using these December 31, 1998 prices result in 4 million bbls of oil, 87 billion cubic feet of gas and a standardized measure of $84,000,000. This standardized measure is not necessarily representative of the market value of the Company's properties. HCRC's standardized measure of future net cash flows has been increased by $2,717,000 at December 31, 1998 for the effect of its hedge contracts. This amount represents the difference between year end oil and gas prices and the hedge contract prices multiplied by the quantities under contract, discounted at 10%.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION RESERVE QUANTITIES (Unaudited) (In thousands) Gas Oil (Mcf) (Bbls) Proved Reserves: Balance, December 31, 1995 53,672 7,645 Extensions and discoveries 1,947 491 Revisions of previous estimates 7,701 (28) Sales of reserves in place (1,627) (160) Purchases of reserves in place 11,488 70 Production (8,280) (837) ------- ------- Balance, December 31, 1996 64,901 7,181 Extensions and discoveries 2,894 562 Revisions of previous estimates 15,261 (1,672) Sales of reserves in place (163) (3) Purchases of reserves in place 645 168 Production (7,963) (711) ------- ------- Balance, December 31, 1997 75,575 5,525 Extensions and discoveries 1,363 490 Revisions of previous estimates (8,515) (1,858) Sales of reserves in place (297) (35) Purchases of reserves in place 29,436 627 Production (10,555) (716) ------- ------- Balance, December 31, 1998 87,007 4,033 ====== ===== Proved Developed Reserves: Balance, December 31, 1996 63,044 6,431 ====== ===== Balance, December 31, 1997 73,250 5,080 ====== ===== Balance, December 31, 1998 83,717 3,173 ====== =====
HALLWOOD CONSOLIDATED RESOURCES CORPORATION STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Unaudited) (In thousands) December 31, ----------------- 1998 1997 1996 ---- ---- ---- Future sales $215,000 $227,000 $413,000 Future production and development costs (94,000) (100,000) (158,000) Provision for income tax* (8,000) (30,000) ------------ -------- -------- Future cash flows 121,000 119,000 225,000 10% discount to present value (37,000) (31,000) (91,000) -------- -------- -------- Standardized measure of discounted future net cash flows $ 84,000 $ 88,000 $134,000 ======== ======== ======= *No consideration has been given to future income taxes as of December 31, 1998 since the tax basis of HCRC's oil and gas properties and net operating loss carryforwards exceed future net cash flows.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Unaudited) (In thousands) For the Year Ended December 31, 1998 1997 1996 Standardized measure of discounted future net cash flows at beginning of year $ 88,000 $134,000 $ 85,000 Sales of oil and gas produced, net of production costs (17,892) (20,449) (22,915) Net changes in prices and production costs (10,359) (71,933) 46,516 Extensions and discoveries net of future production and development costs 3,411 5,616 7,011 Changes in estimated future development costs (9,542) (6,480) (7,292) Development costs incurred 6,904 6,531 8,617 Revisions of previous quantity estimates (15,587) 4,688 10,802 Purchases of reserves in place 26,316 1,482 17,061 Sales of reserves in place (402) (162) (3,707) Accretion of discount 8,818 13,439 8,513 Net change in income taxes 5,825 16,206 (15,332) Changes in production rates and other (1,492) 5,062 (274) -------- -------- -------- Standardized measure of discounted future net cash flows at end of year $ 84,000 $ 88,000 $134,000 ======== ======== =======
ITEM 9 - DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. PART III ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Directors, Officers and Key Employees HCRC does not have any employees. Hallwood Petroleum, Inc. ("HPI"), an affiliate of HCRC, operates the properties and administers the day to day activities of HCRC and its affiliates. On March 24, 1999, HPI had 108 employees. Following are brief biographies of the directors, officers and key employees of HCRC and HPI. Anthony J. Gumbiner, 54, has served as a director of the HCRC since February 1992. He has also served as Chairman of the Board of Directors of The Hallwood Group Incorporated ("Hallwood Group"), a diversified holding company with real estate, textile products, hotel and energy operations, since 1981 and as Chief Executive Officer of Hallwood Group since April 1984. He has been Chairman of the Board since 1984 and Chief Executive Officer since 1987 of the general partner of HEP. Mr. Gumbiner has also served as Chairman of the Board of Directors and as a director of Hallwood Holdings S.A., a Luxembourg real estate investment company, since March 1984. He has been a director of Hallwood Realty Corporation ("Hallwood Realty"), which is the general partner of Hallwood Realty Partners, L.P., since November 1990. He is a Solicitor of the Supreme Court of Judicature of England. William L. Guzzetti, 55, has been President and a director of HCRC since May 1991 and of HPI since October 1989, and a director of HPI since August 1989. Mr. Guzzetti is also an Executive Vice President of Hallwood Group and in that capacity may devote a portion of his time to the activities of Hallwood Group, including the management of real estate investments, acquisitions and restructurings of entities controlled by Hallwood Group. He is a director and President of Hallwood Realty and in that capacity may devote a portion of his time to the activities of Hallwood Realty. Russell P. Meduna, 44, has served as Executive Vice President of HCRC since June 1992 and of HPI since October 1989. Mr. Meduna was Vice President of HPI from April 1989 to October 1989 and Manager of Operations from January 1989 to April 1989. He joined HPI in 1984 as Production Manager. Prior to joining HPI, he was employed by both major and independent oil companies. Mr. Meduna is a registered professional engineer in the States of Colorado and Texas. Cathleen M. Osborn, 46, has served as Secretary and General Counsel of HCRC since May 1992 and as Vice President since June 1992. She has been Vice President, Secretary and General Counsel of HPI since September 1986. She joined HPI in 1985 as senior staff attorney. Ms. Osborn is a member of the Colorado Bar Association. Thomas J. Jung, 50, has served as Vice President and Chief Financial Officer of Hallwood G.P., HCRC and HPI since May 1998. From January 1997 until April 1998, he was a Senior Financial Associate with Trinity Petroleum Management, and during that period, he also provided consulting services to other companies involved in the development, financing, management and monetization of tax credits for alternative energy projects. From 1994 to 1996, he was Chief Executive Officer of FAR Gas Acquisitions Corp. From 1986 to 1994, he was Vice President and Chief Financial Officer of NICOR Exploration & Production Company and Reliance Pipeline Company. Betty J. Dieter, 51, has been Vice President of HPI responsible for domestic operations since January 1995. Her previous positions with HPI have included Operations Manager, Rocky Mountain and Mid-Continent District Manager and Manager for Operations Accounting and Administration. She joined HPI in 1985, and has 26 years experience in accounting and operations, 19 of which are in the oil and gas industry. Ms. Dieter is a Certified Public Accountant. George Brinkworth, 57, has been Vice President-Exploration and International Division of HPI since August 1994. He became associated with HPI in 1987 when he was President of a joint venture program funded by HPI and two other domestic oil companies. Mr. Brinkworth has 34 years experience with various exploration and production companies, including previous responsibility for operations in the United Kingdom, Spain, Morocco, Egypt and Indonesia. He is a registered geophysicist in the State of California. William H. Marble, 48, has served as Vice President of HPI since December 1990. His previous positions with HPI have included Texas/Gulf Coast District Manager, Manager of Nonoperated Properties and Chief Engineer. He joined a predecessor general partner of the Partnership in 1984. Mr. Marble is a registered engineer in the State of Colorado and has 24 years oil and gas engineering experience. Brian M. Troup, 51, has served as a director of HCRC since February 1992. He has been President and Chief Operating Officer of Hallwood Group since April 1986, and he is a director. Mr. Troup has been a director of the general partner of HEP since May 1984. Mr. Troup is a director of Hallwood Holdings S.A. and of Hallwood Realty. He is an associate of the Institute of Bankers in Scotland and a member of the Society of Investment Analysts in the United Kingdom. John R. Isaac, Jr., 49, has served as a director of HCRC since June 1992. Since October 1997, Mr. Isaac has been Chief Executive Officer and President of Ideas, Inc., a retail consulting company. From February 1996 to October 1997, Mr. Isaac was President and Chief Executive Office of Thorn Americas, Inc., parent of Rent-A-Center USA. From March 1995 until February 1996, Mr. Isaac was President and Chief Operating Officer of Rent-A-Center USA. From February 1991 to February 1995, Mr. Isaac was President and Chief Operating Officer of Everything's A Dollar, a division of Value Merchants, Inc. He was President and Chief Executive Officer of Hallwood Industries Incorporated from August 1987 to October 1991. He was President of Tradevest, Inc., a mail order catalog retailer, from 1986 to 1987, and a Vice President of Service Merchandise Co., Inc., a catalog showroom retailer, from 1981 to 1986. Jerry A. Lubliner, 43, has served as a director of HCRC since June 1992. Dr. Lubliner is a medical doctor who has been in private practice since 1986. From 1986 to 1988, he was Associate Chief-Sports Medicine at the Hospital for Joint Diseases-Orthopedic Institute in New York. Dr. Lubliner is a Fellow of the American Academy of Orthopedic Surgeons. He is also a director of New York Orthopedics and Sports Medicine, P.C. Hamilton P. Schrauff, 62, has served as a director of HCRC since September 1996. From March 1997 until June 1998, he was Chief Financial Officer of Burns Controls Company. From March 1996 to January 1997 he was Vice President of Capital Alliance. From August 1995 to February 1996 he was an independent financial consultant. From October 1991 to August 1995 he was Vice President and Chief Financial Officer of Basic Capital Management, Inc., Syntek Asset Management, Inc., American Realty Trust Investors, Inc., Income Opportunity Realty Trust and Transcontinental Realty Investors, Inc. From October 1991 to February 1994 he was Executive Vice President and Chief Financial Officer of National Income Realty Trust and Vinland Property Trust. From December 1990 to October 1991 he was Vice President Finance-Partnership Investments of Hallwood Group. From October 1980 to October 1990 he was Vice President Finance and Treasurer, and from November 1976 to September 1980 he was Vice President Finance of Texas Oil and Gas Corporation. Mr. Schrauff is a Certified Public Accountant and a Certified Financial Planner. He is a member of the American Institute of Certified Public Accountants, the Texas Society of Certified Public Accountants and the Financial Executives Institute. Bill M. Van Meter, 65, has served as a director of HCRC since September 1996. From 1986 until May 1996, Mr. Van Meter was President of the Energy Companies of ONEOK division of ONEOK Inc. From 1958 to 1996, Mr. Van Meter was employed by both major and independent oil companies. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires the officers and directors of HCRC and persons who own more than ten percent of the Common Stock, to file reports of ownership and changes in ownership with the Securities and Exchange Commission. Officers, directors and greater than ten percent owners are required by SEC regulation to furnish HCRC with copies of all Section 16(a) forms they file. Based solely on its review of the copies of such forms received by it, or written representations from certain reporting persons that no forms were required for those persons, HCRC believes that, during the year ended December 31, 1998, all officers and directors of the Company and greater than ten-percent beneficial owners complied with applicable filing requirements, except that Mr. Thomas Jung filed his initial statement of beneficial ownership late. Mr. Jung did not beneficially own any Common Stock of HCRC. ITEM 11 - EXECUTIVE COMPENSATION General The Company has no employees. Management services are provided to the Company by HPI, an affiliate of the Company. Employees of HPI perform all duties related to the management of the Company, including the operations of various properties in which the Company owns an interest. The Company is charged for management services by HPI based on an allocation procedure that takes into account the amount of time spent on management, the number of properties owned by the Company and the Company's performance relative to its affiliates. The allocation procedure is applied consistently to all related entities for which HPI performs services. In 1998 the Company reimbursed HPI for approximately $2,376,000 of expenses, of which $442,000 was attributable to compensation paid to executive officers of the Company. Compensation of Executive Officers The following table sets forth the compensation to the Chief Executive Officer and each of the four other most highly compensated officers whose compensation paid by HPI exceeded $100,000 (determined for the year ended December 31, 1998).
Summary Compensation Table Long Term Annual Compensation Compensation Securities Underlying LTIP All Other Name & Principal Position Year Salary Bonus Options/SARs Payouts Compensation - ------------------------- ---- ------ ----- ------------ ------- ------------ (#) (1) Anthony J. Gumbiner (2) 1998 $ 0 $ 0 0 $ (5) $ 0 Chief Executive 1997 0 0 (3) (5) 0 Officer 1996 125,000 0 0 (5) 0 William L. Guzzetti 1998 79,038 71,876 0 15,032 1,852 President and Chief 1997 82,535 65,677 (3) 24,855 1,919 Operating Officer 1996 82,943 60,490 0 14,927 2,314 Russell P. Meduna 1998 63,159 43,709 0 15,032 1,852 Executive Vice 1997 66,120 50,909 (3) 24,855 1,919 President 1996 66,448 46,874 0 14,927 1,827 Thomas J. Jung 1998 31,972 26,490 (4) 0 742 Vice President and Chief Financial Officer Cathleen M. Osborn 1998 46,160 32,892 0 10,568 1,852 Vice President and 1997 42,697 45,650 (3) 17,472 1,919 General Counsel 1996 42,908 28,704 0 10,391 1,827 (1) Employer contribution to 401(k) and a service award of $487 paid to Mr Guzzetti in 1996. (2) For 1996, Mr. Gumbiner had a Compensation Agreement with HPI. $125,000 of his compensation was allocated to the Company in 1996. The Compensation Agreement terminated effective December 1996. In addition to compensation listed in the table. HPI had a consulting agreement with Hallwood Group for 1996, pursuant to which Hallwood Group received an annual consulting fee of $300,000 from affiliates of HPI. The Company paid approximately $122,000 in 1996 pursuant to this arrangement. During 1997 and 1998, the Company participate in a new financial consulting agreement between HPI and Hallwood Group, pursuant to which Hallwood Group received a fee of $550,000 from affiliates of HPI. The Company paid Hallwood Group approximately $241,000 in 1998 and 1997 for the Company's share of the consulting agreement. The consulting services were provided by HSC Financial Corporation ("HSC Financial"), through the services of Mr. Gumbiner and Mr. Troup, and Hallwood Group paid the annual fee it received to HSC Financial. (3) Consists of the following options granted in 1997, which have been adjusted for a 3-for-1 split effective in 1997. Securities Underlying Name Options/SARs (#) Anthony J. Gumbiner 47,700 William L. Guzzetti 23,850 Russell P. Meduna 22,260 Cathleen M. Osborn 9,540 (4) Consists of the following options granted in 1998. Securities Underlying Name Options/SARs (#) Thomas J. Jung 19,080 (5) Payments were made to HSC Financial, with which Mr. Gumbiner is associated, in the amount of $33,479 for 1998, $31,755 in 1997 and $4,474 for 1996.
Option Grants and Exercises in Last Fiscal Year The following table sets forth the options to purchase Common Stock of the Company granted to executive officers during 1998.
Option/SAR Grants in Last Fiscal Year Potential Realized Value at Assumed Annual Rates of Stock Price Appreciation Individual Grants for Option Term (2) Number of % of Total Securities Options/SARs Underlying Granted Exercise or 5% 10% Options/SARs Employees in Base Price Expiration $25.66 $40.85 Name Granted (1) Fiscal Year ($/Share) Date Share Price Share Price ---- ----------- ------------- ----------- ---------- ----------- ----------- Thomas J. Jung 19,080 100 $15.75 05/05/08 $189,989 $478,936 (1) Options have a ten-year term and vest cumulatively over two years at the rate of 1/3 on the grant date and the 1/3 on first two anniversaries of the grant date. All options vest immediately in the event of certain changes in control of HCRC. (2) Securities and Exchange Commission Rules require calculation of potential realizable value assuming that the market price of the Common Stock appreciates in value at 5% and 10% annualized rates. At a 5% annualized rate of appreciation, the Common Stock price would be $25.66 at the end of ten years. At a 10% annualized rate of appreciation, the Common Stock price would be $40.85 at the end of ten years. No gain to an executive officer is possible without an appreciation in Common Stock value, which will benefit all holders of Common Stock. The actual value an executive officer may receive depends on market prices for the Common Stock, and there can be no assurance that the amounts reflected will actually be realized.
The following table shows exercises of options to purchase Common Stock during 1998 and the value of the unexercised options on December 31, 1998.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values Number of Securities Underlying Value of Unexercised Unexercised In-the-Money Options/SARs Options/SARs at FY - End (#) at FY -End ($) Stock Acquired Value Exercisable/ Exercisable/ Name on Exercise (#) Realized ($) Unexercisable (1) Unexercisable (2) ---- --------------- ------------ ----------------- ----------------- Anthony J. Gumbiner 4,000 $33,820 75,500 / 15,900 189,221 / 0 William L. Guzzetti 39,750 / 7,950 103,271 / 0 Russell P. Meduna 2,500 21,700 34,600 / 7,420 85,561 / 0 Cathleen M. Osborn 5,000 42,900 10,900 / 3,180 19,658 / 0 Thomas J. Jung 6,360 / 12,720 0 / 0 (1) The options have a ten-year term and vest cumulatively over three years at the rate of 1/3 on each of the date of grant and the first two anniversaries of the grant date. All options vest immediately in the event of certain changes in control of the Company. The number of options has been adjusted to reflect a 3-for-1 stock split effective in 1997. (2) The exercise price of the options granted in 1995 is $6.67 per share, the exercise price of the options granted in 1997 is $20.33 per share and the exercise price of the options granted in 1998 is $15.75 per share. The closing price of the common stock was $11.00 on December 31, 1998. The exercise prices have been adjusted to reflect a 3-for-1 stock split effective in 1997.
Long-Term Incentive Plan The following table describes performance units awarded to the executive officers of the Company for 1998 under the incentive Plan (as described below) for the Company and affiliated entities. The value of awards under each plan depends primarily on the Company's success in drilling, completing and achieving production from new wells each year and from certain recompletions and enhancements of existing wells. The amounts shown below are the portion of awards under the plan allocated to the Company.
Long-Term Incentive Plan Awards in Last Fiscal Year Performance or Estimated Future Number of Other Period Payouts under Non-Stock Name Units Unit Payout Price-Based Plans (1) ---- ----------- --------------- ----------------------- Anthony J. Gumbiner(2) -- -- $ -- William L. Guzzetti 0.0727 2003 8,951 Russell P. Meduna 0.0727 2003 8,951 Cathleen M. Osborn 0.0545 2003 6,710 (1) The amount represents an award under the Incentive Plan. There are no minimum, maximum or target amounts payable under the Incentive Plan. Payments under the awards will be equal to the indicated percentage of Plan net cash flow from certain wells for the first five years after an award and, in the sixth year, the indicated percentage of 80% of the remaining net percent value of estimated future production from the wells allocated to the Plan. The amounts shown above are estimates based on estimated reserve quantities and future prices. Because of the uncertainties inherent in estimating quantities of reserves and prices, it is not possible to predict cash flow or remaining net present value of estimated future production with any degree of certainty. (2) In addition, an award of .3818 units, with an estimated future payout of $47,010, was made to HSC Financial, with which Mr. Gumbiner is associated. The payout period ends in 2003.
The Incentive Plan for the Company is intended to provide incentive and motivation to HPI's key employees to increase the oil and gas reserves of the various affiliated entities for which HPI provides services and to enhance those entities' ability to attract, motivate and retain key employees and consultants upon whom, in large measure, those entities' success depends. Under the Incentive Plan, the Board of Directors of the Company (the "Board") annually determines the portion of the Company's collective interests in the cash flow from certain international projects and from domestic wells drilled, recompleted or enhanced during that year (the "Plan Year") which will be allocated to participants in the plan and the participants will receive payment in the sixth year of an award. The portion allocated to participants in the plan is referred to as the Plan Cash Flow. The Board then determines which key employees and consultants may participate in the plan for the Plan Year and allocates the Plan Cash Flow among the participants. Awards under the plan do not represent any actual ownership interest in the wells. Awards are made in the Board's discretion. Each award under the Incentive Plan represents the right to receive for five years a specified share of the Plan Cash Flow attributable to certain domestic wells drilled, recompleted or enhanced during the Plan Year. In the sixth year afterward, the participant is paid an amount equal to a specified percentage of the remaining net present value of estimated future production from the wells and the award is terminated. Cash flow from international projects, if any, allocated to the Incentive Plan is paid to participants for a 10-year period, with no buy-out for estimated future production. The awards for the 1998 Plan Year were made in January 1998. No other awards were made in 1998. For the 1998 Plan Year, the Compensation Committee of Hallwood G.P. determined that the total Plan Cash Flow would be equal to 2.75% of the cash flow of the domestic wells completed, recompleted or enhanced during the Plan Year. Accordingly, the value of awards for each Plan Year depends primarily on the Company's success in drilling, completing and achieving production from new wells each year and from certain recompletions and enhancements of existing wells. The Compensation Committee also determined that the participants' interests in eligible domestic wells for the 1998 Plan Year would be purchased in the sixth year at 80% of the remaining net present value of the wells completed in the Plan Year. The Compensation Committee also determined that the total award would be allocated among key employees primarily on the basis of salary, and, to a lesser extent, on the basis of contribution to HCRC's drilling activity. Director Compensation Each director of the Company who is not an officer of HCRC or an employee of HPI, is paid an annual fee of $20,000 that is proportionately reduced if the director attends fewer than four regularly scheduled meetings of the Board during the year. During 1998, Messrs. Lubliner, Van Meter and Schrauff were each paid $20,000. In addition, all directors are reimbursed for their expenses in attending meetings of the Board and committees. Compensation Committee Interlocks and Insider Participation The Board of Directors of HCRC makes compensation decisions for the Company during the first quarter of each year. Mr. Gumbiner is Chief Executive Officer and serves on the compensation committee of Hallwood Group, of which Mr. Troup is President and Mr. Guzzetti is Executive Vice President. Mr. Gumbiner is Chief Executive Officer and a director, and Mr. Guzzetti is President and a director, of Hallwood Realty. During 1998, Mr. Gumbiner and Mr. Guzzetti served on the compensation committee of Hallwood Realty. The Company participates in a financial consulting agreement between HPI and Hallwood Group, pursuant to which Hallwood Group furnishes consulting and advisory services to HPI, the Company and their affiliates. Under the terms of this agreement, HPI and its affiliates are obligated to pay Hallwood Group $550,000 per year until June 30, 2000. The agreement automatically renews for successive three year terms; either party may terminate the agreement on not less than 30 days written notice prior to the expiration of any three year term. The financial consulting agreement replaced both a previous financial consulting agreement and a compensation agreement with Mr. Gumbiner. Under the terms of the previous financial consulting agreement, HPI and its affiliates were obligated to pay Hallwood Group three annual payments of $300,000 beginning June 30, 1994, and Hallwood group was obligated to furnish consulting and advisory services to HPI and its affiliates through June 30, 1997. In 1997, the consulting services were provided by HSC Financial Corporation, through the services of Mr. Gumbiner and Mr. Troup, and Hallwood Group paid the annual fee it received to HSC Financial. A fee of approximately $241,000 was paid in 1998 and 1997 and $122,000 was paid in 1996, by the Company pursuant to this arrangement. For 1996, Mr. Gumbiner had a compensation agreement with HPI under which the Company was allocated $125,000 in consulting fees. This agreement was terminated effective December 31, 1996. The Company reimburses Hallwood Group for expenses incurred on behalf of the Company. The Company reimbursed Hallwood Group for approximately $246,000, $232,000 and $234,000 of expenses during 1998, 1997 and 1996, respectively. ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table shows information, as of March 24, 1999, about any individual, partnership or corporation that is known to Hallwood Consolidated Resources to be the beneficial owner of more than 5% of Hallwood Consolidated Resources Common Stock issued and outstanding and each executive officer and director of Hallwood Consolidated Resources and all executive officers and directors of Hallwood Consolidated Resources as a group.
Amount Beneficially Name Owned Percent of Class Hallwood Energy Partners, L.P. (1) 1,374,465(5) 45.7 Heartland Advisors, Inc. (2) 476,500(6) 15.8 Estate of William Baxter Lee, III (3) 293,800(7) 9.8 FMR Corp. (4) 241,550(8) 8.0 Anthony J. Gumbiner 1,449,965(9)(10) 47.0 William L. Guzzetti 1,414,215(9)(10) 46.4 Russell P. Meduna 34,879(10) 1.2 Cathleen M. Osborn 10,990(10) * Thomas J. Jung 6,360(10) * Brian M. Troup 53,000(10) 1.7 Jerry A. Lubliner - - Hamilton P. Schrauff - - Bill M. Van Meter - - John R. Isaac, Jr. - - All directors and executive officers of 1,594,944(11) 49.4 HCRC as a group (10 persons) - ---------------------- * Less than 1% (1) The address of Hallwood Energy Partners is 4582 S. Ulster Street Parkway, Suite 1700, Denver, Colorado 80237. (2) The address of Heartland Advisors, Inc. is 790 North Milwaukee Street, Milwaukee, WI 53202. (3) The address of the Estate of William Baxter Lee, III, is c/o Glankler Brown, PLLC, 1700 One Commerce Sq., Memphis, TN 38103. (4) The address of FMR Corp. is 82 Devonshire Street, Boston, MA 02109. (5) Includes 40,323 shares held by Hallwood Oil and Gas, Inc., a subsidiary of Hallwood Energy Partners. Hallwood Energy Partners has sole voting and investment power with respect to the shares reported. The general partner of Hallwood Energy Partners is HEPGP Ltd., a limited partnership, the general partner of which is Hallwood G.P. The executive officers of Hallwood G.P. and Hallwood Consolidated Resources are the same individuals: Anthony J. Gumbiner, William L. Guzzetti, Russell R. Meduna, Cathleen M. Osborn and Thomas J. Jung. (6) Information is from Amendment No. 6 to the Schedule 13G of Heartland Advisors dated January 26, 1999. The Schedule 13G states that the shares are held in investment advisory accounts of Heartland Advisors, Inc. and that the interests of one such account, Heartland Value Fund, a series of Heartland Group, Inc., a registered investment company, relates to more than 5% of the Common Stock. (7) Information is from Schedule 13G filed February 23, 1999. (8) According to Schedule 13G filed February 12, 1999, Fidelity Management & Research Company is the beneficial owner of the shares and acts as investment adviser to Fidelity Low-Price Stock Fund which owns the shares. Edward C. Johnson 3d, FMR Corp. and Fidelity Low-Price Stock Fund each has sole power to dispose of the shares. The power to vote the shares resides with the Board of Trustees of Fidelity Low-Price Stock Fund. (9) Includes 1,374,465 shares beneficially owned by Hallwood Energy Partners. Mr. Gumbiner is Chief Executive Officer and Mr. Guzzetti is President and a director of the general partner of the general partner of Hallwood Energy Partners. (10) The following numbers of shares issuable upon the exercise of currently exercisable options are included in the amounts shown: Mr. Troup, 53,000 shares; Mr. Gumbiner, 75,500 shares; Mr. Guzzetti, 39,750 shares; Mr. Meduna, 34,600 shares; Ms. Osborn, 10,900 shares and Mr. Jung 6,360 shares. (11) Consists of 1,374,465 shares beneficially owned by Hallwood Energy Partners, currently exercisable options to purchase 220,110 shares and 369 shares owned by directors and executive officers.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS See Item 8 - Financial Statements and Supplementary Data (Note 5 to the Financial Statements). PART IV ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K Financial Statements and Financial Statement Schedules See Index at Item 8 Reports on Form 8-K No reports on Form 8-K were filed during the quarter ended December 31, 1998. Exhibits (1) 3.1 Restated Certificate of Incorporation of HCRC, as amended through January 21, 1992 (1) 3.2 Bylaws of HCRC (2) 3.3 Amendment to Bylaws of HCRC (3) 3.4 Certificate of Amendment of Restated Certificate of Incorporation dated November 9, 1995. (7) 3.5 Certificate of Amendment of Restated Certificate of Incorporation, effective August 1, 1997. (9) 4.1 Common Stock Purchase Warrant dated December 23, 1997. (9) 4.2 Registration Rights Agreement dated as of December 23, 1997. (1) 10.1 Agreement of Limited Partnership of Hallwood Consolidated Partners, L.P.(originally, agreement of HCP Acquisition, L.P.) (1) 10.5 Management Agreement between Hallwood Petroleum, Inc. and HCRC (4) 10.7 Amended and Restated Credit Agreement dated as of March 31, 1995 among HCRC and the Banks listed therein. (7) 10.8 Extension of Management Agreement between HCRC and Hallwood Petroleum, Inc. dated May 1, 1997. * (4) 10.9 Domestic Incentive Plan between HCRC and Hallwood Petroleum, Inc. dated January 14, 1993. * (5) 10.10 1995 Stock Option Plan * (5) 10.11 1995 Stock Option Loan Program (7) 10.13 Second Amended and Restated Credit Agreement dated as of May 31, 1997. * (7) 10.14 1997 Stock Option Plan * (8) 10.15 1997 Stock Option Plan Loan Program (8) 10.16 Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of October 31, 1997. (9) 10.17 Subordinated Note and Warrant Purchase Agreement dated as of December 23, 1997. (9) 10.18 Amendment No. 2 to Second Amended and Restated Credit Agreement dated as of December 23, 1997. * (10)10.19 Option Letter to Thomas Jung dated May 5, 1998 (10)10.20 Extension of Management Agreement between Hallwood Petroleum, Inc., and HCRC dated May 5, 1998. (11)10.21 Merger and Asset Contribution Agreement By and Among Hallwood Energy Corporation, and HEC Acquisition Partnership, L.P., HEC Acquisition Corp., Hallwood Consolidated Resources Corporation and HEPGP Ltd. dated as of December 15, 1998. 10.22 Letter Amendment No. 1 to Subordinated Note and Warrant Purchase Agreement. (6) 21 Subsidiaries of Registrant 23.1 Consent of Deloitte & Touche LLP 23.2 Consent of Deloitte & Touche LLP 27 Financial Data Schedule - ------------------ (1) Incorporated by reference to the Registrant's Registration Statement No. 33-45729 on Form S-4 filed on February 14, 1992. (2) Incorporated by reference to the Annual Report on Form 10-K for the year ended December 31, 1992. (3) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1995. (4) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended March 31, 1995. (5) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1995. (6) Incorporated by reference to the Annual Report on Form 10-K for the year ended December 31, 1995. (7) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1997. (8) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1997. (9) Incorporated by reference to the Annual Report of Form 10-K for the year ended December 31, 1997. (10) Incorporated by reference to the Quarterly Report on Form 10-Q for the quarter ended June 30, 1998 (11) Incorporated by reference to Schedule 14A of HCRC dated December 30, 1998. * Designates management contract or compensatory plan or arrangement. 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. HALLWOOD CONSOLIDATED RESOURCES CORPORATION Date: March 24 , 1999 By: /s/William L. Guzzetti William L. Guzzetti President and Director Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Capacity Date /s/Anthony J. Gumbiner Chairman of the Board and March 24, 1999 Anthony J. Gumbiner Director /s/Brian M.Troup Director March 24, 1999 Brian M. Troup /s/John R. Isaac,Jr. Director March 24, 1999 John R. Isaac, Jr. /s/Jerry A. Lubliner Director March 24, 1999 Jerry A. Lubliner /s/Hamilton P. Schrauff Director March 24, 1999 Hamilton P. Schrauff /s/Bill M. Van Meter Director March 24, 1999 Bill M. Van Meter /s/Thomas J. Jung Vice President March 24, 1999 Thomas J. Jung Chief Financial Officer (Principal Accounting Officer) INDEX TO EXHIBITS Page Exhibit 10.22 - Letter Amendment No. 1 to Subordinated Note and Warrant Purchase Agreement 68-72 Exhibit 23.1 - Consent of Deloitte & Touche LLP 73 Exhibit 23.2 - Consent of Deloitte & Touche LLP 74 EX-10.2 2 LETTER AMENDMENT NO. 1 TO SUBORDINATED NOTE AGRMNT Hallwood Consolidated Resources Corporation - -------------------------------------------------------------------------------- 4582 S. Ulster St. Pkwy o Suite 1700 o Stanford Place III o P.O. Box 378111 Denver, Colorado 80237 o (303) 850-7373 - -------------------------------------------------------------------------------- LETTER AMENDMENT NO. 1 March 15, 1999 The Prudential Insurance Company of America c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, Texas 75201 Ladies and Gentlemen: We refer to the Subordinated Note and Warrant Purchase Agreement dated as of December 23, 1997 (the "Agreement") among the undersigned, Hallwood Consolidated Resources Corporation (the "Company"), and you. Unless otherwise defined herein, the terms defined in the Agreement shall be used herein as therein defined. Paragraph 6A(2) of the Agreement requires that the Company not permit Consolidated Net Worth on the last day of any fiscal quarter, commencing with the fiscal quarter ending December 31, 1997, to be less than the sum of (i) $31,255,900 plus (ii) 100% of any Equity Proceeds plus (iii) the cumulative total of 50% of Consolidated Net Income for each fiscal quarter after September 30, 1997 in which Consolidated Net Income is positive. On December 31, 1998, the Consolidated Net Worth requirement contained in paragraph 6A(2) was $31,417,267. Because of a total of $19,600,000 in property impairments recorded during 1998, Consolidated Net Worth was $29,589,000 at December 31, 1998. The Company requests that you waive the requirements of paragraph 6A(2) for the fourth quarter of 1998, provided that Consolidated Net Worth during such period was not less than $29,000,000. In addition, the Company is contemplating a consolidation (the "Consolidation") of the Company, Hallwood Energy Partners, L.P. ("HEP") and the energy interests of The Hallwood Group Incorporated into Hallwood Energy Corporation, a newly formed corporation ("HEC"). As a result of the Consolidation, the Company and HEP will become wholly-owned subsidiaries of HEC. In addition, the equity interests in HEP owned by the Company (representing approximately 19.00% of the outstanding limited partnership interests of HEP) will not be converted into securities of HEC. Whether or not the Company proceeds with the Consolidation, the Company anticipates that it will not be in compliance with paragraph 6A(2) during 1999 and has requested that you amend the covenant to permit the Company to go forward with the Consolidation without being in default, despite the transfer of the HEP interests. In addition, the Company would amend paragraph 6A of the Agreement such that the Consolidated Net Worth requirement and the Total Debt to EBITDA ratio would each be applicable to HEC on a consolidated basis and would be defined in a manner, and would have compliance levels, satisfactory to you and the Company. Finally, the Company or HEC would pay you an amendment fee of $75,000 on the effective date of the assumption. Based on the foregoing, you have indicated your willingness to waive the default occasioned by noncompliance with paragraph 6A(2) for the fourth quarter of 1998 and to give a conditional amendment to such covenant, provided that the Company agrees with the other conditions set forth herein. Accordingly, it is hereby agreed by you and us as follows: 1. Waiver. The holders of the Notes hereby agree to waive the Event of Default occasioned by noncompliance by the Company with paragraph 6A(2) as of December 31, 1998, provided that the Consolidated Net Worth at such date was not less than $29,000,000. 2. Amendments. The Agreement is, effective the date first above written, hereby amended as follows: (a) Paragraph 6A(2). Consolidated Net Worth. Paragraph 6A(2) of the Agreement is amended in its entirety to read as follows: 6A(2). Consolidated Net Worth. Consolidated Net Worth on the last day of any fiscal quarter (I) commencing with the fiscal quarter ending December 31, 1997 and ending December 31, 1998, to be less than the sum of (i) $31,255,900 plus (ii) 100% of any Equity Proceeds plus (iii) the cumulative total of 50% of Consolidated Net Income for each fiscal quarter after September 30, 1997 in which Consolidated Net Income is positive, to and including the fiscal quarter ended on such measurement date, (II) commencing with the fiscal quarter ending March 31, 1999 and ending on the earlier of the fiscal quarter ending March 31, 2000 and the last day of the fiscal quarter ending immediately before the Consolidation, to be less than $25,000,000, and (III) at any time after the earlier of March 31, 2000 and the last day of the fiscal quarter ending immediately before the Consolidation, to be less than the sum of (x) $31,417,267 plus (y) 100% of any Equity Proceeds received after December 31, 1998 plus (z) the cumulative total of 50% of Consolidated Net Income for each fiscal quarter after December 31, 1998 in which Consolidated Net Income is positive, to and including the fiscal quarter ended on such measurement date. (b) Paragraph 8A. Acceleration. Paragraph 8A of the Agreement is amended by (I) adding the word "or" after clause (xv) and adding a new clause (xvi) to read as follows: (xvi) the Company shall merge or consolidate with or into, or convey, transfer, lease, or otherwise dispose of all or substantially all of its assets to HEC, HEP or any other entity, pursuant to the Consolidation or any other corporate reorganization without the obligations of the Company under the Agreement and Notes being assumed by HEC or such other entity and the obligations of HEC or such other entity under the Agreement and the Notes being guaranteed on a subordinated basis substantially similar to paragraph 7 by each of the Company and HEP, all in a manner satisfactory to the Required Holders; (c) Paragraph 11B. Other Terms. Paragraph 11B is amended by adding the following definitions in the appropriate alphabetical order: "Consolidation" shall mean the consolidation of the Company, HEP and the energy interests of The Hallwood Group Incorporated into HEC. "HEC" shall mean Hallwood Energy Corporation, a Delaware corporation. On and after the effective date of this letter amendment, each reference in the Agreement to "this Agreement", "hereunder", "hereof", or words of like import referring to the Agreement, and each reference in the Notes to "the Agreement", "thereunder", "thereof", or words of like import referring to the Agreement, shall mean the Agreement as amended by this letter amendment. The Agreement, as amended by this letter amendment, is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. The execution, delivery and effectiveness of this letter amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy under the Agreement nor constitute a waiver of any provision of the Agreement. This letter amendment may be executed in any number of counterparts and by any combination of the parties hereto in separate counterparts, each of which counterparts shall be an original and all of which taken together shall constitute one and the same letter amendment. The effectiveness of this letter amendment is conditioned upon the accuracy of the factual matters set forth above. The Company hereby confirms its agreement to pay the fees, charges and disbursements of your special counsel incurred in connection with this letter amendment. If you agree to the terms and provisions hereof, please evidence your agreement by executing and returning at least a counterpart of this letter amendment to the Company at 4582 S Ulster St. Pkwy., Suite 1700, Denver, Colorado 80237, Attention: Legal Department. This letter amendment shall become effective as of the date first above written when and if: (i) counterparts of this letter amendment shall have been executed by us and you; (ii) the consent attached hereto shall have been executed by the Guarantor; and (iii) you shall have received an amendment fee of $25,000 by wire transfer to the account specified in the Purchaser Schedule attached to the Agreement. Very truly yours, HALLWOOD CONSOLIDATED RESOURCES CORPORATION By: Thomas J. Jung, Vice President and Chief Financial Officer Agreed as of the date first above written: THE PRUDENTIAL INSURANCE COMPANY OF AMERICA By: Vice President CONSENT The undersigned, as Guarantor under the Senior Subordinated Guaranty dated as of December 23, 1997 (the "Guaranty") in favor of The Prudential Insurance Company of America, a party to the Agreement referred to in the foregoing letter amendment, hereby consents to said letter amendment and hereby confirms and agrees that the Guaranty is, and shall continue to be, in full force and effect and is hereby confirmed and ratified in all respects except that, upon the effectiveness of, and on and after the date of, said letter amendment, all references in the Guaranty to the Agreement, "thereunder", "thereof", or words of like import referring to the Agreement shall mean the Agreement as amended by said letter amendment. HALLWOOD CONSOLIDATED PARTNERS, L.P. BY: HALLWOOD CONSOLIDTED RESOURCES CORPORATION, GENERAL PARTNER By: Thomas J. Jung Vice President and Chief Financial Officer March 15, 1999 EX-23.1 3 CONSENT OF DELOITTE & TOUCHE INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-1154 of Hallwood Consolidated Resources Corporation on Form S-8 of our report dated March 24, 1999, appearing in this Annual Report on Form 10-K of Hallwood Consolidated Resources Corporation for the year ended December 31, 1998. DELOITTE & TOUCHE LLP Denver, Colorado March 24, 1999 EX-23.2 4 CONSENT OF DELOITTE & TOUCHE INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-34105 of Hallwood Consolidated Resources Corporation on Form S-8 of our report dated March 24, 1999, appearing in this Annual Report on Form 10-K of Hallwood Consolidated Resources Corporation for the year ended December 31, 1998. DELOITTE & TOUCHE LLP Denver, Colorado March 24, 1999 EX-27 5 FDS HALLWOOD CONSOLIDATED RESOURCES 12/31/98 10-K
5 This schedule contains summary financial information extracted from Form 10-K for the year ended December 31, 1998 for Hallwood Consolidated Resources Corporation and is qualified in its entirety by reference to such Form 10-K. 0000883953 Hallwood Consolidated Resources Corporation 1,000 12-MOS DEC-31-1998 DEC-31-1998 551 0 7,299 0 0 12,566 339,526 252,204 101,167 18,262 0 0 0 30 29,559 101,167 32,230 32,410 0 11,642 0 0 4,160 (19,993) 286 (20,279) 0 0 0 (20,279) (7.38) (7.38)
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