-----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, SSb5Y1DPnZAN19KKr6YhW/O0c7ea2h4xcWRiOo6kFGUVGT1MsSHXKJ/ARyrrvdMN IKet2FNylxszkL1Q45m2LA== 0000883953-99-000004.txt : 19990512 0000883953-99-000004.hdr.sgml : 19990512 ACCESSION NUMBER: 0000883953-99-000004 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990511 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-Q SEC ACT: SEC FILE NUMBER: 000-19931 FILM NUMBER: 99617080 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-Q 1 HALLWOOD CONSOLIDATED RESOURCES 3/31/99 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-Q MARK ONE [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly Period Ended March 31, 1999 [ ] 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 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 [ ] Shares of Common Stock outstanding at May 11, 1999 3,007,852
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands) March 31, December 31, 1999 1998 CURRENT ASSETS Cash and cash equivalents $ 181 $ 551 Accrued oil and gas revenue 2,661 3,053 Due from affiliates 5,207 4,246 Prepaid and other assets 436 285 Current assets of affiliates 3,463 4,431 --------- --------- Total current assets 11,948 12,566 -------- -------- PROPERTY, PLANT AND EQUIPMENT, at cost Oil and gas properties (full cost method) Proved oil and gas properties 340,005 336,713 Unproved mineral interests - domestic 2,859 2,813 --------- --------- Total 342,864 339,526 Less - accumulated depreciation, depletion, amortization and impairment (255,641) (252,204) ------- ------- Net property, plant and equipment 87,223 87,322 -------- -------- OTHER ASSETS Deferred expenses 1,188 1,201 Noncurrent assets of affiliate 80 78 ----------- ----------- Total other assets 1,268 1,279 --------- --------- TOTAL ASSETS $100,439 $101,167 ======= =======
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HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands except Shares) March 31, December 31, 1999 1998 CURRENT LIABILITIES Accounts payable and accrued liabilities $ 3,034 $ 3,886 Current portion of long-term debt 6,624 4,781 Current liabilities of affiliates 9,888 9,595 --------- --------- Total current liabilities 19,546 18,262 -------- -------- NONCURRENT LIABILITIES Long-term debt 43,955 44,774 Long-term obligations of affiliates 8,013 8,482 Deferred liability 53 60 ----------- ----------- Total noncurrent liabilities 52,021 53,316 -------- -------- Total liabilities 71,567 71,578 -------- -------- COMMITMENTS AND CONTINGENCIES (NOTE 5) STOCKHOLDERS' EQUITY Common stock, par value $.01; 10,000,000 shares authorized; 3,007,852 shares issued in 1999 and 1998 30 30 Additional paid-in-capital 81,283 81,283 Accumulated deficit (48,577) (47,860) Treasury stock - 258,395 shares in 1999 and 1998 (3,864) (3,864) --------- --------- Stockholders' equity - Net 28,872 29,589 -------- -------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $100,439 $101,167 ======= =======
The accompanying notes are an integral part of the financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (In thousands except per Share data) For the Three Months Ended March 31, 1999 1998 REVENUES: Gas revenue $ 5,207 $ 4,312 Oil revenue 2,063 2,745 Pipeline and other 880 320 Interest income 25 85 --------- --------- 8,175 7,462 ------- ------- EXPENSES: Production operating 2,965 2,763 General and administrative 1,157 909 Interest 1,295 821 Depreciation, depletion and amortization 3,437 2,531 ------- ------- 8,854 7,024 ------- ------- INCOME (LOSS) BEFORE INCOME TAXES (679) 438 -------- -------- PROVISION FOR INCOME TAXES: Current 38 123 --------- -------- NET INCOME (LOSS) $ (717) $ 315 ======== ======== NET INCOME (LOSS) PER SHARE - BASIC $ (.26) $ .11 ======== ======== NET INCOME (LOSS) PER SHARE - DILUTED $ (.26) $ .11 ======== ======== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 2,749 2,740 ======= =======
The accompanying notes are an integral part of the financial statements.
HALLWOOD CONSOLIDATED RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands) For the Three Months Ended March 31, 1999 1998 OPERATING ACTIVITIES: Net income (loss) $ (717) $ 315 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization 3,437 2,531 Amortization of deferred loan costs and debt discount 53 50 Noncash interest expense 6 Undistributed earnings of affiliates (1,461) (698) Recoupment of take-or-pay liability (7) (7) Changes in assets and liabilities provided (used) cash net of noncash activity: Accrued oil and gas sales 392 953 Due from affiliates (961) (1,057) Prepaid and other assets (180) (494) Deferred expenses 13 Accounts payable and accrued liabilities (852) (1,131) -------- ------ Net cash provided by (used in) operating activities (283) 468 -------- ------- INVESTING ACTIVITIES: Additions to oil and gas properties (787) (115) Exploration and development costs incurred (1,660) (2,221) Proceeds from oil and gas property sales 12 Distributions received from affiliates 1,348 286 ------ ------- Net cash used in investing activities (1,087) (2,050) ----- ------ FINANCING ACTIVITIES: Proceeds from long-term debt 1,000 Payments on contract settlement obligation (1,045) Exercise of stock options 113 Net cash provided by (used in) financing activities 1,000 (932) ------ ------- NET DECREASE IN CASH AND CASH EQUIVALENTS (370) (2,514) CASH AND CASH EQUIVALENTS: BEGINNING OF PERIOD 551 4,492 ------- ------ END OF PERIOD $ 181 $ 1,978 ======= ======
The accompanying notes are an integral part of the financial statements. HALLWOOD CONSOLIDATED RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) NOTE 1 - ORGANIZATION AND BASIS OF PRESENTATION Hallwood Consolidated Resources Corporation ("HCRC" or the "Company") is a Delaware corporation engaged in the development, production, sale and transportation 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. The interim financial data in the accompanying financial statements are unaudited; however, in the opinion of management, the interim data include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim periods. These financial statements should be read in conjunction with the financial statements and accompanying notes included in the Company's 1998 Annual Report on Form 10-K. NOTE 2 - ACCOUNTING POLICIES Consolidation The Company 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 the Company and its pro rata share of the activities of Hallwood Energy Partners, L.P. ("HEP"). Treasury Stock At March 31, 1999 and December 31, 1998, the Company owned approximately 19% of the outstanding units of HEP which owns approximately 46% of the Company's common stock; consequently, the Company had an interest in 258,395 of its own shares at March 31, 1999 and December 31, 1998. These shares are treated as treasury stock in the accompanying financial statements. 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 outstanding. Diluted income per share includes the potential dilution that could occur upon exercise of outstanding options to acquire common stock 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 3, 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 for the three months ended March 31, 1999 because their inclusion would be antidilutive. 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 Three Months Ended March 31, 1999 Net loss per share - basic $(717) 2,749 $(.26) ---- ----- ==== Net Loss per share - diluted $(717) 2,749 $(.26) ==== ===== ==== For the Three Months Ended March 31, 1998 Net income per share - basic $ 315 2,740 $ .11 ==== Effect of Options 81 -------- ------- Net Income per share - diluted $ 315 2,821 $ .11 ==== ===== ====
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 three month periods ended March 31, 1999 and 1998. Therefore, total comprehensive income (loss) was the same as net income (loss) for those periods. 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 the prior period amounts to conform to the classifications used in the current period. NOTE 3 - 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. Because of the grant and vesting of options to purchase shares of the Company, the number of warrants to purchase shares of Common Stock has increased to 99,361 and the exercise price has decreased to $28.77 per share as required by the terms of the Subordinated Note Agreement. 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 will be amortized over the term of the Subordinated Notes using the interest method of amortization. During 1997, the Company and its banks amended the Company's Credit Agreement to extend the term date to May 31, 1999. Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. The Company had $26,500,000 in borrowings outstanding as of March 31, 1999 and, therefore, had no available unused borrowing base. Borrowings against the credit line bear interest, at the option of the Company, at either (i) the banks' Certificate of Deposit rate plus from 1.375% to1.875%, (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% plus the Federal funds rate, plus .75%. The applicable interest rate was 6.9% at March 31, 1999. Interest is payable at least quarterly, and quarterly principal payments of $1,656,000 commence May 31, 1999. HCRC intends to extend the maturity date of its Credit Agreement prior to the commencement of the amortization period. The credit facility 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 will occur in the second quarter of 1999 if the proposed consolidation discussed in Note 6 is not approved.. HCRC anticipates that, 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 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. All of the contracts are interest rate swaps with fixed rates. As of March 31, 1999, HCRC was a party to four contracts with three different counterparties. The following table provides a summary of HCRC's financial contracts. Amount of Contract Period Debt Hedged Floor Rate Last nine months of 1999 $15,000,000 5.60% 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 4 - STATEMENTS OF CASH FLOWS Cash paid for interest during the three months ended March 31, 1999 and 1998 was $1,160,000 and $645,000, respectively. NOTE 5 - 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 to 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, in the amount of $452,000. That amount was accrued in the December 31, 1998 financial statements of the Company and will be paid during the second quarter of 1999. 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 6 - SUBSEQUENT EVENT On April 30, 1999, a Joint Proxy Statement/ Prospectus for the consolidation of HCRC with HEP and the energy interests of The Hallwood Group Incorporated ("Hallwood Group") into a new corporation called Hallwood Energy Corporation was declared effective by the Securities and Exchange Commission. The consolidation must be approved by a majority of the outstanding shares of HCRC and of each class of outstanding Units of HEP. The consummation of the consolidation is also subject to a number of other conditions. ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS During the first three months of 1999, HCRC had a net loss of $717,000, compared to net income of $315,000 for the first three months of 1998. The weighted average prices received by HCRC for oil and gas have declined in each of the last four quarters. HCRC's hedges have mitigated the price reductions. HCRC's weighted average oil and gas prices, when the effects of hedging are considered, were 25% and 8% lower, respectively, for the first three months of 1999 compared to the first three months of 1998. 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 filed with the Securities Exchange Commission, was declared effective on April 30, 1999. The Joint Proxy Statement/Prospectus was mailed on May 4, 1999, to shareholders of HCRC and unitholders of HEP of record as of April 14, 1999. A meeting of the shareholders of the Company will be held on May 25, 1999. If the consolidation is approved, public stockholders of Hallwood Consolidated Resources will receive 1.5918 shares of common stock of Hallwood Energy Corporation for each share of stock they now hold. Public holders of Class A Units of Hallwood Energy Partners will receive 0.7417 of a share of common stock of Hallwood Energy Corporation for each Class A Unit they now hold, and public holders of Class C Units will receive one share of redeemable preferred stock of Hallwood Energy Corporation for each Class C Unit they now hold. Hallwood Group will also contribute its energy interests to Hallwood Energy Corporation in exchange for additional shares of common stock of Hallwood Energy Corporation. Liquidity and Capital Resources Cash Flow HCRC used $283,000 of cash flow in operating activities during the first quarter of 1999. The primary cash inflows were: o $1,000,000 from borrowings under long-term debt and o $1,348,000 in distributions received from affiliates. Cash was primarily used for $2,447,000 of property additions, exploration and development costs. When combined with miscellaneous other cash activity during the first quarter, the result was a decrease in HCRC's cash and cash equivalents of $370,000 from $551,000 at December 31, 1998 to $181,000 at March 31, 1999. Exploration and Development Projects and Acquisitions Through March 31, 1999, HCRC incurred $2,447,000 in direct property additions, development, exploitation, and exploration costs. The costs were comprised of $787,000 for property acquisitions and approximately $1,660,000 for domestic exploration and development. HCRC's 1999 capital budget is set at $5,152,000. During the first quarter of 1999, HCRC postponed development drilling and recompletions for many oil-targeted projects due to the historically low oil prices experienced during that time. In April 1999, oil prices began to rebound and HCRC is reevaluating the economics of these projects. The significant capital expenditures for first quarter of 1999 are discussed below. Rocky Mountain Region HCRC expended approximately $686,000 of its capital budget in the Rocky Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico and Wyoming. Of this amount, approximately $626,000 was for the purchase of overriding royalty interests and working interests in 18 of the coal bed methane properties currently owned and operated by HCRC, located in San Juan County, New Mexico. Most of the interests purchased qualify for tax credits under Section 29 of the Internal Revenue Code. The majority of the acquired interests were purchased by 44 Canyon LLC ("44 Canyon") a special purpose entity owned by a large East Coast financial institution in exchange for cash, a production payment, and promissory notes. HCRC's activity in the area began in 1990, and the acquisition increases HCRC's net current average daily production by 475 mcf per day. Greater Permian Region During the first quarter of 1999, HCRC expended approximately $241,000 of its capital budget in the Greater Permian Region located in Texas and Southeast New Mexico. The major projects within the Region are discussed below. Catclaw Draw/Carlsbad Area Projects. HCRC spent approximately $192,000 successfully recompleting one operated well and drilling one development well in the Carlsbad/Catclaw Draw areas in Lea, Eddy and Chaves Counties, New Mexico. The development well is currently being completed. Gulf Coast Region In the first quarter of 1999, HCRC expended approximately $1,234,000 of its capital budget in the Gulf Coast Region in Louisiana and South and East Texas. The following are major projects within the Region. Mirasoles Project. HCRC incurred approximately $444,000 related to the Mirasoles project in Kenedy County, Texas during the first quarter of 1999. HCRC began drilling the 17,000 foot Frio Formation exploration well in 1998 and is completing the well, starting with the lowermost zone and moving uphole. Eight potential pay zones are identified in this exploration well, and the lower most zone was abandoned for mechanical reasons following encouraging, but extremely preliminary results. HCRC has a 17.5% working interest in this large structural prospect defined by 63 square miles of proprietary 3-D seismic data. Esperanza Project. In the first three months of 1999, HCRC incurred approximately $141,000 for costs associated with a non-operated 15,400 foot directional exploration well which tested the Wilcox formation in LaVaca County, Texas. The well was completed in 1998 and HCRC owns a 7.5% working interest in the well. Current gross gas production is approximately 9,500 mcf per day. HCRC began drilling an additional exploration well in the second quarter of 1999, and development drilling is anticipated in the latter months of 1999. Boca Chica Project. During the first quarter of 1999, HCRC participated in a directionally drilled 10,000 foot exploration well in the Big Hum formation from the shore to a bottom hole location under the waters of the Gulf of Mexico. Despite the well testing wet, the exploration results were sufficiently encouraging that working interest owners agreed to shoot 3D seismic in the third quarter of 1999 to evaluate future potential. It is anticipated that a second attempt will be made in the first quarter of 2000, possibly reentering the existing wellbore or using a shallow water drilling rig. For its 12.5% working interest, HCRC spent approximately $226,000. Other The remaining $286,000 of HCRC's first quarter 1999 capital expenditures were devoted principally to technical general and administrative expenditures and numerous other projects which are completed or underway and which are individually less significant. 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. Because of the grant and vesting of options to purchase shares of the Company, the number of warrants to purchase shares of Common Stock has increased to 99,361 and the exercise price has decreased to $28.77 per share, as required by the terms of the Subordinated Note Agreement. 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. During 1997, the Company and its banks amended the Company's Credit Agreement to extend the term date to May 31, 1999. Under the Credit Agreement, HCRC has a borrowing base of $26,500,000. The Company had amounts of $26,500,000 in borrowings outstanding as of March 31, 1999 and therefore, had no available unused borrowing base. Borrowings against the credit line bear interest, at the option of the Company, at either (i) the banks' Certificate of Deposit rate plus from 1.375% to1.875%, (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% plus the Federal funds rate, plus .75%. The applicable interest rate was 6.9% at March 31, 1999. Interest is payable at least quarterly, and quarterly principal payments of $1,656,000 commence May 31, 1999. HCRC intends to extend the maturity date of its Credit Agreement prior to the commencement of the amortization period. The credit facility 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 will occur in the second quarter of 1999 if the proposed consolidation discussed in Note 6 is approved. HCRC anticipates that, 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 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. All of the contracts are interest rate swaps with fixed rates. As of March 31, 1999, HCRC was a party to four contracts with three different counterparties. The following table provides a summary of HCRC's financial contracts. Amount of Contract Period Debt Hedged Floor Rate Last nine months of 1999 $15,000,000 5.60% 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% 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. 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 66% of the 180 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 $100,000. 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. 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-Q 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-Q 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 general partner, 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. Please refer to the Company's Annual Report on Form 10-K for additional statements concerning important factors that could cause actual results to differ materially from the Company's expectations. These risks and uncertainties include, among other things, volatility of oil and gas prices, competition, risks inherent in the Company's oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, the Company's ability to replace and expand oil and gas reserves, and such other risks and uncertainties described from time to time in the Company's periodic reports and filings with the Securities and Exchange Commission. 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. Inflation and Changing Prices Prices Prices obtained for oil and gas production depend upon numerous factors that are beyond the control of the Company, 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 fluctuated significantly throughout 1998 and through the first quarter of 1999, with a distinct downward trend in both oil and gas prices occurring in the calendar year 1998 and through the first quarter of 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. The Company believes oil and gas prices for the remainder of 1999 will exceed the budgeted prices. However, there can be no assurance that HCRC's forecast is accurate. If prices decrease below the forecasted levels, 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 each quarter by the Company and the effects of the hedging transactions described below:
Oil Oil Gas Gas (excluding the (including the (excluding the (including the effects of effects of effects of effects of hedging hedging hedging hedging transactions) transactions) transactions) transactions) (per bbl) (per bbl) (per mcf) (per mcf) First quarter 1998 $14.92 $15.08 $1.98 $1.93 Second quarter 1998 13.06 13.38 1.90 1.89 Third quarter 1998 12.05 12.44 1.76 1.88 Fourth quarter 1998 10.93 11.54 1.87 1.93 First quarter 1999 11.20 11.34 1.61 1.77
As part of its risk management strategy, HCRC enters into numerous 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 paid or received upon settlement of hedge contracts are recognized as increases or decreases in 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 May 3, 1999, HCRC was a party to 25 financial contracts with three different counterparties. The following table provides a summary of the Company's financial contracts:
Oil Contract Percent of Direct Delivered Period Production Hedged Floor Price (per bbl) Last nine months of 1999 25% $14.74
Approximately 17% 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. Additionally 17% 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 Contract Percent of Direct Delivered Period Production Hedged Floor Price (per mcf) Last nine months of 1999 49% $1.96 2000 41% 1.98 2001 46% 2.06 2002 32% 1.98
During the second quarter through May 3, 1999, the weighted average oil price (for barrels not hedged) was approximately $15.20 per barrel and the weighted average price of natural gas (for mcf not hedged) was approximately $1.70 per mcf. Inflation Inflation did not have a material impact on the Company in 1998 and is not anticipated to have a material impact on the Company 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 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 1998 and 1999.
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION (In thousands except price) For the Quarter Ended March 31, 1999 For the Quarter Ended March 31, 1998 ---------------------------------- ------------------------------------ Direct Direct Owned HEP Total Owned HEP Total Gas production (mcf) 2,322 615 2,937 1,673 567 2,240 Oil production (bbl) 149 33 182 146 36 182 Average gas price (per mcf) $ 1.75 $ 1.85 $ 1.77 $ 1.88 $ 2.05 $ 1.93 Average oil price (per bbl) $ 11.29 $ 11.55 $ 11.34 $ 15.03 $ 15.30 $ 15.08 Gas revenue $ 4,070 $ 1,137 $ 5,207 $ 3,151 $ 1,161 $ 4,312 Oil revenue 1,682 381 2,063 2,194 551 2,745 Pipeline and other 657 223 880 183 137 320 Interest income 4 21 25 60 25 85 --------- ---------- ---------- --------- -------- --------- Total revenue 6,413 1,762 8,175 5,588 1,874 7,462 ------ ------ ------ ------ ------ ------ Production operating expense 2,402 563 2,965 2,182 581 2,763 General and administrative expense 914 243 1,157 699 210 909 Interest expense 1,141 154 1,295 699 122 821 Depreciation, depletion and amortization 2,744 693 3,437 1,939 592 2,531 ------ ------- ------ ------ ------- ------ Total expense 7,201 1,653 8,854 5,519 1,505 7,024 ------ ------ ------ ------ ------ ------ Income (loss) before income taxes (788) 109 (679) 69 369 438 ------- ------- ------- -------- ------- ------- Provision for income taxes: Current 38 38 123 123 -------- -------- ------- ------- Net income (loss) $ (826) $ 109 $ (717) $ (54) $ 369 $ 315 ======= ======= ======= ======= ======= =======
First Quarter of 1999 Compared to the First Quarter of 1998 Gas Revenue Gas revenue increased $895,000 during the first quarter of 1999 compared with the first quarter of 1998. The increase is comprised of an increase in gas production from 2,240,000 mcf in 1998 to 2,937,000 mcf in 1999 partially offset by a decrease in price from $1.93 per mcf in 1998 to $1.77 per mcf in 1999. The increase in production is primarily due to the acquisition of a volumetric production payment during May 1998. The effect of the Company's hedging transactions, as described under "Inflation and Changing Prices," during the first quarter of 1999 was to increase the Company's average gas price from $1.61 to $1.77 per mcf, resulting in a $470,000 increase in revenue. Oil Revenue Oil revenue decreased $682,000 during the first quarter of 1999 as compared with the first quarter of 1998. The decrease in revenue is due to a decrease in the average oil price from $15.08 per barrel in 1998 to $11.34 per barrel in 1999. Production remained consistent at 182,000 barrels in 1998 and in 1999 because normal production declines were offset by increased production from drilling and recompletion projects. The effect of HCRC's hedging transactions during the first quarter of 1999, was to increase the Company's average oil price from $11.20 per barrel to $11.34 per barrel, resulting in a $25,000 increase in revenue. Pipeline and Other Pipeline and other revenue consists of revenue derived from salt water disposal, incentive and tax credit payments from certain coal bed methane wells and other miscellaneous items. Pipeline and other revenue increased $560,000 during the first quarter of 1999 compared with the first quarter of 1998 due to increased incentive payment income resulting from HCRC's acquisition of a volumetric production payment during May 1998. Interest Income Interest income decreased $60,000 during the first quarter of 1999 compared with the first quarter of 1998 due to a lower average cash balance during 1999. Production Operating Expense Production operating expense increased $202,000 during the first quarter of 1999 compared with the first quarter of 1998, primarily as a result of increased production taxes and operating expenses due to the increase in gas production as discussed above. General and Administrative 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, an affiliate of HCRC, which manages and operates certain oil and gas properties on behalf of the Company. These costs increased $248,000 during the first quarter of 1999 as compared with the first quarter of 1998 primarily due to an increase in salaries expense. Interest Expense Interest expense increased $474,000 during the first quarter of 1999 compared with the first quarter of 1998 due to a higher average outstanding debt balance during 1999. Depreciation, Depletion and Amortization Expense Depreciation, depletion and amortization expense increased $906,000 primarily due to a higher depletion rate in 1999 resulting from the increase in gas production previously discussed, as well as higher capitalized costs. ITEM 3 - 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 the Company's estimated debt levels and 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. 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 March 31, 1999, HCRC's debt consists of $26.5 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 $398,000 during the remaining nine months of 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 $225,000 increase in income and cash flows associated with the interest rate swap and collar agreements that are in effect for the remaining nine months of 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 March 31, 1999. 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 May 3, 1999, HCRC had entered into derivative commodity hedges covering an aggregate of 135,000 barrels of oil and 12,903,000 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 March 31, 1999 would cause a loss in income and cash flows of $2,060,000 during the remaining nine months of 1999, assuming that oil and gas production remain at levels consistent with those during the last nine months of 1998. This loss in income and cash flows would be offset by a $792,000 increase in income and cash flows associated with the oil and natural gas derivative contracts that are in effect for the remaining nine months of 1999. PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS Reference is made to Item 8 - Note 14 of Form 10-K for the year ended December 31, 1998 and Note 7 of this Form 10-Q. ITEM 2 - CHANGES IN SECURITIES None. ITEM 3 - DEFAULTS UPON SENIOR SECURITIES None. ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. ITEM 5 - OTHER INFORMATION None. ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K a) Exhibit 27 Financial Data Schedule b) Reports on Form 8-K None. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. HALLWOOD CONSOLIDATED RESOURCES CORPORATION Date: May 11, 1999 By: /s/Thomas J. Jung Thomas J. Jung, Vice President (Chief Financial Officer) EX-27 2 FDS HALLWOOD CONSOLIDATED RESOURCES 3/31/99 10-Q
5 This schedule contains summary financial information extracted from Form 10-Q for the three months ended March 31, 1999 for Hallwood Consolidated Resources Corporation and is qualified in its entirety by reference to such Form 10-Q. 0000883953 Hallwood Consolidated Resources Corporation 1,000 3-MOS DEC-31-1999 MAR-31-1999 181 0 7,868 0 0 11,948 342,864 255,641 100,439 19,546 0 0 0 30 28,842 100,439 8,150 8,175 0 2,965 0 0 1,295 (679) 38 (717) 0 0 0 (717) (.26) (.26)
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