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 1-8921



                         HALLWOOD ENERGY PARTNERS, L. P.
             (Exact name of registrant as specified in its charter)



              Delaware                                                84-0987088
(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 [ ]

The registrant is a limited partnership and issues Units (representing ownership
of limited partner interests).

Number of Units outstanding as of November 13, 1998

Class A                   10,011,854
Class B                      143,773
Class C                    2,464,063





                                  Page 1 of 25


<PAGE>
<TABLE>
<CAPTION>


PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS

                                                    HALLWOOD ENERGY PARTNERS, L. P.
                                                      CONSOLIDATED BALANCE SHEETS
                                                              (Unaudited)
                                                            (In thousands)



                                                                     September 30,              December 31,
                                                                          1998                      1997

CURRENT ASSETS
<S>                                                                   <C>                         <C>       
    Cash and cash equivalents                                         $  10,301                   $    6,622
    Accounts receivable:
       Oil and gas revenues                                               5,428                        8,772
       Trade                                                              4,932                        4,609
    Due from affiliates                                                     380                          588
    Prepaid expenses and other current assets                             1,791                        1,551
    Net working capital of affiliate                                        442                
                                                                     ----------
         Total                                                           23,274                       22,142
                                                                       --------                     --------

PROPERTY,  PLANT  AND  EQUIPMENT,  at cost
  Oil and gas  properties  (full cost method):
       Proved mineral interests                                         653,425                      624,621
       Unproved mineral interests - domestic                              2,813                        2,315
    Furniture, fixtures and other                                         3,399                        3,513
                                                                      ---------                    ---------
         Total                                                          659,637                      630,449

    Less accumulated depreciation, depletion,
       amortization and property impairment                            (556,552)                    (536,118)
                                                                       --------                      -------
         Total                                                          103,085                       94,331
                                                                        -------                     --------

OTHER ASSETS
    Investment in common stock of HCRC                                   11,958                       15,048
    Deferred expenses and other assets                                      136                           82
                                                                     ----------                  -----------
         Total                                                           12,094                       15,130
                                                                       --------                     --------

TOTAL ASSETS                                                           $138,453                     $131,603
                                                                        =======                      =======













<FN>

                                                   (Continued on the following page)
</FN>
</TABLE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L. P.
                                                      CONSOLIDATED BALANCE SHEETS
                                                              (Unaudited)
                                                      (In thousands except Units)



                                                                             September 30,            December 31,
                                                                                  1998                     1997

CURRENT LIABILITIES
<S>                                                                           <C>                       <C>      
    Accounts payable and accrued liabilities                                  $  21,463                 $  19,915
    Current portion of long-term debt                                             6,213
    Net working capital deficit of affiliate                                                                  448
    Current portion of contract settlement                                                                  2,752
                                                                          -------------                 ---------
         Total                                                                   27,676                    23,115
                                                                               --------                  --------

NONCURRENT LIABILITIES
    Long-term debt                                                               34,987                    34,986
    Deferred liability                                                            1,081                     1,180
                                                                              ---------                 ---------
         Total                                                                   36,068                    36,166
                                                                               --------                  --------

           Total Liabilities                                                     63,744                    59,281
                                                                               --------                  --------

MINORITY INTEREST IN AFFILIATES                                                   2,845                     3,258
                                                                              ---------                 ---------

COMMITMENTS AND CONTINGENCIES (NOTE 9)

PARTNERS' CAPITAL
    Class A Units -  10,011,854  and  9,977,254  Units  issued in 1998 and 1997,
      respectively; 9,121,612 and 9,077,949
      outstanding  in 1998 and 1997, respectively                                52,962                    66,184
    Class B Subordinated Units - 143,773 Units outstanding
      in 1998 and 1997                                                            1,261                     1,411
    Class C Units - 2,464,063 and 664,063 Units outstanding
      in 1998 and 1997, respectively                                             21,385                     4,868
    General partner                                                               3,165                     3,580
    Treasury Units - 890,242 and 899,305 Units in 1998 and
      1997, respectively                                                         (6,909)                    (6,979)
                                                                              ---------                  ---------
         Partners' Capital - Net                                                 71,864                     69,064
                                                                               --------                   --------

TOTAL LIABILITIES AND PARTNERS' CAPITAL                                        $138,453                   $131,603
                                                                                =======                    =======












<FN>

    The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L. P.
                                                 CONSOLIDATED STATEMENTS OF OPERATIONS
                                                              (Unaudited)
                                                  (In thousands except per Unit data)



                                                                                   For the Three Months Ended
                                                                                          September 30,
                                                                                  1998                    1997

REVENUES:
<S>                                                                           <C>                      <C>     
    Gas revenue                                                               $  7,421                 $  6,639
    Oil revenue                                                                  2,626                    3,564
    Pipeline, facilities and other                                               1,067                      523
    Interest                                                                       241                       69
                                                                             ---------                ---------
                                                                                11,355                   10,795
                                                                                ------                   ------

EXPENSES:
    Production operating                                                         3,083                    3,072
    General and administrative                                                   1,104                      996
    Depreciation, depletion and amortization                                     4,617                    3,165
    Impairment of oil and gas properties                                         6,600
    Interest                                                                       734                      716
                                                                              --------                 --------
                                                                                16,138                    7,949
                                                                                ------                  -------

OTHER INCOME (EXPENSES):
    Equity in earnings (loss) of HCRC                                             (767)                     138
    Minority interest in net income of affiliates                                 (203)                    (449)
    Litigation                                                                    (375)                     (33)
                                                                             ---------                ---------
                                                                                (1,345)                    (344)
                                                                               -------                 --------

NET INCOME (LOSS)                                                               (6,128)                   2,502

CLASS C UNIT DISTRIBUTIONS ($.25 PER UNIT)                                         616                      166
                                                                              --------                 --------

NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
    PARTNER, CLASS A AND CLASS B LIMITED
    PARTNERS                                                                  $ (6,744)                $  2,336
                                                                               =======                  =======

ALLOCATION OF NET INCOME (LOSS):

General partner                                                            $        82                $     532
                                                                            ==========                 ========
Class A and Class B Limited partners                                          $ (6,826)                $  1,804
                                                                               =======                  =======
    Per Class A Unit and Class B Unit - basic                               $     (.74)              $      .20
                                                                             =========                =========
    Per Class A Unit and Class B Unit - diluted                             $     (.74)              $      .19
                                                                             =========                =========
    Weighted average Class A Units and Class B Units
       outstanding                                                               9,265                    9,222
                                                                               =======                  =======






<FN>

    The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L. P.
                                                 CONSOLIDATED STATEMENTS OF OPERATIONS
                                                              (Unaudited)
                                                  (In thousands except per Unit data)



                                                                                    For the Nine Months Ended
                                                                                          September 30,
                                                                                  1998                    1997

REVENUES:
<S>                                                                            <C>                      <C>    
    Gas revenue                                                                $21,159                  $19,073
    Oil revenue                                                                  8,356                   11,157
    Pipeline, facilities and other                                               2,743                    2,072
    Interest                                                                       567                      328
                                                                              --------                 --------
                                                                                32,825                   32,630
                                                                                ------                   ------

EXPENSES:
    Production operating                                                         9,389                    8,767
    General and administrative                                                   3,353                    3,250
    Depreciation, depletion and amortization                                    11,234                    8,657
    Impairment of oil and gas properties                                         9,200
    Interest                                                                     1,927                    2,315
                                                                               -------                  -------
                                                                                35,103                   22,989
                                                                               -------                   ------

OTHER INCOME (EXPENSES):
    Equity in earnings (loss) of HCRC                                           (3,090)                   1,384
    Minority interest in net income of affiliates                                 (787)                  (1,341)
    Litigation                                                                    (930)                     240
                                                                              --------                 --------
                                                                                (4,807)                     283
                                                                               -------                 --------

NET INCOME (LOSS)                                                               (7,085)                   9,924

CLASS C UNIT DISTRIBUTIONS ($.75 PER UNIT)                                       1,848                      498
                                                                               -------                 --------

NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
    PARTNER, CLASS A AND CLASS B LIMITED PARTNERS
                                                                              $ (8,933)                $  9,426
                                                                               =======                  =======

ALLOCATION OF NET INCOME (LOSS):

General partner                                                             $      732                 $  1,408
                                                                             =========                  =======
Class A and Class B Limited partners                                          $ (9,665)                $  8,018
                                                                               =======                  =======
    Per Class A Unit and Class B Unit - basic                               $    (1.04)              $      .87
                                                                             =========                =========
    Per Class A Unit and Class B Unit - diluted                             $    (1.04)              $      .86
                                                                             =========                =========
    Weighted average Class A Units and Class B Units
       outstanding                                                               9,256                    9,222
                                                                               =======                  =======






<FN>

    The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                    HALLWOOD ENERGY PARTNERS, L. P.
                                                 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)                                                          $  (7,085)            $   9,924
    Adjustments to reconcile net income to net cash provided
       by operating activities:
          Depreciation, depletion and amortization                                11,234                 8,657
          Impairment of oil and gas properties                                     9,200
          Depreciation charged to affiliates                                         188                   165
          Asset disposals                                                           (188)
          Amortization of deferred loan costs and other assets                        54                    61
          Noncash interest expense                                                    15                   178
          Equity in (earnings) loss of HCRC                                        3,090                (1,384)
          Minority interest in net income                                            787                 1,341
          Undistributed (earnings) loss of affiliates                               (508)                   73
          Recoupment of take-or-pay liability                                        (99)                  (97)

    Changes in  operating  assets and  liabilities  provided  (used) cash net of
       noncash activity:
          Oil and gas revenues receivable                                          3,344                 1,976
          Trade receivables                                                         (323)                 (305)
          Due from affiliates                                                       (874)                 (996)
          Prepaid expenses and other current assets                                 (240)               (1,031)
          Accounts payable and accrued liabilities                                 1,548                 1,488
          Due to affiliates                                                                             (1,772)
                                                                             -----------               -------
                Net cash provided by operating activities                         20,143                18,278
                                                                                  ------                ------

INVESTING ACTIVITIES:
    Additions to property, plant and equipment                                   (19,772)               (2,499)
    Exploration and development costs incurred                                    (9,561)               (9,073)
    Proceeds from sales of property, plant and equipment                             189                    85
    Distributions received from affiliate                                            639
    Other investing activities                                                       (21)                  (76)
                                                                              ----------            ----------
                Net cash used in investing activities                            (28,526)              (11,563)
                                                                                 -------               -------

FINANCING ACTIVITIES:
    Proceeds from long-term debt                                                  24,500                 2,000
    Proceeds from the issuance of Class C Units net of syndication                16,517
costs
    Payments of long-term debt                                                   (18,286)               (5,285)
    Distributions paid                                                            (7,072)               (5,583)
    Payment of contract settlement                                                (2,767)
    Distribution paid by consolidated affiliates to minority interest             (1,200)               (1,503)
    Exercise of Unit Options                                                         199                       
    Capital contribution from the general partner                                    171                       
    Other                                                                                                 (115)
                                                                           -------------              --------
                Net cash provided by (used in) financing activities               12,062               (10,486)
                                                                                 -------                ------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
                                                                                   3,679                (3,771)

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD                                                                6,622                 5,540
                                                                                 -------               -------

END OF PERIOD                                                                   $ 10,301              $  1,769
                                                                                 =======               =======
<FN>

    The accompanying notes are an integral part of the financial statements.
</FN>
</TABLE>


<PAGE>


                         HALLWOOD ENERGY PARTNERS, L. P.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (Unaudited)



NOTE 1    -  GENERAL

Hallwood Energy  Partners,  L. P. ("HEP") is a publicly traded Delaware  limited
partnership engaged in the development,  exploration, acquisition and production
of oil and gas properties in the continental  United States.  HEP's objective is
to provide its partners with an attractive  return through a combination of cash
distributions and capital appreciation.  To achieve its objective,  HEP utilizes
operating  cash flow,  first,  to reinvest in operations to maintain its reserve
base and production;  second, to make stable cash  distributions to Unitholders;
and third,  to grow HEP's  reserve base over time.  HEP's future  growth will be
driven by a combination of development of existing projects, exploration for new
reserves and select acquisitions. The general partner of HEP is HEPGP Ltd.

The  activities  of HEP are  conducted  through HEP  Operating  Partners,  L. P.
("HEPO") and EDP Operating,  Ltd. ("EDPO").  HEP is the sole limited partner and
HEPGP Ltd. is the sole general partner of HEPO and of EDPO.  Solely for purposes
of simplicity  herein,  unless  otherwise  indicated,  all  references to HEP in
connection with the ownership, exploration, development or production of oil and
gas properties include HEPO and EDPO.

The interim financial data are unaudited; however, in the opinion of the general
partner,  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 HEP's December 31,
1997 Annual Report on Form 10-K.

Accounting Policies

Consolidation

HEP  fully  consolidates  entities  in which it owns a greater  than 50%  equity
interest  and  reflects  a  minority  interest  in  the  consolidated  financial
statements.  HEP accounts for its interest in 50% or less owned  affiliated  oil
and gas partnerships  and limited  liability  companies using the  proportionate
consolidation method of accounting. HEP's investment in approximately 46% of the
common  stock of its  affiliate,  Hallwood  Consolidated  Resources  Corporation
("HCRC"), is accounted for under the equity method.

The  accompanying  financial  statements  include  the  activities  of HEP,  its
subsidiaries  Hallwood  Petroleum,  Inc.  ("HPI") and Hallwood Oil and Gas, Inc.
("Hallwood  Oil"), and majority owned affiliates,  the May Limited  Partnerships
1983-1, 1983-2, 1983-3, 1984-1, 1984-2 and 1984-3 ("Mays").

Computation of Net Income (Loss) Per Unit

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.  HEP  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 Class A and Class B Unit is computed  by dividing  net
income (loss) attributable to the Class A and Class B limited partners' interest
(net income  excluding  income (loss)  attributable  to the general  partner and
Class C Units) by the weighted average number of Class A Units and Class B Units
outstanding  during  the  periods.  Diluted  income per Class A and Class B Unit
includes the  potential  dilution  that could occur upon  exercise of options to
acquire Class A Units,  computed  using the treasury  stock method which assumes
that the increase in the number of Units is reduced by the number of Units which
could  have been  repurchased  by the  Partnership  with the  proceeds  from the
exercise  of the options  (which  were  assumed to have been made at the average
market price of the Class A Units during the reporting period).

The  following  table  reconciles  the number of Units  outstanding  used in the
calculation of basic and diluted income (loss) per Class A and Class B Unit. The
Unit options have been  ignored in the  computation  of diluted loss per Class A
and Class B Unit for the three and nine months ended  September 30, 1998 because
their inclusion would be antidilutive.

<TABLE>
<CAPTION>

                                                                        Income (Loss)       Units        Per Unit
                                                                             (In thousands except per Unit)

For the Three Months Ended September 30, 1998
<S>                                                                     <C>               <C>             <C>    
   Net loss per Class A Unit and Class B Unit - basic                   $(6,826)          9,265           $ (.74)
                                                                         ------           -----            =====
     Net Loss per Class A Unit and Class B Unit - diluted               $(6,826)          9,265           $ (.74)
                                                                         ======           =====            =====

For the Nine Months Ended September 30, 1998
   Net loss per Class A Unit and Class B Unit - basic                   $(9,665)          9,256           $(1.04)
                                                                         ------           -----            ======
     Net Loss per Class A Unit and Class B Unit - diluted               $(9,665)          9,256           $(1.04)
                                                                         ======           =====            =====

For the Three Months Ended September 30, 1997
   Net income per Class A Unit and Class B Unit - basic                 $ 1,804           9,222            $  .20
                                                                                                            =====
   Effect of Unit Options                                                                   113
                                                                     ----------          ------
     Net Income per Class A Unit and Class B Unit - diluted             $ 1,804           9,335            $  .19
                                                                         ======           =====             =====

For the Nine Months Ended September 30, 1997
   Net income per Class A Unit and Class B Unit -basic                  $ 8,018           9,222            $  .87
                                                                                                            =====
  Effect of Unit Options                                                                    131
                                                                     ----------          ------
     Net Income per Class A Unit and Class B Unit - diluted             $ 8,018           9,353            $  .86
                                                                         ======           =====             =====
</TABLE>

Treasury Units

HEP owns  approximately 46% of the outstanding  common stock of HCRC, while HCRC
owns approximately 19% of HEP's Class A Units. Consequently, HEP has an interest
in 890,242 and 899,305 of its own Units at  September  30, 1998 and December 31,
1997, respectively.
These  Units  are  treated  as  treasury  Units  in the  accompanying  financial
statements.

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 Partnership  adopted SFAS 130 on January 1, 1998. The  Partnership  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 Partnership is required to
adopt SFAS 133 on January 1, 2000. The Partnership 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 2    -  DEBT

During the first quarter of 1997, HEP and its lenders amended and restated HEP's
Second  Amended  and  Restated  Credit   Agreement  (as  amended,   the  "Credit
Agreement") to extend the term date of its line of credit to May 31, 1999. Under
the Credit Agreement,  HEP has a borrowing base of $62,000,000.  HEP had amounts
outstanding  at September 30, 1998 of  $41,200,000.  Subsequent to September 30,
1998,  HEP  borrowed  an  additional  $8,500,000  for  the  Arcadia  acquisition
described in Note 8 and for capital projects, increasing its amounts outstanding
to $49,700,000.  HEP's unused borrowing base totaled $12,300,000 at November 13,
1998.

Borrowings  against  the  Credit  Agreement  bear  interest  at the lower of the
Certificate  of Deposit rate plus from 1.375% to 1.875%,  prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 7.0%
at September 30, 1998.  Interest is payable  monthly,  and  quarterly  principal
payments of  $3,106,500,  as adjusted  for the  $8,500,000  of  borrowings  made
subsequent to September 30, 1998, commence May 31, 1999.

The borrowing base for the Credit  Agreement is redetermined  semiannually.  The
Credit  Agreement  is secured by a first lien on  approximately  80% in value of
HEP's oil and gas properties.  Additionally, aggregate distributions paid by HEP
in any 12 month  period are limited to 50% of cash flow from  operations  before
working  capital  changes and  distributions  received from  affiliates,  if the
principal amount of debt of HEP is 50% or more of the borrowing base.  Aggregate
distributions paid by HEP are limited to 65% of cash flow from operations before
working capital changes and 65% of distributions  received from  affiliates,  if
the principal amount of debt is less than 50% of the borrowing base.

HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for 1998 and  $10,000,000  for each of 1999 and 2000.  HEP does not use
the hedges for  trading  purposes,  but rather for the  purpose of  providing  a
measure of  predictability  for a portion of HEP's  interest  payments under its
Credit Agreement,  which has a floating  interest rate. In general,  it is HEP's
goal to hedge 50% of the principal amount of its debt for the next two years and
25% for each year of the remaining  term of the debt.  HEP has entered into four
hedges,  one of which is an  interest  rate  collar  pursuant to which it pays a
floor rate of 7.55% and a ceiling  rate of 9.85%,  and the  others are  interest
rate swaps with fixed rates ranging from 5.75% to 6.57%. The amounts received or
paid upon settlement of these transactions are recognized as interest expense at
the time the interest payments are due.


NOTE 3    -  STATEMENTS OF CASH FLOWS

Cash paid for interest  during the nine months ended September 30, 1998 and 1997
was $1,845,000 and $2,077,000, respectively.

NOTE 4    -  CLASS C UNIT ISSUANCE

On February  17,  1998,  HEP closed its public  offering of 1.8 million  Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were  approximately  $16,517,000.  HEP used  $14,000,000  of the net proceeds to
repay borrowings  under its Credit Agreement and applied the remaining  proceeds
toward the  repayment of HEP's  outstanding  contract  settlement  obligation at
December 31, 1997 of $2,752,000.


NOTE 5    -  ACQUISITION

In July  1996,  HEP and its  affiliate,  HCRC,  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 HEP and HCRC purchased the volumetric  production  payment from
the affiliate of Enron Corp. HEP funded its $17,257,000 share of the acquisition
price from operating cash flow and borrowings under its Credit Agreement.


NOTE 6    -  IMPAIRMENT OF OIL AND GAS PROPERTIES

During the second and third  quarters of 1998,  HEP 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 $2.00 per mcf of gas and  $12.80  per barrel of oil and $1.90 per mcf
of gas, respectively.


NOTE 7    -  UNIT OPTION PLAN

During  the second  quarter  of 1998,  HEP  adopted a Class C Unit  Option  Plan
covering  120,000  Class C Units.  Options  to  purchase  all of the Units  were
granted effective May 5, 1998 at an exercise price of $10.00 per Unit, which was
equal to the fair  market  value of the Units on the date of grant.  One-half of
the options  vested on the date of grant,  and the  remainder  vest on the first
anniversary of the date of grant.

On May 5, 1998,  HEP  granted  options to  purchase  25,500  Class A Units at an
exercise  price of $6.625 per Unit,  which was equal to the fair market value of
the Units 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 HEP's 1995 Unit Option  Plan.  One-third  of the options  vested on the
date of grant,  and the remainder vest one-half on the first  anniversary of the
date of grant and one-half on the second anniversary of the date of grant.


NOTE 8    -  ARBITRATION

In connection with the Demand for Arbitration  filed by Arcadia  Exploration and
Production Company ("Arcadia") with the American Arbitration Association against
Hallwood Energy Partners,  L.P., Hallwood  Consolidated  Resources  Corporation,
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.



<PAGE>


At the end of October 1998, HEP and its affiliate,  HCRC, 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. HEP'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 $12.80 per barrel of oil and
$1.90 per mcf of gas, was included in the  determination  of the  impairment  of
HEP's oil and gas properties in the third quarter of 1998.


NOTE 9    -  LEGAL SETTLEMENT

Concise Oil and Gas Partnership  ("Concise"),  a wholly owned  subsidiary of the
Partnership,  was a defendant in a lawsuit styled Dr. Allen J. Ellender,  Jr. et
al. vs. Goldking Production Company, et al., filed in the Thirty-Second Judicial
District Court, Terrebonne Parish, Louisiana on May 30, 1996. The portion of the
lawsuit against Concise was settled in  consideration  of the payment by Concise
of $600,000.  This amount was recorded as litigation  settlement  expense in the
second  quarter of 1998.  Concise has been  dismissed  with  prejudice  from the
lawsuit.

In addition to the litigation  noted above, the Partnership and its subsidiaries
are from time to time subject to routine  litigation  and claims  incidental  to
their business, which the Partnership believes will be resolved without material
effect on the Partnership's financial condition, cash flows or operations.


ITEM 2    -  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
             RESULTS OF OPERATIONS

During the first nine months of 1998, HEP had a net loss of $7,085,000, compared
to a net income of $9,924,000 for the first nine months of 1997. The 1998 period
includes  noncash charges in the second and third quarters  totaling  $9,200,000
for property impairments which were taken to lower the capitalized cost of HEP's
properties.  Also  included  in the net loss is a noncash  charge of  $3,090,000
which  represents  HEP's  equity in the loss of HCRC.  This  amount  is  largely
comprised of HEP's share of HCRC's property impairments.

HEP'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.

The weighted  average  prices  received by HEP for oil and gas have  declined in
each  of the  last  three  quarters.  HEP's  hedges  have  mitigated  the  price
reductions, however; HEP's weighted average oil and gas prices, when the effects
of hedging are considered,  were 29% and 8% lower,  respectively,  for the first
nine months of 1998 compared to the first nine months of 1997.

Although HEP's production for the first nine months of 1998 was 16% greater than
the prior year, and operating,  general and administrative and interest expenses
were  lower on a unit of  production  basis,  net  income  was lower  because of
continued  low  commodity  prices  and  litigation  costs  associated  with  the
resolution of litigation.

Liquidity and Capital Resources

Cash Flow

HEP generated  $20,143,000  of cash flow from  operating  activities  during the
first nine months of 1998.


<PAGE>


The other primary cash inflows were:

         o   Proceeds from long-term debt of $24,500,000;

         o   Proceeds from the issuance of Class C Units, net of syndication
              costs, of $16,517,000;

         o   Distributions received from affiliate of $639,000;

         o   Exercise of Unit Options of $199,000; and

         o   Capital contribution from the general partner of $171,000.

Cash was used primarily for:

         o  Additions to property and development costs incurred of $29,333,000;

         o  Payments of long-term debt of $18,286,000;

         o  Distributions to Unitholders of $7,072,000 and

         o  Payment of contract settlement of $2,767,000.

When combined with  miscellaneous  other cash  activity  during the period,  the
result was an increase of $3,679,000  in HEP's cash from  $6,622,000 at December
31, 1997 to $10,301,000 at September 30, 1998.

Exploration and Development Projects and Acquisitions

Through  September  30,  1998,  HEP  incurred  $29,333,000  in  direct  property
additions,  development,  exploitation,  and exploration  costs.  The costs were
comprised of $19,772,000 for property acquisitions and approximately  $9,561,000
for domestic  exploration  and  development.  The  expenditures  resulted in the
drilling,  recompletion,  or workover of 38 development wells and 28 exploration
wells.  Thirty-four  development wells (89%) and 14 exploration wells (50%) were
successfully  completed as producers,  for an overall success rate of 73%. HEP's
1998  capital  budget was  initially  set at  $25,000,000  but was  increased to
$40,250,000.  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 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

HEP  expended  approximately  $20,645,000  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,  HEP  spent
approximately $2,343,000 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.



<PAGE>


San Juan Basin  Project - Colorado.
In July 1996,  HEP and its  affiliate  HCRC
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 HEP and HCRC,  purchased from the affiliate
of Enron Corp. the volumetric  production  payment.  HEP 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,  HEP 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,  HEP
was already responsible for all costs associated with the wells. HPI has managed
and operated the wells since July 1996, and has increased the wells'  production
from 14 to 26  mmcf  per  day  through  successful  workover  and gas  gathering
facilities improvement programs. The acquisition increased HEP's current average
daily production by 6,750 mcf per day.

San Juan Basin Project - New Mexico.
Costs  associated with a gathering  system
for HEP's New Mexico coalbed methane properties totaled  approximately  $938,000
during 1998.  HEP expects the  gathering  system to  significantly  increase gas
gathering,  processing and compression  capacity for the associated  properties.
The project  should be completed in the fourth quarter of 1998. On the completed
portion of the project,  production  has  increased  3.0 gross mmcf per day. HEP
owns an approximate 35% working interest in the wells.

Cajon Lake Field. 
HEP is currently  completing  the  sidetracking  and  redrilling of a 6,000 foot
Ismay  formation  exploration  well  in San  Juan  County,  Utah.  HEP  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 HEP estimates that the sale of production will begin in November
1998.

Colorado Western Slope Project.
HEP successfully completed two 5,500 foot Dakota Formation wells in the Piceance
Basin in Colorado  and Utah.  HEP owns an average  29%  working  interest in the
wells.  Both wells began sales of production  in the third quarter of 1998,  and
they had a combined  initial  production rate of 1,500 mcf per day. In 1998, HEP
also successfully  recompleted one well in the Basin.  Total costs for the three
wells through September 30, 1998 are approximately $365,000.

West Sioux Pass Prospect.
In the West Sioux area of Richland County, Montana, HEP drilled one unsuccessful
12,405 foot operated Red River Formation  exploration  well in the first quarter
of 1998.  HEP's  costs in 1998 are  approximately  $255,000.  HEP  continues  to
evaluate the project using the  additional  data  obtained from the  exploratory
well.

East Kevin Field Project. 
In Toole County,  Montana,  HEP drilled two successful  horizontal  wells to the
Nisku Formation.  The wells have combined initial production rates of 1,300 mcfe
per  day.  HEP  has a 50%  working  interest  in  the  projects  and  has  spent
approximately  $400,000 in 1998.  HEP'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, HEP expended  approximately  $3,440,000 of
its capital budget in the Greater  Permian Region located in Texas and Southeast
New Mexico. HEP spent approximately  $2,315,000 for drilling,  recompletion,  or
workover  of 22  development  wells  and  for  drilling  17  exploration  wells.
Thirty-one (79%) of the wells drilled or recompleted were successful.  The major
projects within the Region are discussed below.

Arcadia  Acquisition.
In October 1998, HEP 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. HEP expects that the  acquisition
will add proven reserves of approximately 425,000 barrels of oil and 6.1 billion
cubic feet of natural gas. HEP's estimated  proven reserve  addition of 8.7 bcfe
represents  47% of HEP's  estimated  1998  production.  HEP estimates  that 1999
production will be approximately .9 bcfe.

Catclaw   Draw/Carlsbad  Area  Projects. 
HEP spent approximately $726,000 successfully  recompleting seven 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,  HEP
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, HEP drilled
11 exploration  wells,  nine of which were successful.  Costs incurred by HEP in
1998 for the 11 wells drilled were approximately  $870,000.  HEP owns an average
28.5% 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,  HEP purchased  land for $100,000 and incurred  costs of  approximately
$420,000 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.  HEP is  evaluating  the  possibility  of  future  exploration
prospects  within  this  project.   Limited  delineation  drilling  on  previous
discoveries  exists in the area. HEP owns an average 22% working interest in the
prospect area.

Gulf Coast Region

During the first nine months of 1998, HEP expended  approximately  $4,330,000 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, HEP incurred  approximately  $430,000 for land costs
related to the  Mirasoles  project in Kenedy  County,  Texas.  HEP also incurred
approximately  $600,000  in 1998 for  drilling  a  17,000  foot  Frio  Formation
exploration well, which is currently underway.  HEP has a 17.5% working interest
in this large structural  prospect defined by 63 square miles of proprietary 3-D
seismic data.

Esperanza  Project.
HEP 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 HEP expects sales of production to begin
in November 1998. Costs incurred in 1998 by HEP are approximately $350,000.

Bell Project. 
HEP has a 30%  working  interest in an  operated  project to evaluate  the Buda,
Carrizo,  Woodbine,  and Dexter sands in Houston County,  Texas.  HEP'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, HEP also incurred  $235,000
for land and leaseholds costs relating to the project.

Mercy Field Project. 
HEP participated in a successful 10,450 foot nonoperated development well in the
Wilcox formation  located in San Jacinto County,  Texas.  Costs incurred in 1998
are approximately  $192,000. No additional Mercy fieldwork is anticipated in the
remainder of 1998.

Whitewater  Field.
HEP's share of 1998 costs  associated with plugging two  nonoperated  near shore
platform wells were approximately $600,000. This field is now abandoned,  and no
additional work is anticipated.

Mid-Continent Region

HEP expended  approximately  $350,000 of its capital budget in the Mid-Continent
Region  located in Oklahoma  and Kansas.  Major  projects  within the Region are
discussed below.

Stealth Project. 
HEP 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.  HEP's 1998
year to date drilling and completion costs were approximately $165,000 for HEP's
5% working interest.

El Reno  Project.
HEP 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.  HEP has a 35%
working interest.

Other

The  remaining  $568,000  of  HEP's  1998  capital   expenditures  were  devoted
principally  to drilling  four  unsuccessful  exploration  wells in Yolo County,
California and for other  miscellaneous  projects.  HEP also participated in two
nonoperated  3-D  seismic   projects  in  nearby  Solano  and  Colusa  Counties,
California.

Peru  Block Z-3  Project.  HEP'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.  HEP 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.

Class C Unit Issuance

On February  17,  1998,  HEP closed its public  offering of 1.8 million  Class C
Units, priced at $10.00 per Unit. Proceeds to HEP, net of underwriting expenses,
were  approximately  $16,517,000.  HEP used  $14,000,000  of the net proceeds to
repay borrowings  under its Credit Agreement and applied the remaining  proceeds
toward the  repayment of HEP's  outstanding  contract  settlement  obligation at
December 31, 1997 of $2,752,000.

Distributions

HEP declared  distributions  of $.13 per Class A Unit and $.25 per Class C Unit,
payable on November 13, 1998 to Unitholders of record on September 30, 1998.

Distributions  on the Class B Units are suspended if the Class A Units receive a
distribution  of less than $.20 per Class A Unit per  calendar  quarter.  In any
quarter for which distributions of $.20 or more per unit are made on the Class A
Units, the Class B Units are entitled to be paid, in whole or in part, suspended
distributions.

The Class C Units  have a  distribution  preference  of $1.00 per year,  payable
quarterly, which began in the first quarter of 1996. HEP may not declare or make
any cash  distributions  on the Class A or Class B Units  unless all accrued and
unpaid distributions on the Class C Units have been paid.

The Board of Directors of HEP's General Partner is considering the  distribution
level for  future  quarters,  taking  into  account  oil and gas  prices and the
capital needs for HEP.

Financing

During the first quarter of 1997, HEP and its lenders amended and restated HEP's
Second  Amended  and  Restated  Credit   Agreement  (as  amended,   the  "Credit
Agreement") to extend the term date of its line of credit to May 31, 1999. Under
the Credit Agreement,  HEP has a borrowing base of $62,000,000.  HEP had amounts
outstanding  at September 30, 1998 of  $41,200,000.  Subsequent to September 30,
1998,  HEP  borrowed  an  additional  $8,500,000  for  the  Arcadia  acquisition
described above and for capital projects,  increasing its amounts outstanding to
$49,700,000.  HEP's unused  borrowing  base totaled  $12,300,000 at November 13,
1998.

Borrowings  against  the  Credit  Agreement  bear  interest  at the lower of the
Certificate  of Deposit rate plus from 1.375% to 1.875%,  prime plus 1/2% or the
Euro-Dollar rate plus from 1.25% to 1.75%. The applicable interest rate was 7.0%
at September 30, 1998.  Interest is payable  monthly,  and  quarterly  principal
payments of  $3,106,500,  as adjusted  for the  $8,500,000  of  borrowings  made
subsequent to September 30, 1998, commence May 31, 1999.

The borrowing base for the Credit  Agreement is redetermined  semiannually.  The
Credit  Agreement  is secured by a first lien on  approximately  80% in value of
HEP's oil and gas properties.  Additionally, aggregate distributions paid by HEP
in any 12 month  period are limited to 50% of cash flow from  operations  before
working  capital  changes and  distributions  received from  affiliates,  if the
principal amount of debt of HEP is 50% or more of the borrowing base.  Aggregate
distributions paid by HEP are limited to 65% of cash flow from operations before
working capital changes and 65% of distributions  received from  affiliates,  if
the principal amount of debt is less than 50% of the borrowing base.

HEP entered into contracts to hedge its interest rate payments on $15,000,000 of
its debt for 1998 and  $10,000,000  for each of 1999 and 2000.  HEP does not use
the hedges for  trading  purposes,  but rather for the  purpose of  providing  a
measure of  predictability  for a portion of HEP's  interest  payments under its
Credit Agreement,  which has a floating  interest rate. In general,  it is HEP's
goal to hedge 50% of the principal amount of its debt for the next two years and
25% for each year of the remaining  term of the debt.  HEP 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  Partnership:   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  Partnership'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 Partnership 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  Partnership IT systems that must be updated or
replaced in order to be Year 2000 compliant. In particular, the software used by
the  Partnership  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 Partnership 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  Partnership's  assessment  of the
readiness  of third  parties  whose  IT  systems  might  have an  impact  on the
Partnership'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 Partnership's Non IT systems,  the Partnership  believes that
most  of  these  systems  can  be  brought  into  compliance  on  schedule.  The
Partnership'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
Partnership  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  Partnership'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  Partnership's IT and
Non IT systems, as well as to the systems of third parties.  Such failures could
materially and adversely affect the  Partnership'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 Partnership is
unable to determine at this time whether the  consequences of Year 2000 failures
will have a material  impact on the  Partnership's  results of operations,  cash
flow or financial  condition.  Although the Partnership 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  Partnership.  The  Partnership  is
contacting  the various  purchasers  and pipelines  with which it regularly does
business  to  determine  their  state  of  readiness  for  the  Year  2000.  The
Partnership's   Year  2000  Plan  is  expected  to   significantly   reduce  the
Partnership'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 Partnership's development of contingency plans.

Cautionary Statement Regarding Forward-Looking Statements

In the interest of providing the partners with certain information regarding the
Partnership'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.   Although  any  forward-looking   statements
contained  in this  Form  10-Q or  otherwise  expressed  by or on  behalf of the
Partnership  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  Partnership'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 Partnership's oil and gas
operations, the inexact nature of interpretation of seismic and other geological
and  geophysical  data,  imprecision  of reserve  estimates,  the  Partnership's
ability to replace  and expand oil and gas  reserves,  and such other  risks and
uncertainties  described from time to time in the Partnership'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
Partnership'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  Partnership
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,  Unitholders  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 HEP,  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 HEP and the effects of the hedging  transactions
discussed 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 - 1997                 $22.10                $21.08                  $2.89                  $2.52
Second quarter - 1997                 17.71                 17.71                   2.02                   1.98
Third quarter - 1997                  18.40                 18.47                   2.25                   2.13
Fourth quarter - 1997                 18.72                 18.69                   2.92                   2.56
First quarter - 1998                  14.80                 15.30                   2.11                   2.07
Second quarter - 1998                 13.03                 13.82                   2.08                   2.06
Third quarter - 1998                  12.19                 13.06                   1.85                   1.95
</TABLE>



<PAGE>


HEP 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  received or paid
upon  settlement of hedge  contracts are recognized as oil or gas revenue at the
time the  hedged  volumes  are  sold.  During  1998,  HEP has not  entered  into
additional  oil price hedges for future years because hedge  contracts at prices
HEP considers advantageous are not available.

The following table provides a summary of HEP's outstanding financial contracts:

                                                Oil

                                   Percent of Production            Contract
             Period                           Hedged               Floor Price

                                                                    (per bbl)

Last three months of 1998                    22%                      $16.62
1999                                          2%                       15.38

Between  9% and 100% of the oil  volumes  hedged in each year are  subject  to a
participating  hedge  whereby HEP 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.
Between 59% and 100% of the volumes  hedged in each year are subject to a collar
agreement whereby HEP will receive the contract price if the spot price is lower
than the contract price,  the cap price if the spot price is higher than the cap
price,  and the spot price if that price is between the  contract  price and the
cap price. The cap prices range from $17.00 to $18.85.



<PAGE>






                                                  Gas

                                   Percent of Production            Contract
             Period                            Hedged              Floor Price

                                                                    (per mcf)

Last three months of 1998                    58%                       $2.07
1999                                         47%                        2.05
2000                                         45%                        2.10
2001                                         40%                        2.08
2002                                         33%                        2.14

Between  7% and 10% of the gas  volumes  hedged  in each year are  subject  to a
collar  agreement  whereby HEP 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 $2.59 to $2.93.

During the fourth  quarter  through  October 30, 1998 the  weighted  average oil
price (for barrels not hedged) was approximately $12.80 per barrel. The weighted
average  price of  natural  gas (for mcf not  hedged)  during  that  period  was
approximately $1.90 per mcf.

Inflation

Inflation is not  anticipated  to have a material  impact on the  Partnership in
1998.

Results of Operations

The  following  tables are  presented  to contrast  HEP's  revenue,  expense and
earnings for discussion purposes.  Significant fluctuations are discussed in the
accompanying  narrative.  The "direct  owned"  column  represents  HEP's  direct
royalty and  working  interests  in oil and gas  properties.  The "Mays"  column
represents the results of operations of six May Limited  Partnerships  which are
consolidated  with HEP. In 1998, HEP owned  interests which ranged from 54.8% to
69.1% and in 1997, HEP owned  interests  which ranged from 54.7% to 68.7% of the
Mays.


<PAGE>
<TABLE>
<CAPTION>


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


                                              For the Quarter Ended September 30, 1998     For the Quarter Ended September 30, 1997
                                             ----------------------------------------      ----------------------------------------
                                                Direct                                        Direct
                                                 Owned          Mays          Total            Owned         Mays         Total

<S>                                             <C>             <C>         <C>            <C>             <C>         <C>  
Gas production (mcf)                               3,524           278         3,802          2,734           380         3,114
Oil production (bbl)                                 188            13           201            171            22           193

Average gas price (per mcf)                     $   1.94      $   2.16      $   1.95       $   2.08      $   2.54      $   2.13
Average oil price (per bbl)                      $ 13.13       $ 12.08       $ 13.06        $ 18.42       $ 18.86       $ 18.47

Gas revenue                                      $ 6,820       $   601      $  7,421       $  5,675       $   964      $  6,639
Oil revenue                                        2,469           157         2,626          3,149           415         3,564
Pipeline, facilities and other revenue             1,067                       1,067            523                         523
Interest income                                      226            15           241             53            16            69
                                                --------      --------       -------       --------      --------      --------

   Total revenue                                  10,582           773        11,355          9,400         1,395        10,795
                                                  ------       -------        ------        -------        ------        ------

 Production operating expense                      2,982           101         3,083          2,933           139         3,072
 General and administrative expense                1,019            85         1,104            902            94           996
 Depreciation, depletion, and amortization         4,279           338         4,617          2,876           289         3,165
 Impairment of oil and gas properties              6,600                       6,600
 Interest expense                                    734                         734            716                         716
 Equity in (income) loss of HCRC                     767                         767           (138)                       (138)
 Minority interest in net income of affiliates                     203           203                          449           449
 Litigation                                          375                         375              9            24            33
                                               ---------   -----------     ---------     ----------      --------    ----------

   Total expense                                  16,756           727        17,483          7,298           995         8,293
                                                  ------       -------        ------        -------        ------       -------

     Net income (loss)                          $ (6,174)   $       46      $ (6,128)      $  2,102       $   400      $  2,502
                                                 =======     =========       =======        =======        ======       =======
</TABLE>

<TABLE>
<CAPTION>

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


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

<S>                                           <C>            <C>       <C>               <C>          <C>            <C>  
Gas production (mcf)                              9,568          895       10,463            7,563        1,025          8,588
Oil production (bbl)                                553           41          594              521           60            581

Average gas price (per mcf)                    $   1.99     $   2.39     $   2.02         $   2.15     $   2.75       $   2.22
Average oil price (per bbl)                     $ 14.11      $ 13.54      $ 14.07          $ 19.06      $ 20.47        $ 19.20

Gas revenue                                     $19,016       $2,143      $21,159          $16,255      $ 2,818        $19,073
Oil revenue                                       7,801          555        8,356            9,929        1,228         11,157
Pipeline, facilities and other revenue            2,743                     2,743            2,072                       2,072
Interest income                                     517           50          567              272           56            328
                                               --------     --------     --------         --------    ---------       --------

   Total revenue                                 30,077        2,748       32,825           28,528        4,102         32,630
                                                 ------       ------       ------           ------       ------         ------

 Production operating expense                     9,049          340        9,389            8,345          422          8,767
 General and administrative expense               3,078          275        3,353            2,958          292          3,250
 Depreciation, depletion, and amortization       10,321          913       11,234            7,754          903          8,657
 Impairment of oil and gas properties             9,200                     9,200
 Interest expense                                 1,927                     1,927            2,315                       2,315
 Equity in (income) loss of HCRC                  3,090                     3,090           (1,384)                     (1,384)
 Minority interest in net income of affiliates                   787          787                         1,341          1,341
 Litigation                                         930                       930             (234)          (6)          (240)
                                                -------   ----------     --------         --------    ---------       --------

   Total expense                                 37,595        2,315       39,910           19,754        2,952         22,706
                                                 ------       ------       ------           ------      -------         ------

     Net income (loss)                         $ (7,518)    $    433     $ (7,085)        $  8,774     $  1,150       $  9,924
                                                =======      =======      =======          =======      =======        =======
</TABLE>


<PAGE>


Third Quarter of 1998 Compared to Third Quarter of 1997

Gas Revenue

Gas revenue  increased  $782,000  during the third quarter of 1998 compared with
the  third  quarter  of 1997.  The  increase  is the  result of an  increase  in
production from 3,114,000 mcf in 1997 to 3,802,000 mcf in 1998 partially  offset
by a decrease  in the  average gas price from $2.13 per mcf in 1997 to $1.95 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 HEP's  hedging  transactions  as described  under  "Inflation  and
Changing  Prices,"  during the third  quarter  of 1998,  was to  increase  HEP's
average gas price from $1.85 per mcf to $1.95 per mcf,  representing  a $380,000
increase in revenue from hedging transactions.

Oil Revenue

Oil revenue  decreased  $938,000  during the third quarter of 1998 compared with
the third  quarter of 1997.  The  decrease  is the  result of a decrease  in the
average  oil price from  $18.47 per barrel in 1997 to $13.06 in 1998,  partially
offset by an  increase in  production  from  193,000  barrels in 1997 to 201,000
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 HEP's hedging  transactions  during the third quarter of 1998, was
to increase HEP's average oil price from $12.19 per barrel to $13.06 per barrel,
resulting in a $175,000 increase in revenue from hedging transactions.

Pipeline, Facilities and Other

Pipeline,  facilities and other revenue consists  primarily of facilities income
from two gathering  systems  located in New Mexico,  revenues  derived from salt
water  disposal  and  incentive  payments  related to certain  wells in San Juan
County, New Mexico and LaPlata County, Colorado. Pipeline,  facilities and other
revenue  increased  $544,000  during the third quarter of 1998 compared with the
third quarter of 1997 primarily due to increased  incentive  payment income from
the acquisition of the volumetric production payment during May 1998.

Interest Income

Interest  income  increased  $172,000  during the third quarter of 1998 compared
with the third quarter of 1997 due to a higher average cash balance during 1998.

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 the operating company on behalf of HEP.
These expenses increased $108,000 during the third quarter of 1998 primarily due
to increased salaries expense.

Depreciation, Depletion and Amortization Expense

Depreciation, depletion and amortization expense increased $1,452,000 during the
third quarter of 1998  compared with the third quarter of 1997.  The increase is
primarily the result of higher  capitalized costs and a higher depletion rate in
1998 due to the increase in production previously discussed.

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 $12.80 per bbl of oil and $1.90
per mcf of gas.


<PAGE>


Equity in Earnings (Loss) of HCRC

Equity in earnings (loss) of HCRC decreased $905,000 during the third quarter of
1998 compared  with the third quarter of 1997.  The decrease is primarily due to
decreased oil revenue caused by lower oil prices and increased  interest expense
due to HCRC's higher average outstanding debt balance during 1998.

Minority Interest in Net Income of Affiliates

Minority interest in net income of affiliates represents  unaffiliated partners'
interest in the net income of the May Partnerships.  The decrease of $246,000 is
due to a decrease in the net income of the May Partnerships  resulting primarily
from lower oil prices received for sales from their properties.

Litigation

Litigation  expense  during the third  quarter of 1998 is comprised of the costs
related  to the  Arcadia  arbitration  described  in Note 8 of the  accompanying
financial  statements.  Litigation  expense  during the third quarter of 1997 is
related  to  several  property  related  claims,  none of which is  individually
significant.

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  $2,086,000 during the first nine months of 1998 compared
with the first nine months of 1997. The increase is the result of an increase in
production from 8,588,000 mcf in 1997 to 10,463,000 mcf in 1998 partially offset
by a decrease in price from $2.22 per mcf in 1997 to $2.02 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 HEP's  hedging  transactions  during the first nine months of 1998
was to  increase  HEP's  average  gas price  from $2.00 per mcf to $2.02 per mcf
representing a $209,000 increase in revenue from hedging transactions.

Oil Revenue

Oil revenue  decreased  $2,801,000 during the first nine months of 1998 compared
with the first nine  months of 1997.  The  decrease  is due to a decrease in the
average  oil price  from  $19.20 per barrel in 1997 to $14.07 per barrel in 1998
partially  offset by an increase in production  from 581,000  barrels in 1997 to
594,000  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 HEP's  hedging  transactions  during the first nine months of 1998
was to  increase  HEP's  average  oil price from $13.35 per barrel to $14.07 per
barrel,  representing  an  increase  in revenue  from  hedging  transactions  of
$428,000.

Production Operating Expense

Production  operating expense increased $622,000 during the first nine months of
1998 compared with the first nine months of 1997.  The increase is primarily due
to  increased  production  taxes and  operating  expenses due to the increase in
production previously discussed.

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  $2.00  per mcf of gas,  as well as the third  quarter  property  impairment
previously discussed. Interest Expense

Interest  expense  decreased  $388,000  during  the  first  nine  months of 1998
compared  to the  first  nine  months  of 1997,  primarily  as a result of lower
average outstanding debt during 1998.

Equity in Earnings (Loss) of HCRC

Equity in earnings  (loss) of HCRC  decreased  $4,474,000  during the first nine
months of 1998  compared  to the first  nine  months of 1997.  The  decrease  is
primarily  due to a property  impairment  recorded by HCRC during the first nine
months of 1998.

Litigation

Litigation  expense during the first nine months of 1998 includes the settlement
of the  Ellender  lawsuit  described  in  Note 9 of the  accompanying  financial
statements in addition to the costs of the Arcadia arbitration  described above.
Litigation income during the first nine months of 1997 is comprised of insurance
proceeds  which  reimbursed  a portion of expense  incurred in a prior period to
settle certain litigation.



<PAGE>


PART II  -OTHER INFORMATION


ITEM 1     -  LEGAL PROCEEDINGS

              Reference  is made to Item 8 - Notes 12 and 13 of Form 10-K for
              the year  ended  December  31,  1997 and Notes 8 and 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
Partnership  has duly  caused  this  report to be  signed  on its  behalf by the
undersigned, thereunto duly authorized.

                                           HALLWOOD ENERGY PARTNERS, L. P.
                                           By:  HEPGP LTD.
                                                General Partner

                                           By:  HALLWOOD G. P., INC.
                                                General Partner



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