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 June 30, 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
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 August 14, 1998 3,007,852
Page 1 of 22
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<CAPTION>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
June 30, December 31,
1998 1997
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 1,745 $ 4,492
Accrued oil and gas revenue 3,248 4,266
Due from affiliates 3,726 2,418
Prepaid and other assets 1,143 844
Current assets of affiliates 3,728 3,854
--------- ---------
Total current assets 13,590 15,874
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost
Oil and gas properties (full cost method)
Proved oil and gas properties 318,396 294,922
Unproved mineral interests - domestic 2,781 2,250
--------- ---------
Total 321,177 297,172
Less - accumulated depreciation,
depletion, amortization and impairment (236,885) (221,141)
------- -------
Net property, plant and equipment 84,292 76,031
-------- --------
OTHER ASSETS
Deferred tax asset 450 450
Noncurrent assets of affiliate 6 16
----------- ----------
Total other assets 456 466
--------- ---------
TOTAL ASSETS $ 98,338 $ 92,371
======== ========
<FN>
(Continued on the following page)
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except Shares)
June 30, December 31,
1998 1997
CURRENT LIABILITIES
<S> <C> <C>
Accounts payable and accrued liabilities $ 2,584 $ 3,087
Current portion of long-term debt 1,063
Current portion of contract settlement obligation 1,039
Current liabilities of affiliates 7,362 6,881
--------- ---------
Total current liabilities 11,009 11,007
-------- -------
NONCURRENT LIABILITIES
Long-term debt 39,948 25,000
Long-term obligations of affiliates 7,652 7,589
Deferred liability 75 89
----------- -----------
Total noncurrent liabilities 47,675 32,678
-------- --------
Total liabilities 58,684 43,685
-------- --------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
STOCKHOLDERS' EQUITY
Common stock par value $.01; 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 (37,795) (27,581)
Treasury stock - 258,395 shares in 1998 and 259,278 shares in 1997 (3,864) (3,874)
--------- ---------
Stockholders' equity - Net 39,654 48,686
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 98,338 $ 92,371
======== ========
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
</TABLE>
<PAGE>
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<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Share data)
For the Three Months Ended
June 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $ 4,568 $ 3,360
Oil revenue 2,369 2,951
Pipeline and other 564 636
Interest income 60 77
--------- ---------
7,561 7,024
------- -------
EXPENSES:
Production operating 2,754 2,432
General and administrative 993 884
Interest 913 566
Depreciation, depletion and amortization 2,213 1,934
Impairment of oil and gas properties 11,000
Litigation settlement of affiliate 113
---------
17,986 5,816
------- -------
INCOME (LOSS) BEFORE INCOME TAXES (10,425) 1,208
------- -------
PROVISION FOR INCOME TAXES:
Current 104 56
--------- ---------
NET INCOME (LOSS) $(10,529) $ 1,152
======= =======
NET INCOME (LOSS) PER SHARE - BASIC $ (3.83) $ .42
========= ==========
NET INCOME (LOSS) PER SHARE - DILUTED $ (3.83) $ .41
========= ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
2,749 2,718
======= =======
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands except per Share data)
For the Six Months Ended
June 30,
1998 1997
REVENUES:
<S> <C> <C>
Gas revenue $ 8,880 $ 8,134
Oil revenue 5,114 6,865
Pipeline and other 884 1,043
Interest income 145 117
--------- ---------
15,023 16,159
------- -------
EXPENSES:
Production operating 5,517 4,947
General and administrative 1,902 1,785
Interest 1,734 1,162
Depreciation, depletion and amortization 4,744 4,001
Impairment of oil and gas properties 11,000
Litigation settlement of affiliate 113
---------
25,010 11,895
------- -------
INCOME (LOSS) BEFORE INCOME TAXES (9,987) 4,264
------- -------
PROVISION FOR INCOME TAXES:
Current 227 147
--------- --------
NET INCOME (LOSS) $(10,214) $ 4,117
======= =======
NET INCOME (LOSS) PER SHARE - BASIC $ (3.72) $ 1.51
========= ========
NET INCOME (LOSS) PER SHARE - DILUTED $ (3.72) $ 1.45
========= ========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
2,744 2,718
======= =======
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
For the Six Months Ended
June 30,
1998 1997
OPERATING ACTIVITIES:
<S> <C> <C>
Net income (loss) $(10,214) $ 4,117
Adjustments to reconcile net income (loss)
to net cash provided by operating activities:
Depreciation, depletion and amortization 4,744 4,001
Impairment of oil and gas properties 11,000
Amortization of deferred loan costs and warrants 43
Noncash interest expense 6 44
Undistributed earnings of affiliates (1,572) (2,131)
Recoupment of take-or-pay liability (14) (15)
Changes in assets and liabilities provided (used) cash net of noncash
activity:
Accrued oil and gas sales 1,018 1,590
Due from affiliates (1,041) (870)
Prepaid and other assets (299) 373
Accounts payable and accrued liabilities (503) 263
-------- --------
Net cash provided by operating activities 3,168 7,372
------- -------
INVESTING ACTIVITIES:
Additions to oil and gas properties (17,990) (1,498)
Exploration and development costs incurred (4,692) (3,102)
Proceeds from oil and gas property sales 90 26
Distributions received from affiliates 572 572
Other (11)
------------ ---------
Net cash used in investing activities (22,020) (4,013)
------- -------
FINANCING ACTIVITIES:
Exercise of stock options 150
Proceeds from long-term debt 17,000
Payments on long-term debt (3,000)
Payments on contract settlement obligation (1,045)
--------
Net cash provided by (used in)
financing activities 16,105 (3,000)
------- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS (2,747) 359
CASH AND CASH EQUIVALENTS:
BEGINNING OF PERIOD 4,492 628
------- -------
END OF PERIOD $ 1,745 $ 987
======= =======
<FN>
The accompanying notes are an integral part of the
financial statements.
</FN>
</TABLE>
<PAGE>
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
NOTES TO 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 December 31, 1997 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 June 30, 1998 and December 31, 1997, 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 and 259,278
of its own shares at June 30, 1998 and December 31, 1997, respectively. These
shares are treated as treasury stock in the accompanying financial statements.
Computation of Net Income (Loss) Per Share
During February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128 Earnings per Share ("SFAS 128"). SFAS
128 establishes standards for computing and presenting earnings per share (EPS),
and supersedes APB Opinion No. 15 and its related interpretations. It replaces
the presentation of primary EPS with a presentation of basic EPS, which excludes
dilution, and requires dual presentation of basic and diluted EPS for all
entities with complex capital structures. Diluted EPS is computed similarly to
fully diluted EPS pursuant to Opinion No. 15. SFAS 128 is effective for periods
ending after December 15, 1997, including interim periods, and requires
restatement of all prior period EPS data presented. HCRC adopted SFAS 128
effective December 31, 1997, and has restated all prior period EPS data
presented to give retroactive effect to the new accounting standard.
<PAGE>
Basic income (loss) per share is computed by dividing net income (loss) by the
weighted average number of common shares outstanding during the periods. Diluted
income (loss) per share includes the potential dilution that could occur upon
exercise of outstanding options to acquire common stock, and the effects of the
warrants described in Note 3, 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). All share and
per share information has been restated to reflect the three-for-one stock split
described in Note 5.
The following table reconciles the number of shares outstanding used in the
calculation of basic and diluted income (loss) per share. 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 in 1998 because their inclusion would be
anti-dilutive.
<TABLE>
<CAPTION>
Income (Loss)
Shares Per Share
(In thousands except per Share)
For the Three Months Ended June 30, 1998
<S> <C> <C> <C>
Net loss per share - basic $(10,529) 2,749 $(3.83)
------- ----- =====
Net Loss per share - diluted $(10,529) 2,749 $(3.83)
======= ===== =====
For the Six Months Ended June 30, 1998
Net loss per share - basic $(10,214) 2,744 $(3.72)
------- ----- =====
Net Loss per share - diluted $(10,214) 2,744 $(3.72)
======= ===== =====
For the Three Months Ended June 30, 1997
Net income per share - basic $ 1,152 2,718 $ .42
=======
Effect of Options 113
------------ ------
Net Income per share - diluted $ 1,152 2,831 $ .41
======= ===== =======
For the Six Months Ended June 30, 1997
Net income per share - basic $ 4,117 2,718 $ 1.51
======
Effect of Options 117
------------ ------
Net Income per share - diluted $ 4,117 2,835 $ 1.45
======= ===== ======
</TABLE>
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 three and six month periods ended
June 30, 1998 and 1997. Therefore, total comprehensive income (loss) was the
same as net income (loss) for those periods.
During 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 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 a financial institution. HCRC
also sold Warrants to the lender 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 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 $22,000,000. The Company had amounts outstanding of
$17,000,000 as of June 30, 1998. HCRC's unused borrowing base totaled $5,000,000
at August 14, 1998.
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 7.2% at June 30,
1998. Interest is payable at least quarterly, and quarterly principal payments
of $1,063,000 commence May 31, 1999. The credit facility is secured by a first
lien on approximately 80% in value of the Company's oil and gas properties.
HCRC entered into contracts to hedge its interest rate payments on $10,000,000
of its debt for 1998 and $5,000,000 for each of 1999 and 2000. HCRC does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HCRC's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HCRC's
goal to hedge 50% of the principal amount of its debt under the Credit Agreement
for the next two years and 25% for each year of the remaining term of the debt.
HCRC has entered into four hedges, one of which is an interest rate collar
pursuant to which it pays a floor rate of 7.55% and a ceiling rate of 9.85%, and
the others are interest rate swaps with fixed rates ranging from 5.75% to 6.57%.
The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.
NOTE 4 - STATEMENTS OF CASH FLOWS
Cash paid for interest during the six months ended June 30, 1998 and 1997 was
$1,635,000 and $772,000, respectively.
<PAGE>
NOTE 5 - 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.
NOTE 6 - ACQUISITION
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
Enron. HCRC funded its $17,257,000 share of the acquisition price from operating
cash flow and borrowings under its Credit Agreement.
NOTE 7 - IMPAIRMENT OF OIL AND GAS PROPERTIES
During the second quarter of 1998, HEP recorded an impairment of its oil and gas
properties because capitalized costs at June 30, 1998 exceeded the present value
(discounted at 10%) of estimated future net revenues from proved oil and gas
reserves, based on prices at that date of $13.00 per barrel of oil and $1.90 per
mcf of gas.
NOTE 8 - STOCK OPTION GRANT
On May 5, 1998, HCRC granted options for 9,540 shares of Common Stock at an
exercise price of $15.75 per share. 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.
On May 5, 1998, HCRC also granted options for 9,540 shares of Common Stock under
its 1997 Stock Option Plan at an exercise price of $15.75. 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.
NOTE 9 - LEGAL PROCEEDINGS
On December 3, 1997, Arcadia Exploration and Production Company ("Arcadia")
filed a Demand for Arbitration 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 herein as "Hallwood"), claiming that Hallwood breached
a Purchase and Sale Agreement dated August 25, 1997, between Arcadia and HCRC
and HEP. Arcadia's Demand for Arbitration seeks specific performance of the
agreement which Arcadia claims requires Hallwood to purchase oil and gas
properties from Arcadia for approximately $27 million. HCRC and HEP terminated
the agreement because of environmental and title problems with the properties.
Additionally, Arcadia seeks incidental and special damages, prejudgment interest
and attorneys' fees and costs. Hallwood filed its Answering Statement and
Counterclaim asserting that it properly terminated and/or rescinded the
Agreement and seeking refund of Hallwood's earnest money deposit, prejudgment
interest, attorneys' fees and costs. This matter was heard by the arbitrators
during May and July 1998. The arbitrators have not yet rendered a decision.
<PAGE>
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 seeks to rescind the conversion of Hallwood Consolidated Partners, L.P.
("HCP") into the Company ("Conversion") and to recover damages in unspecified
amounts. The plaintiff also seeks class certification to represent similarly
situated HCP unitholders. In general, the suit alleges that the defendants
breached fiduciary duties to HCP unitholders by, among other things, proposing
allocation of common stock in the Conversion on a basis that the plaintiff
alleges is unfair, failing to require that the allocation be approved by an
independent third party, causing the costs of proposing the Conversion to be
borne indirectly by the partners of HCP whether or not the Conversion was
completed, and failing to disclose certain matters in the Consent
Statement/Prospectus soliciting consents to the Conversion. The defendants
believe that they fully considered and disclosed all material information in
connection with the Conversion, and they believe that the suit is without merit.
HCRC plans to vigorously defend this case, but because of its early stages,
cannot predict the outcome of this matter or any possible effect an adverse
outcome might have.
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.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Liquidity and Capital Resources
Cash Flow
The Company generated $3,168,000 of cash flow from operating activities during
the first six months of 1998. The other primary cash inflows were $17,000,000 in
proceeds from long-term debt and $572,000 in distributions received from
affiliates. Cash was primarily used for additions to property and exploration
and development costs of $22,682,000 and for payments on contract settlement
obligation of $1,045,000 for the six months ended June 30, 1998, resulting in a
$2,747,000 decrease in cash from $4,492,000 at December 31, 1997 to $1,745,000
at June 30, 1998.
Exploration and Development Projects and Acquisitions
Through June 30, 1998, HCRC incurred $22,682,000 in direct property additions,
development, exploitation, and exploration costs. The costs were comprised of
$17,990,000 for property acquisitions and approximately $4,692,000 for domestic
exploration and development expenditures. The expenditures resulted in the
drilling, recompletion or workover of 26 development wells and 22 exploration
wells. Twenty-four development wells (92%) and 14 exploration wells (64%) were
successfully completed as producers, for an overall success rate of 79%. HCRC's
1998 capital budget was initially set at $21,426,000 but was increased to
$33,426,000 to allow for the purchase of the volumetric production payment
discussed below. The remaining budget for 1998 includes 39 future projects in
more than 21 areas. Significant acquisition, exploration, exploitation, and
development projects for 1998 are discussed below.
Rocky Mountain Region
HCRC expended approximately $18,610,000 of its capital budget in the Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and Wyoming. Of this amount, approximately $17,257,000 was for the purchase of
the volumetric production payment discussed below. In 1998, HCRC spent
approximately $1,070,000 successfully recompleting five operated development
wells, drilling one unsuccessful operated exploration well, and drilling three
additional operated wells which are still underway. A discussion of the major
projects in the Region follows.
San Juan Basin Project - Colorado. 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
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 from Enron
the volumetric production payment. HCRC funded its $17,257,000 share of the
acquisition price from operating cash flow and borrowings under its Credit
Agreement. 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 was
already responsible for all costs associated with the wells. HPI has managed and
operated the wells since July 1996, and has increased the wells' production from
14 to 26 mmcf per day through successful workover and gas gathering facilities
improvement programs. The acquisition has increased HCRC's current average daily
production by 6.75 mmcf per day.
Colorado Western Slope Project. HCRC is in the process of drilling two 5,500
foot Dakota Formation wells in the Piceance Basin in Colorado and Utah. Both
wells are presently being completed, and HCRC expects to begin sales of
production in the third quarter of 1998. Currently, HCRC owns an average 46%
working interest in the wells. In 1998, HCRC also successfully recompleted one
well in the Basin. Total costs for the three wells through June 30, 1998 are
approximately $517,000. HCRC has plans to drill two more wells in 1998 depending
upon drilling rig availability. Increased natural gas prices and improved
stimulation technology make the Basin an attractive area for HCRC.
West Sioux Pass Prospect. In the West Sioux area of Richland County, Montana,
HCRC drilled one unsuccessful 12,405 foot operated Red River Formation
exploration well for a cost of approximately $252,000. HCRC continues to
evaluate the project using the additional data obtained from the exploratory
well.
East Kevin Field Project. Drilling is currently underway for one operated
development well in the Horizontal Nisku Formation in Toole County, Montana.
HCRC has a 50% working interest in the project and has spent approximately
$170,000 in 1998. HCRC plans to drill two additional wells in the third quarter
of 1998. HCRC will consider drilling additional locations after it evaluates the
results of the first three wells.
Greater Permian Region
During the first six months of 1998, HCRC expended approximately $2,555,000 of
its capital budget in the Greater Permian Region located in Texas and Southeast
New Mexico. HCRC spent approximately $1,765,000 for drilling, recompletion, or
workover of 17 development wells, drilling 17 exploration wells, and acquiring
undeveloped acreage and geological and geophysical data. Twenty-six (76%) of the
wells drilled or recompleted were successful. The major projects within the
Region are discussed below.
Catclaw Draw/Carlsbad Area Projects. HCRC spent approximately $141,000
successfully recompleting six operated wells in the Carlsbad/Catclaw Draw areas
in Lea, Eddy and Chaves Counties, New Mexico. HCRC incurred an additional
$250,000 in 1998 for drilling costs associated with an operated 8,300 foot
Delaware development well which is currently being tested. Several additional
drilling locations exist in the area. HCRC plans to apply for drilling permits
in 1998 and to drill the wells in 1999.
Merkle Project. In 1997, HCRC acquired 74 square miles of proprietary 3-D
seismic data in Jones, Taylor and Nolan Counties, Texas, in a project area
originated in 1995. Target zones in this area include the Canyon Reef, Strawn,
Flippan, Tannehill, and Ellenberger Formations ranging in depth from 2,500 feet
to 6,000 feet. In 1998, HCRC drilled 11 exploration wells, nine of which were
successful. Costs incurred by HCRC in 1998 for the 11 wells drilled were
approximately $905,000. HCRC owns an average 30% working interest in the wells.
Four wells are currently underway, and HCRC has 33 potential locations for
future drilling. HCRC anticipates drilling only four additional wells in the
remainder of 1998 because of present low crude oil prices.
Griffin Project. In 1998, HCRC purchased land for $95,000 and incurred
approximately $443,000 to drill three exploration wells and one development well
in Gaines County, Texas. None of the four nonoperated 7,500 foot Leonardian Sand
wells were successful. HCRC is still evaluating five prospects within this
project. HCRC owns an average 25% working interest in the wells.
Gulf Coast Region
During the first six months of 1998, HCRC expended approximately $835,000 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. In 1998, HCRC incurred approximately $430,000 for land costs
related to the Mirasoles project in Kenedy County, Texas. In the third quarter
of 1998, HCRC plans to test the Frio Formation by drilling a 17,000 foot
exploration well. HCRC has a 17.5% working interest in this large structural
prospect defined by 63 square miles of proprietary 3-D seismic data.
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
$350,000. The well found the shallower reservoirs to be non-productive, and HCRC
is presently drilling in the Buda section. In 1998, HCRC incurred an additional
$70,000 for the purchase of land.
Mid-Continent Region
HCRC expended approximately $485,000 of its capital budget in the Mid-Continent
Region located in Oklahoma and Kansas. Major projects within the Region are
discussed below.
Stealth Project. HCRC is participating in an Arkoma Basin exploration prospect
in Carter County, Oklahoma. This nonoperated project is a 19,000 feet deep
multi-formation structural test of the Hunton, Viola, Sycamore, and Springer
Formations and is currently in the completion phase. The operator was unable to
test the targeted Hunton and Viola Formation objectives and found that the
Sycamore produced at subcommercial gas rates. The operator is evaluating a
Springer recompletion. 1998 year to date drilling costs were approximately
$165,000 for HCRC's 5% working interest.
El Reno Project. HCRC incurred approximately $135,000 in 1998 to complete one
successful exploration well in Canadian County, Oklahoma. The well was completed
in the Red Fork Formation, and HCRC has a 35% working interest.
Kansas Area. HCRC successfully recompleted two development wells in Kansas at a
cost of $46,000 during 1998. Due to sustained weak crude oil prices, however,
eight development projects have been deferred.
Other
The remaining $197,000 of HCRC's 1998 capital expenditures was devoted
principally to drilling one unsuccessful exploration well in Yolo County,
California and to other miscellaneous projects. HCRC is also participating in
two nonoperated 3-D projects underway in nearby Solano and Colusa Counties,
California.
Peru Block Z-3 Project. HCRC's partner on the Peruvian offshore Z-3 Block
completed 1,200 miles of seismic data acquisition to supplement existing seismic
data. Data processing is currently underway. HCRC has a 7.5% working interest in
this project, but will not incur capital costs until actual drilling operations
begin. The production-sharing contract calls for drilling operations to begin no
later than January 2001.
Financing
On December 23, 1997, HCRC sold $25,000,000 of 10.32% Senior Subordinated Notes
("Subordinated Notes") due December 23, 2007 to a financial institution. HCRC
also sold Warrants to the lender 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.
<PAGE>
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 $22,000,000. The Company had amounts outstanding of
$17,000,000 as of June 30, 1998. HCRC's unused borrowing base totaled $5,000,000
at August 14, 1998.
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 7.2% at June 30,
1998. Interest is payable at least quarterly and quarterly principal payments of
$1,063,000 commence May 31, 1999. The credit facility is secured by a first lien
on approximately 80% in value of the Company's oil and gas properties.
HCRC entered into contracts to hedge its interest rate payments on $10,000,000
of its debt for 1998 and $5,000,000 for each of 1999 and 2000. HCRC does not use
the hedges for trading purposes, but rather for the purpose of providing a
measure of predictability for a portion of HCRC's interest payments under its
Credit Agreement, which has a floating interest rate. In general, it is HCRC's
goal to hedge 50% of the principal amount of its debt under its Credit Agreement
for the next two years and 25% for each year of the remaining term of the debt.
HCRC has entered into four hedges, one of which is an interest rate collar
pursuant to which it pays a floor rate of 7.55% and a ceiling rate of 9.85%, and
the others are interest rate swaps with fixed rates ranging from 5.75% to 6.57%.
The amounts received or paid upon settlement of these transactions are
recognized as interest expense at the time the interest payments are due.
Cautionary Statement Regarding Forward Looking Statements
In the interest of providing the Company's stockholders and potential investors
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 meaning 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 Company, expected to prove true and to 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 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, stockholders and potential
investors are cautioned that certain events or circumstances could cause actual
results to differ materially from those projected, estimated or predicted.
<PAGE>
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 1997 and through
the second quarter of 1998. The following table sets forth the weighted average
price received each quarter by the Company and the effects of the hedging
transactions described below:
<PAGE>
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
First quarter 1997 $23.56 $20.49 $2.64 $2.41
Second quarter 1997 17.85 17.88 1.91 1.87
Third quarter 1997 18.20 18.31 2.09 1.96
Fourth quarter 1997 18.60 18.60 2.72 2.38
First quarter 1998 14.92 15.08 1.98 1.93
Second quarter 1998 13.06 13.38 1.90 1.89
</TABLE>
The Company has entered 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 these contracts are recognized as oil or gas revenue at the
time the hedged volumes are sold.
The following table provides a summary of the Company's outstanding financial
contracts:
<TABLE>
<CAPTION>
Oil
Percent of Direct Contract
Period Production Hedged Floor Price
(per bbl)
<S> <C> <C>
Last six months of 1998 14% $14.57
1999 5% 15.38
</TABLE>
Between 30% and 100% of the oil volumes hedged in each year are subject to a
participating hedge 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 each year 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 $17.00 to $18.85 per barrel.
<PAGE>
<TABLE>
<CAPTION>
Gas
Percent of Direct Contract
Period Production Hedged Floor Price
(per mcf)
<S> <C> <C>
Last six months of 1998 51% $2.03
1999 42% 1.97
2000 40% 2.02
2001 39% 2.00
2002 38% 2.06
</TABLE>
Between 0% and 16% of the gas volumes hedged in each year 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 price is $2.93 per mcf.
During the third quarter through August 2, 1998, the weighted average oil price
(for barrels not hedged) was approximately $12.50 per barrel and the weighted
average price of natural gas (for mcf not hedged) was approximately $2.05 per
mcf.
Inflation
Inflation is not anticipated to have a material impact on the Company in 1998.
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 1997 and 1998.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
<PAGE>
For the Quarter Ended June 30, 1998 For the Quarter Ended June 30, 1997
----------------------------------- -----------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 1,835 583 2,418 1,365 433 1,798
Oil production (bbl) 143 34 177 134 31 165
Average gas price (per mcf) $ 1.87 $ 1.96 $ 1.89 $ 1.84 $ 1.96 $ 1.87
Average oil price (per bbl) $13.27 $13.88 $13.38 $17.96 $17.58 $17.88
Gas revenue $ 3,427 $ 1,141 $ 4,568 $ 2,513 $ 847 $ 3,360
Oil revenue 1,897 472 2,369 2,406 545 2,951
Pipeline and other 385 179 564 442 194 636
Interest income 26 34 60 53 24 77
--------- --------- --------- --------- --------- ---------
Total revenue 5,735 1,826 7,561 5,414 1,610 7,024
-------- ------- -------- ------- ------- -------
Production operating expense 2,196 558 2,754 1,941 491 2,432
General and administrative expense 795 198 993 696 188 884
Interest expense 810 103 913 414 152 566
Depreciation, depletion and amortization 1,714 499 2,213 1,661 273 1,934
Impairment of oil and gas properties 11,000 11,000
Litigation settlement of affiliate 113 113
----------- --------- ---------
Total expense 16,515 1,471 17,986 4,712 1,104 5,816
------- ------- ------- ------- ------- -------
Income (loss) before income taxes (10,780) 355 (10,425) 702 506 1,208
------- -------- ------- -------- -------- -------
Provision for income taxes:
Current 104 104 56 56
-------- --------- --------- ---------
Net income (loss) $(10,884) $ 355 $(10,529) $ 646 $ 506 $ 1,152
======= ======== ======= ======= ======== =======
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
<PAGE>
For the Six Months Ended June 30, 1998 For the Six Months Ended June 30, 1997
-------------------------------------- --------------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
Gas production (mcf) 3,508 1,150 4,658 2,835 942 3,777
Oil production (bbl) 289 70 359 287 69 356
Average gas price (per mcf) $ 1.88 $ 2.00 $ 1.91 $ 2.13 $ 2.22 $ 2.15
Average oil price (per bbl) $14.16 $14.61 $14.25 $19.29 $19.26 $19.28
Gas revenue $ 6,578 $ 2,302 $ 8,880 $ 6,044 $ 2,090 $ 8,134
Oil revenue 4,091 1,023 5,114 5,536 1,329 6,865
Pipeline and other 568 316 884 709 334 1,043
Interest income 86 59 145 71 46 117
---------- --------- -------- -------- -------- --------
Total revenue 11,323 3,700 15,023 12,360 3,799 16,159
------- ------- ------- ------- ------- -------
Production operating expense 4,378 1,139 5,517 3,918 1,029 4,947
General and administrative expense 1,494 408 1,902 1,375 410 1,785
Interest expense 1,509 225 1,734 860 302 1,162
Depreciation, depletion and amortization 3,653 1,091 4,744 3,240 761 4,001
Impairment of oil and gas properties 11,000 11,000
Litigation settlement of affiliate 113 113
--------- --------- ---------
Total expense 22,034 2,976 25,010 9,393 2,502 11,895
------- ------- ------- ------- ------- -------
Income (loss) before income taxes (10,711) 724 (9,987) 2,967 1,297 4,264
------- --------- -------- ------- ------- -------
Provision for income taxes:
Current 227 227 147 147
--------- --------- --------- ---------
Net income (loss) $(10,938)$ 724 $(10,214) $ 2,820 $ 1,297 $ 4,117
======= ========= ======= ======= ======= =======
</TABLE>
<PAGE>
Second Quarter of 1998 Compared to the Second Quarter of 1997
Gas Revenue
Gas revenue increased $1,208,000 during the second quarter of 1998 as compared
with the second quarter of 1997. The increase is comprised of an increase in
price from $1.87 per mcf in 1997 to $1.89 per mcf in 1998 and an increase in gas
production from 1,798,000 mcf in 1997 to 2,418,000 mcf in 1998. The increase in
production is primarily due to the temporary shut-in of two wells in Louisiana
during the second quarter of 1997 while workover procedures were performed.
The effect of the Company's hedging transactions, as described under "Inflation
and Changing Prices," during the second quarter of 1998 was to decrease the
Company's average gas price from $1.90 to $1.89 per mcf, resulting in a $24,000
decrease in revenue.
Oil Revenue
Oil revenue decreased $582,000 during the second quarter of 1998 as compared
with the second quarter of 1997. The decrease in revenue is comprised of a
decrease in the average oil price from $17.88 per barrel in 1997 to $13.38 per
barrel in 1998, partially offset by an increase in production from 165,000
barrels in 1997 to 177,000 barrels in 1998. The increase in production is
primarily due to the temporary shut-in of two wells in Louisiana during the
second quarter of 1997 while workover procedures were performed.
The effect of HCRC's hedging transactions during the second quarter of 1998, was
to increase the Company's average oil price from $13.06 per barrel to $13.38 per
barrel, resulting in a $57,000 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 decreased $72,000 during the
second quarter of 1998 as compared with the second quarter of 1997 due to
fluctuations in numerous miscellaneous items, none of which are individually
significant.
Interest Income
Interest income decreased $17,000 during the second quarter of 1998 as compared
with the second quarter of 1997 due to a lower average cash balance during 1998.
Production Operating Expense
Production operating expense increased $322,000 during the second quarter of
1998 as compared with the second quarter of 1997, primarily as a result of
increased production taxes due to the increase in oil and 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 Hallwood Petroleum, Inc. ("HPI"), an
affiliate of HCRC, which manages and operates certain oil and gas properties on
behalf of the Company. These costs increased $109,000 during the second quarter
of 1998 as compared with the second quarter of 1997 primarily due to an increase
in salaries expense.
Interest Expense
Interest expense increased $347,000 during the second quarter of 1998 as
compared with the second quarter of 1997 due to a higher outstanding debt
balance during 1998.
Depreciation, Depletion and Amortization Expense
Depreciation, depletion and amortization expense increased $279,000 primarily
due to a higher depletion rate in 1998 resulting from the increase in oil and
gas production previously discussed.
Impairment of Oil and Gas Properties
Impairment of oil and gas properties during the second quarter of 1998
represents the impairment recorded because capitalized costs at June 30, 1998
exceeded the present value (discounted at 10%) of estimated future net revenues
from proved oil and gas reserves, based on prices at that date of $13.00 per bbl
of oil and $1.90 per mcf of gas.
Litigation Settlement of Affiliate
Litigation settlement of affiliate during the second quarter of 1998 is
comprised of HCRC's pro rata share of HEP's litigation settlement expense
accrued for the settlement of a property related lawsuit.
First Six Months of 1998 compared to the First Six Months of 1997
The comparisons for the first six months of 1998 and the first six months of
1997 are consistent with those discussed in the second quarter of 1998 compared
to the second quarter 1997 except for the following:
Gas Revenue
Gas revenue increased $746,000 during the first six months of 1998 as compared
with the first six months of 1997. The increase is comprised of an increase in
production from 3,777,000 mcf in 1997 to 4,658,000 mcf in 1998, partially offset
by a decrease in the average price from $2.15 per mcf to $1.91 per mcf. The
production increase is due to the temporary shut-in of two wells in Louisiana
while workover procedures were performed during the second quarter of 1997.
The effect of HCRC's hedging transactions was to decrease HCRC's average gas
price from $1.94 per mcf to $1.91 per mcf, representing a $140,000 reduction in
revenue from hedging transactions.
Oil Revenue
Oil revenue decreased $1,751,000 during the first six months of 1998 as compared
with the first six months of 1997. The decrease is comprised of a decrease in
the average oil price from $19.28 per barrel in 1997 to $14.25 per barrel in
1998, partially offset by an increase in production from 356,000 barrels in 1997
to 359,000 barrels in 1998. The production increase is due to the temporary
shut-in of two wells in Louisiana while workover procedures were performed
during the second quarter of 1997.
The effect of HCRC's hedging transactions was to increase HCRC's average oil
price from $13.97 per barrel to $14.25 per barrel, representing a $101,000
increase in revenues.
<PAGE>
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, 1997 and Note 9 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) Exhibits
10.19 Option Letter to Thomas Jung dated May 5, 1998
10.20 Extension of Management Agreement between Hallwood Petroleum, Inc.
and HEP dated May 5, 1998
27 Financial Data Schedule
b) Reports on Form 8-K
None.
<PAGE>
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: August 14,1998 By: /s/Thomas J. Jung
Thomas J. Jung, Vice President
(Chief Financial Officer)
May 5, 1998
Mr. Thomas J. Jung
7644 S. Madison Circle
Littleton, Colorado 80112
Re: Options for Shares of Common Stock
Dear Mr. Jung:
As we discussed, in connection with your recent employment by Hallwood
Petroleum, Inc., Hallwood Consolidated Resources Corporation (the "Company")
hereby grants you, effective as of the date of this letter, an option (the
"Option") to acquire Nine Thousand Five Hundred Forty (9,540) shares of the
common stock of the Company.
Although your Option has not been granted pursuant to a previously existing
option plan, your Option will be subject to terms and conditions identical to
those in the Company's 1995 Share Option Plan (the "Option Plan"), and the
associated 1995 Share Option Plan Loan Program (the "Loan Program"). We have
enclosed copies of the Option Plan and the Loan Program for your reference and
review. The following is a description of the Option. Terms not otherwise
defined in this letter have the same meanings ascribed to them in the Option
Plan. You are referred to as the Optionee in the following description.
1. Option Price. The Option price is $15 3/4 for each Share.
2. Date of Grant. The Option is granted as of May 5, 1998 (the "Date of
Grant").
3. Exercise of Option. The Option shall be exercisable in whole or in part
in accordance with the provisions of the Option Plan as follows:
(i) Schedule of Rights to Exercise.
(a) 3180 Shares upon the Date of Grant,
(b) 3180 Shares after May 5, 1999,
(c) 3180 Shares after May 5, 2000,
or on such earlier date as the Option may vest in accordance with Section 7(d)
of the Option Plan, but subject always to the limits set forth in Section 7(e)
of the Option Plan.
(ii) Method of Exercise. The Option shall be exercisable by a written
notice delivered to the Company that shall:
(a) state the election to exercise the Option and the number of
Shares in respect of which it is being exercised; and
(b) be signed by the person or persons entitled to exercise the
Option and, if the Option is being exercised by any person or persons
other than the Optionee, be accompanied by proof, satisfactory to the
Company, of the right of such person or persons to exercise the
Option.
(iii) Payment. The exercise price of any Shares purchased shall be
paid solely in cash, by certified or cashier's check, by money order, with
Shares (provided that at the time of exercise the Committee in its sole
discretion does not prohibit the exercise of Options through the delivery
of Shares owned by the Optionee for at least six months) or by a
combination of the above; provided, however, that the Committee in its sole
discretion may accept a personal check in full or partial payment of any
Shares. If the exercise price is paid in whole or in part with Shares, the
value of the Shares surrendered shall be their Fair Market Value on the
date received by the Company. Any Shares delivered in satisfaction of all
or a portion of the exercise price shall be appropriately endorsed for
transfer and assignment to the Company.
(iv) Withholding. The Optionee shall make arrangements satisfactory to
the Company for the withholding of any amounts necessary for withholding in
accordance with applicable Federal or state income tax laws.
(v) Issuance of Shares. No person shall be, or have any of the rights
or privileges of, a Shareholder of the Company with respect to any of the
Shares subject to an Option unless and until certificates representing such
Shares shall have been issued and delivered to such person. As a condition
of any issuance of a certificate for Shares, the Committee may obtain such
agreements or undertakings, if any, as it may deem necessary or advisable
to assure compliance with any provision of the Plan, the agreement
evidencing the Option or any law or regulation including, but not limited
to, the following:
(a) A representation, warranty or agreement by the Optionee to
the Company at the time any Option is exercised that he is acquiring
the Shares to be issued to him for investment and not with a view to,
or for sale in connection with, the distribution of any such Shares;
and
(b) A representation, warranty or agreement to be bound by any
legends that are, in the opinion of the Committee, necessary or
appropriate to comply with the provisions of any securities laws
deemed by the Committee to be applicable to the issuance of the Shares
and are endorsed upon the Share certificates.
(vi) Surrender of Option. Upon exercise of Option in part, if
requested by the Company, the Optionee shall deliver Option and any other
written agreements executed by the Company and the Optionee with respect to
Option to the Company who shall endorse or cause to be endorsed thereon a
notation of such exercise and return all agreements to the Optionee.
4. Transferability of Option. In the Optionee's discretion, The Option may
be transferred by the Optionee by gift or by contribution to (a) any member of
Optionee's immediate family; (b) any entity of which Optionee or members of
Optionee's family are the sole equity owners or beneficiaries or, if there are
discretionary beneficiaries, among the class of discretionary beneficiaries; or
(c) any combination of the foregoing.
5. Term of Option. The Option may not be exercised after the expiration of
ten (10) years from the Date of Grant of the Option and is subject to earlier
termination as provided in Section 8 of the Plan. The Option may be exercised
during such term only in accordance with the Plan and the terms of the Option.
6. Administration. The Option shall be administered by the Committee
provided for and described in Section 13 of the Plan.
If this letter agreement correctly sets forth your understanding regarding
the Options, please acknowledge and accept the award by signing in the space
provided below.
Sincerely,
HALLWOOD CONSOLIDATED
RESOURCES CORPORATION
/s/Russell P. Meduna
Russell P. Meduna
Executive Vice President
<PAGE>
I acknowledge receipt of the letter dated May 5, 1998 regarding the award
of a Share Option, a copy of the 1995 Option Plan and the Loan Program, and
represent that I am familiar with the terms and provisions thereof, and hereby
accept the Option subject to all the terms and provisions of this letter, the
Option Plan and the Loan Program. I hereby agree to accept as binding,
conclusive and final all decisions or interpretations of the Committee (as
defined in the Option Plan ) upon any questions arising under my Option.
- ----------------- --------------------------
Date Thomas J. Jung
EXTENSION OF MANAGEMENT AGREEMENT
This Extension of Management Agreement dated May 5, 1998 is between
Hallwood Petroleum, Inc. ("HPI") and Hallwood Consolidated Resources Corporation
("HCRC").
Whereas, HPI and HCRC are parties to a Management Agreement dated May 18,
1992, and
Whereas, the Management Agreement provided that it may be extended for
successive one year terms by written agreement of the parties, and
Whereas, the parties desire to extend the Management Agreement until May
18, 1999,
Now, therefore, in consideration of the mutual agreements contained herein,
the parties agree that the term of the Management Agreement is extended to May
18, 1999.
HALLWOOD PETROLEUM, INC.
By: /s/Russell P. Meduna
Russell P. Meduna
Executive Vice President
HALLWOOD CONSOLIDATED RESOURCES CORPORATION
By: /s/William L. Guzzetti
William L. Guzzetti
President
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from Form 10-Q
for the quarter ended June 30, 1998 for Hallwood Consolidated Resources
Corporation and is qualified in its entirety by reference to such Form 10-Q.
</LEGEND>
<CIK> 0000883953
<NAME> Hallwood Consolidated Resources Corporation
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> Jun-30-1998
<CASH> 1,745
<SECURITIES> 0
<RECEIVABLES> 6,974
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0
0
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</TABLE>
