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 September 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 November 13, 1998               3,007,852













                                  Page 1 of 24

<TABLE>
<CAPTION>

PART I.    FINANCIAL INFORMATION
ITEM 1.    FINANCIAL STATEMENTS

                                    HALLWOOD CONSOLIDATED RESOURCES CORPORATION
                                            CONSOLIDATED BALANCE SHEETS
                                                    (Unaudited)
                                                  (In thousands)


                                                                     September 30,              December 31,
                                                                          1998                      1997

CURRENT ASSETS
<S>                                                                    <C>                       <C>       
    Cash and cash equivalents                                          $    674                  $    4,492
    Accrued oil and gas revenue                                           2,995                       4,266
    Due from affiliates                                                   4,098                       2,418
    Prepaid and other assets                                              1,452                         844
    Current assets of affiliates                                          4,361                       3,854
                                                                      ---------                   ---------
             Total current assets                                        13,580                      15,874
                                                                       --------                    --------

PROPERTY, PLANT AND EQUIPMENT, at cost
    Oil and gas properties (full cost method)
        Proved oil and gas properties                                   322,554                     294,922
        Unproved mineral interests - domestic                             2,895                       2,250
                                                                      ---------                   ---------
             Total                                                      325,449                     297,172

    Less - accumulated depreciation,
      depletion, amortization and impairment                           (243,784)                   (221,141)
                                                                        -------                     -------
             Net property, plant and equipment                           81,665                      76,031
                                                                       --------                    --------

OTHER ASSETS
     Deferred tax asset                                                     100                         450
     Noncurrent assets of affiliate                                          26                          16
                                                                    -----------                 -----------
             Total other assets                                             126                         466
                                                                     ----------                  ----------

TOTAL ASSETS                                                          $  95,371                   $  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)


                                                                                  September 30,      December 31,
                                                                                      1998               1997

CURRENT LIABILITIES
<S>                                                                                <C>               <C>       
    Accounts payable and accrued liabilities                                       $    2,772        $    3,087
    Current portion of long-term debt                                                   3,188
    Current portion of contract settlement obligation                                                     1,039
    Current liabilities of affiliates                                                   8,244             6,881
                                                                                    ---------         ---------
         Total current liabilities                                                     14,204            11,007
                                                                                     --------          --------

NONCURRENT LIABILITIES
    Long-term debt                                                                     37,845            25,000
    Long-term obligations of affiliates                                                 7,464             7,589
    Deferred liability                                                                     67                89
                                                                                  -----------       -----------
         Total noncurrent liabilities                                                  45,376            32,678
                                                                                     --------          --------

         Total liabilities                                                             59,580            43,685
                                                                                     --------          --------

COMMITMENTS AND CONTINGENCIES (NOTE 10)

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                                                               (41,658)          (27,581)
    Treasury stock - 258,395 shares in 1998 and 259,278 shares in 1997                 (3,864)           (3,874)
                                                                                    ---------         ---------
         Stockholders' equity - Net                                                    35,791            48,686
                                                                                     --------          --------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                          $  95,371         $  92,371
                                                                                     ========          ========


















<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 Three Months Ended
                                                                                        September 30,
                                                                               1998                       1997

REVENUES:
<S>                                                                           <C>                        <C>    
   Gas revenue                                                                $ 5,638                    $ 3,973
   Oil revenue                                                                  2,240                      3,277
   Pipeline and other                                                             891                        238
   Interest income                                                                 19                         17
                                                                            ---------                  ---------
                                                                                8,788                      7,505
                                                                               ------                     ------

EXPENSES:
   Production operating                                                         2,950                      2,576
   General and administrative                                                     964                        799
   Interest                                                                     1,154                        506
   Depreciation, depletion and amortization                                     3,299                      2,271
   Impairment of oil and gas properties                                         3,600                           
   Litigation                                                                     445                 
                                                                             --------
                                                                               12,412                      6,152
                                                                               ------                     ------

INCOME (LOSS) BEFORE INCOME TAXES                                              (3,624)                     1,353
                                                                              -------                     ------

PROVISION (BENEFIT) FOR INCOME TAXES:
   Current                                                                       (111)                       528
   Deferred                                                                       350                        (100)
                                                                             --------                     -------
                                                                                  239                        428
                                                                             --------                    -------

NET INCOME (LOSS)                                                            $ (3,863)                  $    925
                                                                              =======                    =======

NET INCOME (LOSS) PER SHARE - BASIC                                         $   (1.41)                 $     .34
                                                                             ========                   ========

NET INCOME (LOSS)  PER SHARE - DILUTED                                      $   (1.41)                 $     .33
                                                                             ========                   ========

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 Nine Months Ended
                                                                                       September 30,
                                                                               1998                       1997

REVENUES:
<S>                                                                         <C>                        <C>      
   Gas revenue                                                              $  14,518                  $  12,107
   Oil revenue                                                                  7,354                     10,142
   Pipeline and other                                                           1,767                      1,281
   Interest income                                                                164                        134
                                                                           ----------                 ----------
                                                                               23,803                     23,664
                                                                             --------                   --------

EXPENSES:
   Production operating                                                         8,467                      7,523
   General and administrative                                                   2,866                      2,584
   Interest                                                                     2,888                      1,668
   Depreciation, depletion and amortization                                     8,043                      6,272
   Impairment of oil and gas properties                                        14,600                           
   Litigation                                                                     550              
                                                                           ----------
                                                                               37,414                     18,047
                                                                             --------                   --------

INCOME (LOSS) BEFORE INCOME TAXES                                             (13,611)                     5,617
                                                                             --------                  ---------

PROVISION FOR INCOME TAXES:
   Current                                                                        116                        675
   Deferred                                                                       350                        (100)
                                                                           ----------                   ---------
                                                                                  466                        575
                                                                           ----------                  ---------

NET INCOME (LOSS)                                                           $ (14,077)                $    5,042
                                                                             ========                  =========

NET INCOME (LOSS) PER SHARE - BASIC                                      $      (5.13)               $      1.86
                                                                          ===========                 ==========

NET INCOME (LOSS) PER SHARE - DILUTED                                    $      (5.13)               $      1.78
                                                                          ===========                 ==========

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
                                                                                2,746                      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 Nine Months Ended
                                                                                   September 30,
                                                                          1998                      1997

OPERATING ACTIVITIES:
<S>                                                                     <C>                        <C>     
    Net income (loss)                                                   $(14,077)                  $  5,042
    Adjustments to reconcile net income (loss)
      to net cash provided by operating activities:
        Depreciation, depletion and amortization                           8,043                      6,272
        Impairment of oil and gas properties                              14,600
        Amortization of deferred loan costs and
         debt discount                                                       152
        Noncash interest expense                                               6                         67
        Undistributed earnings of affiliates                              (3,397)                    (2,929)
        Deferred income tax (benefit) expense                                350                       (100)
        Recoupment of take-or-pay liability                                  (22)                       (21)

    Changes in  assets  and  liabilities  provided  (used)  cash net of  noncash
      activity:
        Accrued oil and gas sales                                          1,271                      1,088
        Due from affiliates                                               (1,352)                      (497)
        Prepaid and other assets                                            (695)                       456
        Accounts payable and accrued liabilities                            (315)                       165
                                                                        --------                   --------
                Net cash provided by operating activities                  4,564                      9,543
                                                                         -------                    -------

INVESTING ACTIVITIES:
    Additions to oil and gas properties                                  (19,298)                    (2,128)
    Exploration and development costs incurred                            (6,810)                    (6,538)
    Proceeds from oil and gas property sales                                  97                         26
    Distributions received from affiliates                                 1,524                        858
    Other                                                                                               (17)
                                                                    ------------                 ----------
                Net cash used in investing activities                   ( 24,487)                    (7,799)
                                                                         -------                    -------

FINANCING ACTIVITIES:
    Proceeds from long-term debt                                          17,000                       1,000
    Payments on long-term debt                                                                        (3,000)
    Payments on contract settlement obligation                            (1,045)
    Exercise of stock options                                                150                 
                                                                       ---------
                Net cash provided by (used in)
                    financing activities                                  16,105                      (2,000)
                                                                         -------                     -------

NET DECREASE IN CASH AND CASH
   EQUIVALENTS                                                             (3,818)                      (256)

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD                                                         4,492                        628
                                                                          -------                   --------

END OF PERIOD                                                           $     674                  $     372
                                                                         ========                   ========
<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 September 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 September  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 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 for the three  months  and for the nine
months ended September 30, 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 September 30, 1998
<S>                                                                     <C>               <C>             <C>    
   Net loss per share - basic                                           $ (3,863)         2,749           $(1.41)
                                                                         -------          -----            =====
     Net Loss per share - diluted                                       $ (3,863)         2,749           $(1.41)
                                                                         =======          =====            =====

For the Nine Months Ended September 30, 1998
   Net loss per share - basic                                           $(14,077)         2,746           $(5.13)
                                                                          ------          -----            =====
     Net Loss per share - diluted                                       $(14,077)         2,746           $(5.13)
                                                                          ======          =====            =====

For the Three Months Ended September 30, 1997
   Net income per share - basic                                        $    925           2,718           $   .34
                                                                                                           ======
   Effect of Options                                                                        128
                                                                    -----------          ------
     Net Income per share - diluted                                    $    925           2,846           $   .33
                                                                        =======           =====            ======

For the Nine Months Ended September 30, 1997
   Net income per share - basic                                       $  5,042            2,718            $ 1.86
                                                                                                            =====
   Effect of Options                                                                        121
                                                                   -----------           ------
     Net Income per share - diluted                                   $  5,042            2,839            $ 1.78
                                                                       =======            =====             =====
</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 nine month periods ended
September 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 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 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  $26,500,000.   The  Company  had  amounts   outstanding  of
$17,000,000  as of September 30, 1998.  Subsequent  to September 30, 1998,  HCRC
borrowed an additional  $8,500,000 for the Arcadia acquisition described in Note
9 and for capital projects,  increasing its amounts  outstanding to $25,500,000.
HCRC's unused borrowing base was $1,000,000 at November 13, 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 7.0% at
September  30,  1998.  Interest  is payable at least  quarterly,  and  quarterly
principal  payments of $1,594,000,  as adjusted for the $8,500,000 of borrowings
made  subsequent  to  September  30, 1998,  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.




<PAGE>


NOTE 4    -  STATEMENTS OF CASH FLOWS

Cash paid for interest  during the nine months ended September 30, 1998 and 1997
was $2,349,000 and $1,080,000,  respectively.  Cash paid for income taxes during
the nine months ended  September  30, 1998 and 1997 was  $155,000 and  $725,000,
respectively.


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
an affiliate of Enron Corp. HCRC funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.


NOTE 7    -  IMPAIRMENT OF OIL AND GAS PROPERTIES

During the second and third quarters of 1998,  HCRC recorded  impairments of its
oil and gas properties because  capitalized costs at June 30, 1998 and September
30, 1998 exceeded the present value  (discounted at 10%) of estimated future net
revenues from proved oil and gas reserves,  based on prices of $13.00 per barrel
of oil and $1.90 per mcf of gas and  $12.75  per barrel of oil and $1.80 per mcf
of gas, respectively.


NOTE 8    -  STOCK OPTION GRANT

On May 5, 1998, HCRC granted options to purchase 9,540 shares of Common Stock at
an exercise  price of $15.75 per share which was equal to the fair market  value
of the  Common  Stock on the  date of  grant.  These  options  were not  granted
pursuant to a previously  existing plan, but are subject to terms and conditions
identical to those in HCRC's 1995 Stock  Option  Plan.  One-third of the options
vest  immediately,  and the remainder vest one-half on the first  anniversary of
the date of grant and one-half on the second anniversary of the date of grant.

On May 5, 1998,  HCRC also  granted  options to purchase  9,540 shares of Common
Stock under its 1997 Stock Option Plan at an exercise  price of $15.75 which was
equal  to the  fair  market  value of the  Common  Stock  on the date of  grant.
One-third of the options vest  immediately,  and the remainder  vest one-half on
the  first  anniversary  of the  date  of  grant  and  one-half  on  the  second
anniversary of the date of grant.




<PAGE>


NOTE 9    -  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 worth of properties and denied Arcadia's claim
for attorneys fees.
Arcadia's claim for interest on the adjusted purchase price is still pending.

At the end of October 1998, HCRC and its affiliate,  HEP, closed the acquisition
of oil and gas properties from Arcadia, including 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 $8,100,000. The excess
of the  purchase  price  of the  properties  over  the  estimated  net  revenues
attributable to proved reserves, based on prices of $12.75 per barrel of oil and
$1.90 per mcf of gas, was included in the  determination  of the  impairment  of
HCRC's oil and gas properties in the third quarter of 1998.


NOTE 10 - LEGAL PROCEEDINGS

On April 23,  1992,  a lawsuit  was filed in the  Chancery  Court for New Castle
County,  Delaware,  styled Tappe v. Hallwood Consolidated Resources Corporation,
Hallwood  Consolidated  Partners,  L. P.,  Hallwood Oil and Gas, Inc.,  Hallwood
Energy  Partners,  L. P., and Hallwood  Petroleum,  Inc.  (C. A. No 12536).  The
lawsuit 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

During  the  first  nine  months  of 1998,  HCRC had a net loss of  $14,077,000,
compared to a net income of  $5,042,000  for the first nine months of 1997.  The
1998 period includes  noncash charges in the second and third quarters  totaling
$14,600,000 for property  impairments  which were taken to lower the capitalized
cost of HCRC's properties.

HCRC's  1998  property  impairments  were  recorded  pursuant  to  ceiling  test
limitations  required by the  Securities  and Exchange  Commission for companies
using the full cost method of  accounting.  The total  impairment  was primarily
attributable  to the decline in commodity  prices,  the  difference  between the
purchase  price  negotiated  in August 1997 for the Arcadia  properties  and the
value at  current  prices of those  properties,  and the  write-off  of  certain
unproved acreage.


<PAGE>


The weighted  average  prices  received by HCRC for oil and gas have declined in
each of the  last  three  quarters.  HCRC's  hedges  have  mitigated  the  price
reductions,  however;  HCRC's  weighted  average  oil and gas  prices,  when the
effects of hedging are considered, were 28% and 9% lower, respectively,  for the
first nine months of 1998 compared to the first nine months of 1997.

Although  HCRC's  production  for the first nine  months of 1998 was 21% greater
than the prior year, and operating and general and administrative  expenses were
lower on a unit of production  basis,  net income was lower because of continued
low commodity prices and costs associated with the resolution of litigation.

Liquidity and Capital Resources

Cash Flow

The Company generated  $4,564,000 of cash flow from operating  activities during
the first nine months of 1998.  The other primary cash inflows were  $17,000,000
in proceeds from long-term debt and  $1,524,000 in  distributions  received from
affiliates.  Cash was primarily  used for additions to property and  exploration
and  development  costs of $26,108,000  and for payments on contract  settlement
obligation of $1,045,000 for the nine months ended September 30, 1998, resulting
in a  $3,818,000  decrease  in cash from  $4,492,000  at  December  31,  1997 to
$674,000 at September 30, 1998.

Exploration and Development Projects and Acquisitions

Through  September  30,  1998,  HCRC  incurred  $26,108,00  in  direct  property
additions,  development,  exploitation,  and exploration  costs.  The costs were
comprised of $19,298,000 for property acquisitions and approximately  $6,810,000
for domestic  exploration  and  development.  The  expenditures  resulted in the
drilling,  recompletion,  or workover of 34 development wells and 26 exploration
wells.  Thirty-one  development  wells (91%) and 12 exploration wells (50%) were
successfully completed as producers,  for an overall success rate of 72%. HCRC's
1998  capital  budget was  initially  set at  $21,426,000  but was  increased to
$36,675,000.  The increase allowed for the purchase of the volumetric production
payment and for the  purchase  of oil and gas  reserves  through an  acquisition
which closed in October 1998, both of which are discussed below. The Company has
deferred until 1999 certain capital  expenditures  originally proposed for 1998.
Management  believes  that the  Company  will be able to satisfy  its  remaining
capital  commitments  for 1998.  The remaining  budget for 1998 includes  future
projects  in more  than 10  areas.  Significant  acquisition,  exploration,  and
development projects for 1998 are discussed below.

Rocky Mountain Region

HCRC  expended  approximately  $19,725,000  of its  capital  budget in the Rocky
Mountain Region located in Colorado, Montana, North Dakota, Northwest New Mexico
and Wyoming. Of this amount,  approximately  $17,291,000 was for the purchase of
the  volumetric   production  payment  discussed  below.  In  1998,  HCRC  spent
approximately $1,560,000 expanding the New Mexico gathering system, successfully
recompleting  five  operated   development   wells,   drilling  four  successful
development wells, and drilling two unsuccessful  operated  exploration wells. 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 34 wells 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 the affiliate
of Enron Corp. the volumetric  production  payment.  HCRC funded its $17,291,000
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.  Hallwood
Petroleum,  Inc. ("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 6,750 mcf
per day.

Cajon Lake Field.  HCRC is currently  completing the sidetracking and redrilling
of a 6,000 foot Ismay formation  exploration well in San Juan County, Utah. HCRC
owns an approximate  15% working  interest in the operated well and has incurred
approximately  $90,000  in  1998.  Initial  tests  of the  Ismay  formation  are
promising, and HCRC estimates that the sale of production will begin in November
1998.

Colorado  Western  Slope  Project.  HCRC  successfully  completed two 5,500 foot
Dakota  Formation  wells in the Piceance Basin in Colorado and Utah.  Currently,
HCRC owns an average 46% working  interest in the wells.  Both wells began sales
of  production in the third  quarter of 1998 with  combined  initial  production
rates of 1,500 mcf per day. In 1998, HCRC also successfully recompleted one well
in the Basin.  Total costs for the three wells  through  September  30, 1998 are
approximately $576,000.

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 in the  first  quarter  of  1998.  HCRC's  costs  in 1998  are
approximately  $255,000.  HCRC  continues  to  evaluate  the  project  using the
additional data obtained from the exploratory well.

East Kevin Field Project. In Toole County,  Montana, HCRC drilled two successful
horizontal  wells to the  Nisku  Formation.  The  wells  have  combined  initial
production  rates of 1,300 mcfe per day. HCRC has a 50% working  interest in the
projects and has spent approximately $400,000 in 1998. HCRC's third quarter 1998
drilling  costs  for a third  well,  which is  currently  being  completed,  are
approximately $250,000.

Greater Permian Region

During the first nine months of 1998, HCRC expended approximately  $2,521,000 of
its capital budget in the Greater  Permian Region located in Texas and Southeast
New Mexico. HCRC spent approximately $2,026,000 for drilling,  recompletion,  or
workover of 21 development wells and for drilling 17 exploration  wells.  Thirty
(79%) of the wells drilled or recompleted  were  successful.  The major projects
within the Region are discussed below.

Arcadia Acquisition.  In October 1998, HCRC purchased for $8,100,000 oil and gas
properties,  including interests in approximately 570 wells, numerous proven and
unproven  drilling  locations,   exploration  acreage,  and  3-D  seismic  data.
Approximately  85% in value of the proved  properties  are operated by HPI. HCRC
expects that the acquisition will add proven reserves of  approximately  443,000
barrels  of oil and 6.4  billion  cubic feet of natural  gas.  HCRC's  estimated
proven  reserve  addition of 9.1 bcfe  represents  63% of HCRC's  estimated 1998
production. HCRC estimates that 1999 production will be approximately .9 bcfe.

Catclaw   Draw/Carlsbad  Area  Projects.   HCRC  spent  approximately   $431,000
successfully  recompleting  six  operated  wells  and  drilling  one  successful
development  well in the  Carlsbad/Catclaw  Draw  areas in Lea,  Eddy and Chaves
Counties, New Mexico.

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  $942,000. HCRC owns an average 30% working interest in the wells.
Two wells are currently  underway.  Future drilling has been deferred because of
current low crude oil prices.

Griffin Project. In 1998, HCRC purchased land for $103,000 and incurred costs of
approximately $455,000 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 evaluating the possibility of future exploration
prospects  within  this  project.   Limited  delineation  drilling  on  previous
discoveries exists in the area. HCRC owns an average 25% working interest in the
prospect area.

Gulf Coast Region

During the first nine months of 1998, HCRC expended approximately  $2,941,000 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.  HCRC also incurred  approximately
$600,000 in 1998 for  drilling a 17,000 foot Frio  Formation  exploration  well,
which is currently  underway.  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.  HCRC owns a 7.5% working interest in a non-operated  15,400
foot directional exploration well testing the Wilcox formation in LaVaca County,
Texas.  The  drilling  efforts  were  successful,  and  HCRC  expects  sales  of
production  to  begin  in  November  1998.  Costs  incurred  in 1998 by HCRC are
approximately $350,000 for drilling and approximately $40,000 for land.

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
$540,000.  The well  encountered  Buda pay and flow test rates between 3,552 and
8,239 mcf per day.  Sale of  production  is expected to begin in December  1998,
following installation of gas processing equipment.  In 1998, HCRC also incurred
$235,000 for land and leaseholds costs relating to the project.

Mid-Continent Region

HCRC expended  approximately $490,000 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  because of mechanical
problems and found that the Sycamore  Formation  produced at  subcommercial  gas
rates. The operator is evaluating a Springer Formation  completion.  HCRC's 1998
year to date  drilling  and  completion  costs were  approximately  $165,000 for
HCRC's 5% working interest.

El Reno  Project.  HCRC  incurred  costs of  approximately  $157,000  in 1998 to
complete one successful exploration well in Canadian County,  Oklahoma. The well
was completed in the Red Fork Formation and is currently  producing 750 mcfe per
day. HCRC has a 35% working interest.

Other

The  remaining  $431,000  of  HCRC's  1998  capital  expenditures  were  devoted
principally  to drilling  four  unsuccessful  exploration  wells in Yolo County,
California and for other miscellaneous  projects.  HCRC also participated in two
nonoperated  3-D  seismic   projects  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.

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.


<PAGE>


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   outstanding  of
$17,000,000  as of September 30, 1998.  Subsequent  to September 30, 1998,  HCRC
borrowed an additional  $8,500,000 for the Arcadia  acquisition  described above
and for capital  projects,  increasing its amounts  outstanding to  $25,500,000.
HCRC's unused borrowing base was $1,000,000 at November 13, 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 7.0% at
September  30,  1998.  Interest  is payable at least  quarterly,  and  quarterly
principal  payments of $1,594,000,  as adjusted for the $8,500,000 of borrowings
made  subsequent  to  September  30, 1998,  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.

Year 2000 Update

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's:  information technology such as computers,
programs and related systems ("IT") and non-information  technology systems such
as embedded technology on a silicon chip ("Non IT").

The  Plan.  The  Company's  Year 2000 Plan (the  "Plan")  has four  phases:  (i)
assessment,  (ii) inventory,  (iii) remediation,  testing and implementation and
(iv) contingency plans.  Approximately  twelve months ago, the Company began its
phase one assessment of its particular  exposure to problems that might arise as
a result of the new  millennium.  The  assessment  phase has been  substantially
completed  and has  identified  the Company's IT systems that must be updated or
replaced in order to be Year 2000 compliant. In particular, the software used by
the Company for reservoir engineering must be updated or replaced. The inventory
phase of the Plan is  currently  underway  and is  expected to be  completed  by
December 31, 1998.  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.

To date, the Company has determined that its IT systems are either  compliant or
can be made compliant  without material cost.  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;  the process of inquiring of
third parties and reviewing their responses is underway but is not complete.

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 Non IT systems
are 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. 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 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.  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 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.  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. 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>


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 third quarter of 1998.  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>                  <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
Third quarter 1998                            12.05                12.44                 1.76                 1.88
</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 hedge  contracts are recognized as oil or gas revenue at the
time the  hedged  volumes  are sold.  During  1998,  HCRC has not  entered  into
additional  oil price hedges for future years because hedge  contracts at prices
HCRC considers advantageous are not available.

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 three months of 1998                                14%                       $14.57
1999                                                      4%                        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 $18.35 per barrel.


<PAGE>




<TABLE>
<CAPTION>

                                                       Gas
                                                Percent of Direct                 Contract
               Period                           Production Hedged               Floor Price
                                                                                 (per mcf)

<S>                                                      <C>                        <C>  
Last three months of 1998                                49%                        $2.03
1999                                                     41%                         1.98
2000                                                     37%                         2.02
2001                                                     36%                         2.00
2002                                                     35%                         2.06
</TABLE>

Between 0% and 8% 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 fourth quarter  through  October 30, 1998,  the weighted  average oil
price (for  barrels  not  hedged)  was  approximately  $12.80 per barrel and the
weighted  average  price of natural gas (for mcf not  hedged) was  approximately
$1.80 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 September 30, 1998         For the Quarter Ended September 30, 1997
                                       ----------------------------------------          ----------------------------------------
                                             Direct                                    Direct
                                             Owned         HEP        Total            Owned              HEP             Total

<S>                                         <C>            <C>      <C>               <C>               <C>             <C>  
Gas production (mcf)                           2,351          649      3,000             1,500             523             2,023
Oil production (bbl)                             144           36        180               145              34               179

Average gas price (per mcf)                  $  1.85      $  1.99    $  1.88             $1.92           $2.08             $1.96
Average oil price (per bbl)                   $12.27       $13.14     $12.44            $18.33          $18.21            $18.31

Gas revenue                                 $  4,345     $  1,293   $  5,638          $  2,886        $  1,087          $  3,973
Oil revenue                                    1,767          473      2,240             2,658             619             3,277
Pipeline and other                               693          198        891               149              89               238
Interest income                                   16            3         19                 5              12                17
                                           ---------   ----------  ---------        ----------       ---------         ---------

         Total revenue                         6,821        1,967      8,788             5,698           1,807             7,505
                                             -------      -------    -------           -------         -------           -------

Production operating expense                   2,410          540      2,950             2,034             542             2,576
General and administrative expense               763          201        964               619             180               799
Interest expense                               1,016          138      1,154               372             134               506
Depreciation, depletion and amortization       2,591          708      3,299             1,586             685             2,271
Impairment of oil and gas properties           3,600                   3,600
Litigation                                       375           70        445                                         
                                           ---------    ---------   --------       -----------      -----------

         Total expense                        10,755        1,657     12,412             4,611           1,541             6,152
                                             -------      -------    -------           -------         -------           -------

Income (loss) before income taxes              (3,934)        310      (3,624)           1,087             266             1,353
                                             --------     -------    --------          -------        --------           -------

Provision (benefit) for income taxes:
     Current                                     (111)                   (111)             528                               528
     Deferred                                    350                     350               (100)                            (100)
                                             -------                 -------           --------                         --------
                                                 239                     239               428                               428
                                             -------                 -------          --------                          --------

         Net income (loss)                  $  (4,173)    $   310   $  (3,863)        $    659       $     266          $    925
                                             ========      ======    ========          =======        ========           =======
</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                 TABLE OF HCRC EARNINGS FOR MANAGEMENT DISCUSSION
                                            (In thousands except price)




<PAGE>


                                      For the Nine Months Ended September 30, 1998     For the Nine Months Ended September 30, 1997
                                      --------------------------------------------      --------------------------------------------
                                          Direct                                      Direct
                                          Owned         HEP          Total            Owned              HEP             Total

<S>                                      <C>          <C>          <C>               <C>             <C>               <C>  
Gas production (mcf)                        5,859        1,799        7,658             4,336           1,465             5,801
Oil production (bbl)                          433          106          539               433             102               535

Average gas price (per mcf)               $  1.86      $  2.00      $  1.90           $  2.06         $  2.17           $  2.09
Average oil price (per bbl)                $13.53       $14.11       $13.64            $18.92          $19.10            $18.96

Gas revenue                               $10,923      $ 3,595      $14,518          $  8,930        $  3,177          $ 12,107
Oil revenue                                 5,858        1,496        7,354             8,194           1,948            10,142
Pipeline and other                          1,253          514        1,767               858             423             1,281
Interest income                                72           92          164                76              58               134
                                        ---------      -------       ------          --------        --------          --------

         Total revenue                     18,106        5,697       23,803            18,058           5,606            23,664
                                           ------        -----       ------           -------         -------           -------

Production operating expense                6,788        1,679        8,467             5,952           1,571             7,523
General and administrative expense          2,257          609        2,866             1,994             590             2,584
Interest expense                            2,525          363        2,888             1,232             436             1,668
Depreciation, depletion and amortization    6,244        1,799        8,043             4,826           1,446             6,272
Impairment of oil and gas properties       14,600                    14,600                                                    
Litigation                                    375          175          550                                         
                                        ---------      -------      -------       -----------      -----------

         Total expense                     32,789        4,625       37,414            14,004           4,043            18,047
                                           ------       ------       ------           -------         -------           -------

Income (loss) before income taxes          (14,683)      1,072       (13,611)           4,054           1,563             5,617
                                           -------      ------       -------          -------         -------           -------

Provision for income taxes:
     Current                                  116                       116               675                               675
     Deferred                                 350                       350               (100)                            (100)
                                          -------                   -------           --------                         --------
                                              466                       466               575                               575
                                          -------                   -------          --------                          --------

         Net income (loss)                $(15,149)    $ 1,072      $(14,077)        $  3,479        $  1,563          $  5,042
                                           =======      ======       =======          =======         =======           =======
</TABLE>


<PAGE>


Third Quarter of 1998 Compared to the Third Quarter of 1997

Gas Revenue

Gas revenue increased  $1,665,000 during the third quarter of 1998 compared with
the third  quarter of 1997.  The  increase  is  comprised  of an increase in gas
production from 2,023,000 mcf in 1997 to 3,000,000 mcf in 1998 partially  offset
by a decrease in price from $1.96 per mcf in 1997 to $1.88 per mcf in 1998.  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 third  quarter of 1998 was to  increase  the
Company's average gas price from $1.76 to $1.88 per mcf, resulting in a $360,000
increase in revenue.

Oil Revenue

Oil revenue  decreased  $1,037,000  during the third quarter of 1998 as compared
with the third  quarter of 1997.  The  decrease  in revenue  is  comprised  of a
decrease  in the  average oil price from $18.31 per barrel in 1997 to $12.44 per
barrel in 1998,  partially  offset by an increase  in  production  from  179,000
barrels in 1997 to 180,000 barrels in 1998. Oil production  increased  primarily
because  two  temporarily  shut-in  wells were back on line.  The two wells were
temporarily  shut-in during the third quarter of 1997 while workover  procedures
were performed.

The effect of HCRC's hedging  transactions during the third quarter of 1998, was
to increase the Company's average oil price from $12.05 per barrel to $12.44 per
barrel, resulting in a $70,000 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  $653,000 during the
third  quarter of 1998  compared with the third quarter of 1997 due to increased
incentive  payment  income  resulting  from HCRC's  acquisition  of a volumetric
production payment during May 1998.

Production Operating Expense

Production operating expense increased $374,000 during the third quarter of 1998
compared  with the third  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 HPI, an affiliate of HCRC, which manages
and operates  certain oil and gas  properties  on behalf of the  Company.  These
costs  increased  $165,000 during the third quarter of 1998 as compared with the
third quarter of 1997 primarily due to an increase in salaries expense.

Interest Expense

Interest  expense  increased  $648,000 during the third quarter of 1998 compared
with the third quarter of 1997 due to a higher average  outstanding debt balance
during 1998.

Depreciation, Depletion and Amortization Expense

Depreciation,  depletion and amortization expense increased $1,028,000 primarily
due to a higher  depletion  rate in 1998  resulting from the increase in oil and
gas production previously discussed, as well as higher capitalized costs.



<PAGE>


Impairment of Oil and Gas Properties

Impairment of oil and gas properties during the third quarter of 1998 represents
the impairment recorded because capitalized costs at September 30, 1998 exceeded
the present  value  (discounted  at 10%) of estimated  future net revenues  from
proved  oil and gas  reserves,  based on prices of $12.75  per barrel of oil and
$1.80 per mcf of gas.

Litigation

Litigation  expense  during the third  quarter of 1998 is comprised of the costs
related  to the  Arcadia  arbitration  described  in Note 9 of the  accompanying
financial statements.

First Nine Months of 1998 compared to the First Nine Months of 1997

The  comparisons  for the first nine months of 1998 and the first nine months of
1997 are consistent  with those  discussed in the third quarter of 1998 compared
to the third quarter 1997 except for the following:

Gas Revenue

Gas revenue  increased  $2,411,000 during the first nine months of 1998 compared
with the first nine months of 1997.  The increase is comprised of an increase in
production from 5,801,000 mcf in 1997 to 7,658,000 mcf in 1998, partially offset
by a decrease  in the  average  price  from $2.09 per mcf to $1.90 per mcf.  The
production  increase  is  primarily  due  to  the  acquisition  of a  volumetric
production payment during May 1998.

The effect of HCRC's  hedging  transactions  was to increase  HCRC's average gas
price from $1.87 per mcf to $1.90 per mcf,  representing a $230,000  increase in
revenue from hedging transactions.

Oil Revenue

Oil revenue  decreased  $2,788,000 during the first nine months of 1998 compared
with the first nine months of 1997.  The  decrease is comprised of a decrease in
the  average  oil price  from  $18.96 per barrel in 1997 to $13.64 per barrel in
1998, partially offset by an increase in production from 535,000 barrels in 1997
to 539,000  barrels in 1998.  Oil  production  increased  primarily  because two
temporarily  shut-in  wells were back on line.  The two wells  were  temporarily
shut-in  during  the  third  quarter  of 1997  while  workover  procedures  were
performed.

The effect of HCRC's  hedging  transactions  was to increase  HCRC's average oil
price  from  $13.35 per barrel to $13.64  per  barrel,  representing  a $156,000
increase in revenues.

Impairment of Oil and Gas Properties

Impairment  of oil and gas  properties  during  the  first  nine  months of 1998
includes an impairment at June 30, 1998 based on prices of $13.00 per bbl of oil
and  $1.90  per mcf of gas,  as well as the third  quarter  property  impairment
previously discussed.

Litigation

Litigation  settlement  of  affiliate  during the first  nine  months of 1998 is
comprised  of  HCRC's  pro rata  share of HEP's  litigation  settlement  expense
incurred for the settlement of a property  related  lawsuit,  in addition to the
costs of the Arcadia arbitration described above.



<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)       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:  November 13, 1998             By: /s/Thomas J. Jung
                                         Thomas J. Jung, Vice President
                                         (Chief Financial Officer)