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
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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
<S> <C> <C>
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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(Continued on the following page)
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<TABLE>
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HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except Shares)
March 31, December 31,
1999 1998
CURRENT LIABILITIES
<S> <C> <C>
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
======= =======
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The accompanying notes are an integral part of the
financial statements.
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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:
<S> <C> <C>
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
======= =======
</TABLE>
The accompanying notes are an integral part of the
financial statements.
<PAGE>
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HALLWOOD CONSOLIDATED RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
For the Three Months Ended
March 31,
1999 1998
OPERATING ACTIVITIES:
<S> <C> <C>
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
======= ======
</TABLE>
The accompanying notes are an integral part of the
financial statements.
<PAGE>
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.
<PAGE>
The following table reconciles the number of shares outstanding used in the
calculation of basic and diluted income (loss) per share.
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Income
(Loss) Shares Per Share
(In thousands except per Share)
For the Three Months Ended March 31, 1999
<S> <C> <C> <C>
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
==== ===== ====
</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 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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<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 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").
<PAGE>
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.
<PAGE>
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:
<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>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Oil Contract
Percent of Direct Delivered
Period Production Hedged Floor Price
(per bbl)
<S> <C> <C>
Last nine months of 1999 25% $14.74
</TABLE>
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.
<PAGE>
<TABLE>
<CAPTION>
Gas Contract
Percent of Direct Delivered
Period Production Hedged Floor Price
(per mcf)
<S> <C> <C>
Last nine months of 1999 49% $1.96
2000 41% 1.98
2001 46% 2.06
2002 32% 1.98
</TABLE>
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.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
(In thousands except price)
<PAGE>
For the Quarter Ended March 31, 1999 For the Quarter Ended March 31, 1998
---------------------------------- ------------------------------------
Direct Direct
Owned HEP Total Owned HEP Total
<S> <C> <C> <C> <C> <C> <C>
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
======= ======= ======= ======= ======= =======
</TABLE>
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<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, 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.
<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: May 11, 1999 By: /s/Thomas J. Jung
Thomas J. Jung, Vice President
(Chief Financial Officer)
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
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.
</LEGEND>
<CIK> 0000883953
<NAME> Hallwood Consolidated Resources Corporation
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 181
<SECURITIES> 0
<RECEIVABLES> 7,868
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 11,948
<PP&E> 342,864
<DEPRECIATION> 255,641
<TOTAL-ASSETS> 100,439
<CURRENT-LIABILITIES> 19,546
<BONDS> 0
0
0
<COMMON> 30
<OTHER-SE> 28,842
<TOTAL-LIABILITY-AND-EQUITY> 100,439
<SALES> 8,150
<TOTAL-REVENUES> 8,175
<CGS> 0
<TOTAL-COSTS> 2,965
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,295
<INCOME-PRETAX> (679)
<INCOME-TAX> 38
<INCOME-CONTINUING> (717)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (717)
<EPS-PRIMARY> (.26)
<EPS-DILUTED> (.26)
</TABLE>
