UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    Form 10-Q

MARK ONE
[X]          QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES
             EXCHANGE ACT OF 1934

                  For the Quarterly Period Ended March 31, 1999

[ ]          TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
             EXCHANGE ACT OF 1934

                          Commission File Number 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 May 11, 1999

Class A                   10,011,567
Class B                      143,773
Class C                    2,464,044








<PAGE>

<TABLE>
<CAPTION>

PART I.  FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS

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



                                                                       March 31,                December 31,
                                                                          1999                      1998

CURRENT ASSETS
<S>                                                                    <C>                         <C>      
    Cash and cash equivalents                                          $  5,723                    $  11,874
    Accounts receivable:
       Oil and gas revenues                                               4,987                        5,911
       Trade                                                              7,307                        4,040
    Due from affiliates                                                                                  119
    Prepaid expenses and other current assets                             1,339                        1,338
    Net working capital of affiliate                                        323                          236
                                                                     ----------                   ----------
         Total                                                           19,679                       23,518
                                                                       --------                     --------

PROPERTY,  PLANT  AND  EQUIPMENT,  at cost  Oil and gas  properties
  (full  cost  method):
       Proved mineral interests                                         667,764                      664,799
       Unproved mineral interests - domestic                              2,739                        2,694
    Furniture, fixtures and other                                         3,447                        3,411
                                                                      ---------                    ---------
         Total                                                          673,950                      670,904

    Less accumulated depreciation, depletion,
       amortization and property impairment                            (570,247)                    (565,899)
                                                                        -------                      -------
         Total                                                          103,703                      105,005
                                                                        -------                      -------

OTHER ASSETS
    Investment in common stock of HCRC                                    9,678                       10,160
    Deferred expenses and other assets                                      415                          408
                                                                     ----------                   ----------
         Total                                                           10,093                       10,568
                                                                       --------                     --------

TOTAL ASSETS                                                           $133,475                     $139,091
                                                                        =======                      =======
</TABLE>














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

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



                                                                               March 31,              December 31,
                                                                                  1999                     1998

CURRENT LIABILITIES
<S>                                                                           <C>                       <C>      
    Accounts payable and accrued liabilities                                  $  18,886                 $  22,921
    Current portion of long-term debt                                            12,676                     9,319
    Due from affiliates                                                             131              
                                                                             ----------
         Total                                                                   31,693                    32,240
                                                                               --------                  --------

NONCURRENT LIABILITIES
    Long-term debt                                                               38,024                    40,381
    Deferred liability                                                            1,019                     1,050
                                                                              ---------                 ---------
         Total                                                                   39,043                    41,431
                                                                               --------                  --------

           Total Liabilities                                                     70,736                    73,671
                                                                               --------                  --------

MINORITY INTEREST IN AFFILIATES                                                   2,734                     2,788
                                                                              ---------                 ---------

COMMITMENTS AND CONTINGENCIES (NOTE 5)

PARTNERS' CAPITAL
    Class A Units -  10,011,567  and  10,011,854  Units issued in 1999 and 1998,
      respectively; 9,121,325 and 9,121,612
      outstanding  in 1999 and 1998, respectively                                41,787                    44,198
    Class B Subordinated Units - 143,773 Units outstanding
      in 1999 and 1998                                                            1,125                     1,143
    Class C Units - 2,464,044 and 2,464,063 Units outstanding
      in 1999 and 1998, respectively                                             21,386                    21,386
    General partner                                                               2,616                     2,814
    Treasury Units - 890,242 Units in 1999 and
      1998, respectively                                                         (6,909)                    (6,909)
                                                                              ---------                  ---------
         Partners' Capital - Net                                                 60,005                     62,632
                                                                               --------                   --------

TOTAL LIABILITIES AND PARTNERS' CAPITAL                                        $133,475                   $139,091
                                                                                =======                    =======
</TABLE>














               The accompanying notes are an integral part of the
                             financial statements.


<PAGE>
<TABLE>
<CAPTION>


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



                                                                                   For the Three Months Ended
                                                                                            March 31,
                                                                                  1999                    1998

REVENUES:
<S>                                                                             <C>                      <C>     
    Gas revenue                                                                 $  6,490                 $  6,744
    Oil revenue                                                                    2,167                    3,090
    Pipeline, facilities and other                                                 1,209                      700
    Interest                                                                         116                      140
                                                                                --------                 --------
                                                                                   9,982                   10,674
                                                                                 -------                   ------

EXPENSES:
    Production operating                                                           3,058                    3,061
    Facilities operating                                                             175                      152
    General and administrative                                                     1,342                    1,165
    Depreciation, depletion and amortization                                       4,293                    3,539
    Interest                                                                         818                      644
                                                                                --------                 --------
                                                                                   9,686                    8,561
                                                                                 -------                  -------

OTHER INCOME (EXPENSES):
    Equity in loss of HCRC                                                          (482)                     (94)
    Minority interest in net income of affiliates                                   (132)                    (313)
    Litigation                                                                                                 45
                                                                             -----------                ---------
                                                                                    (614)                    (362)
                                                                                --------                 --------

NET INCOME (LOSS)                                                                   (318)                   1,751

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

NET INCOME (LOSS) ATTRIBUTABLE TO GENERAL
    PARTNER, CLASS A AND CLASS B LIMITED
    PARTNERS                                                                   $    (934)                $  1,135
                                                                                ========                  =======

ALLOCATION OF NET INCOME (LOSS):

General partner                                                                $     193                $     310
                                                                                ========                 ========
Class A and Class B Limited partners                                            $ (1,127)               $     825
                                                                                 =======                 ========
    Per Class A Unit and Class B Unit - basic                                  $    (.12)              $      .09
                                                                                ========                =========
    Per Class A Unit and Class B Unit - diluted                                $    (.12)             $       .09
                                                                                ========               ==========
    Weighted average Class A Units and Class B Units
       outstanding                                                                 9,265                    9,237
                                                                                 =======                  =======
</TABLE>







               The accompanying notes are an integral part of the
                             financial statements.


<PAGE>
<TABLE>
<CAPTION>


                                          HALLWOOD ENERGY PARTNERS, L. P.
                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                    (Unaudited)
                                                  (In thousands)

                                                                                 For the Three Months Ended
                                                                                           March 31,
                                                                                  1999                  1998

OPERATING ACTIVITIES:
<S>                                                                            <C>                    <C>     
    Net income (loss)                                                          $    (318)             $  1,751
    Adjustments to reconcile net income (loss) to net cash provided
       by (used in) operating activities:
          Depreciation, depletion and amortization                                 4,293                 3,539
          Depreciation charged to affiliates                                          55                    63
          Equity in loss of HCRC                                                     482                    94
          Minority interest in net income                                            132                   313
          Undistributed (earnings) loss of affiliates                               (631)                  253
          Recoupment of take-or-pay liability                                        (31)                  (33)
          Gain on asset disposals                                                                         (188)
          Amortization of deferred loan costs and other assets                                              30
          Noncash interest expense                                                                          15

    Changes in  operating  assets and  liabilities  provided  (used) cash net of
       noncash activity:
          Oil and gas revenues receivable                                            924                 2,416
          Trade receivables                                                       (3,267)                  157
          Due from affiliates                                                       (579)                    8
          Prepaid expenses and other current assets                                   (1)                  (68)
          Deferred expenses and other                                                 (7)
          Accounts payable and accrued liabilities                                (4,035)               (2,516)
          Due to affiliates                                                          131           
                                                                                --------
                Net cash provided by (used in) operating activities               (2,852)                5,834
                                                                                 -------               -------

INVESTING ACTIVITIES:
    Additions to property, plant and equipment                                      (964)                 (714)
    Exploration and development costs incurred                                    (1,875)               (2,555)
    Proceeds from sales of property, plant and equipment                              16                    20
    Distributions received from affiliate                                          1,019           
                                                                                 -------
                Net cash used in investing activities                             (1,804)               (3,249)
                                                                                 -------               -------

FINANCING ACTIVITIES:
    Proceeds from long-term debt                                                   1,000
    Proceeds from the issuance of Class C Units net of syndication                                      16,520
costs
    Payments of long-term debt                                                                         (14,000)
    Distributions paid                                                            (2,309)               (2,253)
    Payment of contract settlement                                                                      (2,767)
    Distribution paid by consolidated affiliates to minority interest               (186)                 (500)
    Exercise of Unit Options                                                                               199
    Capital contribution from the general partner                                                          171
                                                                             -----------              --------
                Net cash used in financing activities                             (1,495)               (2,630)
                                                                                 -------               -------

NET DECREASE IN CASH AND CASH EQUIVALENTS                                         (6,151)                  (45)

CASH AND CASH EQUIVALENTS:

BEGINNING OF PERIOD                                                               11,874                 6,622
                                                                                  ------               -------

END OF PERIOD                                                                   $  5,723              $  6,577
                                                                                 =======               =======
</TABLE>


               The accompanying notes are an integral part of the
                             financial statements.


<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 1998 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

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 Unit options
have been  ignored in the  computation  of diluted  loss per Class A and Class B
Unit for the three months ended March 31, 1999 because their  inclusion would be
antidilutive.


<PAGE>


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.
<TABLE>
<CAPTION>

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

For the Three Months Ended March 31, 1999
<S>                                                                    <C>                <C>            <C>    
   Net loss per Class A Unit and Class B Unit - basic                  $ (1,127)          9,265          $ (.12)
                                                                        -------           -----           =====
     Net Loss per Class A Unit and Class B Unit - diluted              $ (1,127)          9,265          $ (.12)
                                                                        =======           =====           =====

For the Three Months Ended March 31, 1998
   Net income per Class A Unit and Class B Unit - basic              $     825            9,237           $  .09
                                                                                                           =====
   Effect of Unit Options                                                                    86
                                                                    ----------           ------
     Net Income per Class A Unit and Class B Unit - diluted          $     825            9,323           $  .09
                                                                      ========            =====            =====
</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 of its own Units at March 31, 1999 and December 31, 1998. 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 month periods ended
March 31, 1999 and 1998.  Therefore,  total comprehensive  income (loss) was the
same as net income (loss) for those periods.

In June 1997,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards  No.  131  "Disclosures  about  Segments  of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards
for  reporting  selected   information  about  operating  segments  and  related
disclosures about products and services,  geographic areas, and major customers.
SFAS 131 requires that an entity report  financial and  descriptive  information
about  its  operating  segments  which  are  regularly  evaluated  by the  chief
operating  decision maker in deciding how to allocate resources and in assessing
performance. HEP adopted FAS 131 in 1998.

The Partnership engages in the development,  production and sale of oil and gas,
and the  acquisition,  exploration,  development  and  operation  of oil and gas
properties  in the  continental  United  States.  The  Partnership's  activities
exhibit  similar  economic   characteristics  and  involve  the  same  products,
production  processes,   class  of  customers,   and  methods  of  distribution.
Management of the  Partnership  evaluates its performance as a whole rather than
by product  or  geographically.  As a result,  HEP's  operations  consist of one
reportable segment.

In June 1998,  the  Financial  Accounting  Standards  Board issued  Statement of
Financial  Accounting  Standards No. 133 "Accounting for Derivative  Instruments
and  Hedging  Activities"  ("SFAS  133").  SFAS 133  establishes  standards  for
derivative  instruments,  including certain derivative  instruments  embedded in
other  contracts  (collectively  referred  to as  derivatives)  and for  hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities  in the statement of financial  position and measure those
instruments  at fair value.  If certain  conditions are met, a derivative may be
specifically  designated  as (a) a hedge of the  exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted  transaction,  or
(c) a hedge of the foreign  currency  exposure of a net  investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated  forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation.  The 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.  The
lenders  are Morgan  Guaranty  Trust  Company,  First  Union  National  Bank and
Nationsbank of Texas.  Under the Credit  Agreement,  HEP has a borrowing base of
$62,000,000. HEP had amounts outstanding at March 31, 1999 of $50,700,000. HEP's
unused borrowing base totaled $11,300,000 at March 31, 1999.

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 6.4%
at March 31, 1999. Interest is payable monthly, and quarterly principal payments
of $3,169,000  commence May 31, 1999. HEP intends to extend the maturity date of
its Credit Agreement prior to the commencement of the amortization period.

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.

As part of its risk management strategy,  HEP enters into financial contracts to
hedge the interest rate payments  under its Credit  Agreement.  HEP does not use
the hedges for trading purposes, but rather to protect against the volatility of
the cash flows under its Credit  Agreement,  which has a floating interest rate.
The  amounts  received  or  paid  upon  settlement  of  these  transactions  are
recognized as interest expense at the time the interest payments are due.

All contracts  are interest  rate swaps with fixed rates.  As of March 31, 1999,
HEP was a party to floor contracts with three different counterparties.

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

                                                                    Average
                                             Amount of              Contract
               Period                       Debt Hedged            Floor Rate

     Last nine months of 1999               $30,000,000               5.30%
     2000                                    30,000,000               5.65%
     2001                                    24,000,000               5.23%
     2002                                    25,000,000               5.23%
     2003                                    25,000,000               5.23%
     2004                                     4,000,000               5.23%



<PAGE>


NOTE 3    -  STATEMENTS OF CASH FLOWS

Cash paid for interest during the three months ended March 31, 1999 and 1998 was
$818,000 and $599,000, respectively.


NOTE 4    -  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. The arbitrators granted Arcadia prejudgment  interest on the
adjusted  purchase price, in the amount of $452,000.  That amount was accrued in
the December 31, 1998 financial  statements of the  Partnership and will be paid
during the second quarter of 1999.

In 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 $8,200,000.


NOTE 5    -  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.


NOTE 6 - SUBSEQUENT EVENT

On April 30, 1999, a Joint Proxy Statement/  Prospectus for the consolidation of
HEP with  HCRC and the  energy  interests  of The  Hallwood  Group  Incorporated
("Hallwood Group") into a new corporation called Hallwood Energy Corporation was
declared effective by the Securities and Exchange Commission.  The consolidation
must be approved by a majority of each class of outstanding  Units of HEP and of
the outstanding  shares of HCRC. The  consummation of the  consolidation is also
subject to a number of other conditions.


ITEM 2    -  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
             RESULTS OF OPERATIONS
             
During the first three months of 1999, HEP had a net loss of $934,000,  compared
to a net income of $1,135,000  for the first three months of 1998.  The weighted
average prices received by HEP for oil and gas have declined in each of the last
four quarters. HEP's hedges have mitigated the price reductions.  HEP's weighted
average oil and gas prices, when the effects of hedging are considered, were 25%
and 13% lower, respectively,  for the first three months of 1999 compared to the
first three months of 1998.



<PAGE>


In December 1998, HEP announced a proposal to consolidate  HEP with HCRC and the
energy interests of Hallwood Group into a new corporation called Hallwood Energy
Corporation.  The consolidation  proposal was approved by the Board of Directors
of HCRC and the general  partner of HEP in December 1998.  Because of the larger
size of the new corporation,  HEP anticipates that the new company will have the
ability to take  advantage  of  opportunities  that are  unavailable  to smaller
entities such as HEP and will have a better ability to raise  capital.  Hallwood
Energy   Corporation   will   focus   on   reserve   growth.   A   Joint   Proxy
Statement/Prospectus  for the consolidation,  filed with the Securities Exchange
Commission,   was  declared  effective  on  April  30,  1999.  The  Joint  Proxy
Statement/Prospectus  was  mailed  on May 4,  1999,  to  unitholders  of HEP and
stockholders  of HCRC of record as of April 14,  1999.  A meeting of the limited
partners of the Partnership will be held on May 25, 1999.

If the  consolidation  is approved,  public holders of Class A Units of Hallwood
Energy  Partners  will  receive  0.7417 of a share of common  stock of  Hallwood
Energy  Corporation  for each Class A Unit they now hold,  and public holders of
Class C Units will receive one share of redeemable  preferred  stock of Hallwood
Energy  Corporation for each Class C Unit they now hold. Public  stockholders of
Hallwood  Consolidated  Resources  will receive 1.5918 shares of common stock of
Hallwood  Energy  Corporation  for each share of stock  they now hold.  Hallwood
Group will also contribute its energy  interests to Hallwood Energy  Corporation
in  exchange  for  additional   shares  of  common  stock  of  Hallwood   Energy
Corporation.

Liquidity and Capital Resources

Cash Flow

HEP used $2,852,000 of cash flow in operating  activities during the first three
months of 1999.

The primary cash inflows were:

          o   Proceeds from long-term debt of $1,000,000; and

          o   Distributions received from affiliate of $1,019,000;

Cash was used primarily for:

o        Additions to property and development costs incurred of $2,839,000; and

o        Distributions to Unitholders of $2,309,000.

When combined with  miscellaneous  other cash  activity  during the period,  the
result was a decrease of $6,151,000 in HEP's cash from  $11,874,000  at December
31, 1998 to $5,723,000 at March 31, 1999.

Exploration and Development Projects and Acquisitions

Through March 31, 1999, HEP incurred  $2,839,000 in direct  property  additions,
development,  exploitation,  and exploration  costs. The costs were comprised of
$964,000 for property  acquisitions  and  approximately  $1,875,000 for domestic
exploration  and  development.  HEP's 1999 capital budget is set at $11,848,000.
During  the first  quarter  of 1999,  HEP  postponed  development  drilling  and
recompletions  for many  oil-targeted  projects due to the  historically low oil
prices  experienced  during  that time.  In April of 1999,  oil prices  began to
rebound and HEP is reevaluating the economics of these projects. The significant
capital expenditures for first quarter 1999 are discussed below.


<PAGE>


Rocky Mountain Region

HEP expended  approximately $732,000 of its capital budget in the Rocky Mountain
Region  located in Colorado,  Montana,  North  Dakota,  Northwest New Mexico and
Wyoming.  Of  this  amount,  approximately  $626,000  was for  the  purchase  of
overriding royalty interests and working interests in 18 of the coal bed methane
properties  currently owned and operated by HEP, located in San Juan County, New
Mexico. Most of the interests purchased qualify for tax credits under Section 29
of the  Internal  Revenue  Code.  The majority of the  acquired  interests  were
purchased  by 44 Canyon LLC ("44  Canyon") a special  purpose  entity owned by a
large East Coast  financial  institution  in  exchange  for cash,  a  production
payment,  and promissory notes. HEP's activity in the area began in 1990 and the
acquisition  increases HEP's net current average daily production by 475 mcf per
day.

Greater Permian Region

During  the first  quarter  of 1999,  HEP spent  approximately  $436,000  of its
capital budget in the Greater  Permian Region located in Texas and Southeast New
Mexico. The major projects within the Region are discussed below.

Catclaw  Draw/Carlsbad  Area  Projects.   HEP  incurred  approximately  $238,000
successfully recompleting one operated well and drilling one development well in
the  Carlsbad/Catclaw  Draw areas in Lea, Eddy and Chaves Counties,  New Mexico.
The development well is currently being completed.

Other Projects. HEP expended approximately $198,000 during first quarter of 1999
on various  maintenance  and facilities  projects,  and also for completing work
which commenced in 1998.

Gulf Coast Region

In the first  quarter of 1999,  HEP  expended  approximately  $1,210,000  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. HEP incurred  approximately $444,000 related to the Mirasoles
project in Kenedy  County,  Texas  during the first  quarter of 1999.  HEP began
drilling  the  17,000  foot  Frio  Formation  exploration  well in  1998  and is
completing the well, starting with the lower most zone and moving uphole.  Eight
potential pay zones are identified in this exploration  well, and the lower most
zone was abandoned for mechanical reasons following  encouraging,  but extremely
preliminary  results.  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. In the first three months of 1999, HEP incurred approximately
$141,000  for costs  associated  with a  non-operated  15,400  foot  directional
exploration well which tested the Wilcox formation in LaVaca County,  Texas. The
well was  completed  in 1998 and HEP owns a 7.5%  working  interest in the well.
Current  gross gas  production  is  approximately  9,500 mcf per day.  HEP began
drilling  an  additional  exploration  well in the second  quarter of 1999,  and
development drilling is anticipated in the latter months of 1999.

Boca Chica  Project.  During the first quarter of 1999,  HEP  participated  in a
directionally drilled 10,000 foot exploration well in the Big Hum formation from
the shore to a bottom  hole  location  under the  waters of the Gulf of  Mexico.
Despite  the  well  testing  wet,  the  exploration  results  were  sufficiently
encouraging that working interest owners agreed to shoot 3D seismic in the third
quarter of 1999 to evaluate future  potential.  It is anticipated  that a second
attempt  will be made in the first  quarter  of 2000,  possibly  reentering  the
existing  wellbore or using a shallow water  drilling rig. For its 12.5% working
interest, HEP spent approximately $226,000.

Other

The  remaining  $461,000 of HEP's first quarter 1999 capital  expenditures  were
devoted  principally to technical  general and  administrative  expenditures and
numerous   other  projects  which  are  completed  or  underway  and  which  are
individually less significant.


<PAGE>


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  $16,520,000.  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 May 14, 1999 to Unitholders of record on March 31, 1999.

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.

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.  The
lenders  are Morgan  Guaranty  Trust  Company,  First  Union  National  Bank and
Nationsbank of Texas.  Under the Credit  Agreement,  HEP has a borrowing base of
$62,000,000. HEP had amounts outstanding at March 31, 1999 of $50,700,000. HEP's
unused borrowing base totaled $11,300,000 at March 31, 1999.

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 6.4%
at March 31, 1999. Interest is payable monthly, and quarterly principal payments
of $3,169,000  commence May 31, 1999. HEP intends to extend the maturity date of
its Credit Agreement prior to the commencement of the amortization period.

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.

As part of its risk management strategy,  HEP enters into financial contracts to
hedge the interest rate payments  under its Credit  Agreement.  HEP does not use
the hedges for trading purposes, but rather to protect against the volatility of
the cash flows under its Credit  Agreement,  which has a floating interest rate.
The  amounts  received  or  paid  upon  settlement  of  these  transactions  are
recognized as interest expense at the time the interest payments are due.

All contracts  are interest  rate swaps with fixed rates.  As of March 31, 1999,
HEP was a party to four contracts with three different counterparties.


<PAGE>


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

                                                                    Average
                                             Amount of              Contract
               Period                       Debt Hedged            Floor Rate

     Last nine months of 1999               $30,000,000               5.30%
     2000                                    30,000,000               5.65%
     2001                                    24,000,000               5.23%
     2002                                    25,000,000               5.23%
     2003                                    25,000,000               5.23%
     2004                                     4,000,000               5.23%

Issues Related to the Year 2000

General.  The following  Year 2000  statements  constitute a Year 2000 Readiness
Disclosure  within  the  meaning  of the Year  2000  Information  and  Readiness
Disclosure  Act of 1998.  The Year 2000 problem has arisen because many existing
computer  programs  use only the last two digits to refer to a year.  Therefore,
these  computer  programs do not properly  recognize and process  date-sensitive
information  beyond  1999.  In  general,  there  are two areas  where  Year 2000
problems  may  exist  for  the  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 and inventory phases have been
substantially  completed and have identified the  Partnership's  IT systems that
must be updated or  replaced  in order to be Year 2000  compliant.  Remediation,
testing and  implementation  are scheduled to be completed by June 30, 1999, and
the  contingency  plans  phase  of the  Plan is  scheduled  to be  completed  by
September 30, 1999.

However,  the  effects of the Year 2000  problem on IT systems  are  exacerbated
because of the  interdependence  of computer  systems in the United States.  The
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;  responses have been received to approximately 66% of the
180 inquiries made.

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.  To date,  the
Partnership  has determined  that its IT systems are either  compliant or can be
made compliant for less than $100,000.  However,  although  management  believes
that its estimates are  reasonable,  there can be no assurance,  for the reasons
stated in the next paragraph, that the actual cost of implementing the Plan will
not differ materially from the estimated costs.


<PAGE>


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 in its third  party  relationships  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.  Although in general the  purchasers  and pipelines
will not guaranty their state of readiness,  the responses received to date have
indicated no material  problems.  The Partnership  believes that in a worst case
scenario,  the failure of its purchasers and transporters to conduct business in
a normal fashion could have a material  adverse effect on cash flow for a period
of six to  nine  months.  The  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.  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,  partners are
cautioned  that certain  events or  circumstances  could cause actual results to
differ materially from those projected, estimated or predicted.

Cautionary Statement Regarding Forward-Looking Statements

In the interest of providing the 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.  Please  refer  to the  Partnership's  Annual  Report  on Form  10-K for
additional  statements  concerning  important  factors  that could cause  actual
results to differ  materially from the Partnership's  expectations.  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.  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,  with a distinct downward
trend in both oil and gas prices occurring in the calendar year 1998 and through
the first quarter of 1999. In preparing its 1999 budget,  HEP has estimated that
the  weighted  average oil price (for  barrels  not  hedged)  will be $11.00 per
barrel,  and the weighted average price of natural gas (for mcf not hedged) will
be $1.70 per mcf for the year. The  Partnership  presently  believes oil and gas
prices for the remainder of 1999 will exceed the budgeted prices. However, there
can be no assurance  that HEP's forecast is accurate.  If prices  decrease below
the  forecasted  levels,  it can be expected that the results of operations  and
cash flow will be affected,  and HEP's budget will decrease. 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 - 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
Fourth quarter - 1998                 11.12                 12.29                   1.96                   2.02
First quarter - 1999                  11.33                 11.41                   1.65                   1.81
</TABLE>

As part of its risk management strategy,  HEP enters into 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.

The  financial  contracts  used by HEP to hedge the price of its oil and natural
gas  production  are swaps,  collars and  participating  hedges.  Under the swap
contracts,  HEP sells  its oil and gas  production  at spot  market  prices  and
receives or makes payments based on the differential  between the contract price
and a floating price which is based on spot market  indices.  As of May 3, 1999,
HEP was a party to 31 financial contracts with five different counterparties.

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

                                               Oil                 Contract

                                  Percent of Production           Delivered
            Period                          Hedged               Floor Price

                                                                  (per bbl)

Last nine months of 1999                    24%                     $14.71

Approximately 9% of the oil volumes hedged 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.  Additionally,  9% of the
volumes  hedged 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
$16.50 to $18.35.



<PAGE>






                                                Gas                Contract

                                  Percent of Production           Delivered
            Period                           Hedged              Floor Price

                                                                  (per mcf)

Last nine months of 1999                    53%                      $2.01
2000                                        45%                       2.08
2001                                        38%                       2.04
2002                                        30%                       2.09

Between  12% and 25% 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 $2.63 per mcf to $2.80 per mcf.

During the second  quarter  through May 3, 1999 the  weighted  average oil price
(for  barrels not  hedged) was  approximately  $15.20 per barrel.  The  weighted
average  price of  natural  gas (for mcf not  hedged)  during  that  period  was
approximately $1.75 per mcf.

Inflation

Inflation did not have a material  impact on HEP in 1998 and is not  anticipated
to have a material impact in 1999.

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 1999, HEP owned  interests which ranged from 54.8% to
69.1% and in 1998, 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 March 31, 1999           For the Quarter Ended March 31, 1998
                                                 ------------------------------------           ------------------------------------
                                                 Direct                                             Direct
                                                  Owned           Mays            Total              Owned         Mays       Total

<S>                                               <C>              <C>           <C>              <C>             <C>       <C>  
Gas production (mcf)                                3,351            229           3,580            2,945           320       3,265
Oil production (bbl)                                  181              9             190              187            15         202

Average gas price (per mcf)                      $   1.80       $   1.94        $   1.81        $    2.02     $    2.47   $    2.07
Average oil price (per bbl)                       $ 11.38        $ 12.00         $ 11.41         $  15.30      $  15.27    $  15.30

Gas revenue                                       $ 6,045      $     445         $ 6,490         $  5,952       $   792    $  6,744
Oil revenue                                         2,059            108           2,167            2,861           229       3,090
Pipeline, facilities and other revenue              1,209                          1,209              700                       700
Interest income                                       106             10             116              122            18         140
                                                 --------      ---------        --------         --------      --------    --------

   Total revenue                                    9,419            563           9,982            9,635         1,039      10,674
                                                   ------       --------          ------          -------        ------      ------

 Production operating expense                       2,979             79           3,058            2,940           121       3,061
 Facilities operating expense                         175                            175              152                       152
 General and administrative expense                 1,244             98           1,342            1,066            99       1,165
 Depreciation, depletion, and amortization          4,036            257           4,293            3,217           322       3,539
 Interest expense                                     818                            818              644                       644
 Equity in loss of HCRC                               482                            482               94                        94
 Minority interest in net income of affiliates                       132             132                            313         313
 Litigation                                                                                           (45)                      (45)
                                              -----------    -----------     -----------        ---------    ----------   ---------

   Total expense                                    9,734            566          10,300            8,068           855       8,923
                                                   ------       --------          ------          -------        ------     -------

     Net income (loss)                          $    (315)   $        (3)      $    (318)        $  1,567       $   184    $  1,751
                                                 ========     ==========        ========          =======        ======     =======
</TABLE>



<PAGE>


First Quarter of 1999 Compared to First Quarter of 1998

Gas Revenue

Gas revenue  decreased  $254,000  during the first quarter of 1999 compared with
the first  quarter of 1998.  The  decrease  is the  result of a decrease  in the
average gas price from $2.07 per mcf in 1998 to $1.81 per mcf in 1999  partially
offset by an increase in production  from 3,265,000 mcf in 1998 to 3,580,000 mcf
in 1999.  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 first  quarter  of 1999,  was to  increase  HEP's
average gas price from $1.65 per mcf to $1.81 per mcf,  representing  a $573,000
increase in revenue from hedging transactions.

Oil Revenue

Oil revenue  decreased  $923,000  during the first quarter of 1999 compared with
the first  quarter of 1998.  The  decrease  is the  result of a decrease  in the
average  oil price  from  $15.30  per  barrel  in 1998 to $11.41 in 1999,  and a
decrease in production  from 202,000 barrels in 1998 to 190,000 barrels in 1999.
The decrease in oil production is primarily due to normal production declines.

The effect of HEP's hedging  transactions  during the first quarter of 1999, was
to increase HEP's average oil price from $11.33 per barrel to $11.41 per barrel,
resulting in a $15,000 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  $509,000  during the first quarter of 1999 compared with the
first quarter of 1998 primarily due to increased  incentive  payment income from
the acquisition of the volumetric production payment during May 1998.

Interest Income

Interest income decreased $24,000 during the first quarter of 1999 compared with
the first quarter of 1998 due to a lower average cash balance during 1999.

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 $177,000 during the first quarter of 1999 primarily due
to increased salaries expense.

Depreciation, Depletion and Amortization Expense

Depreciation,  depletion and amortization  expense increased $754,000 during the
first quarter of 1999  compared with the first quarter of 1998.  The increase is
primarily the result of higher  capitalized costs and a higher depletion rate in
1999 due to the increase in production previously discussed.

Interest

Interest  expense  increased  $174,000 during the first quarter of 1999 compared
with the first quarter of 1998 due to a higher average  outstanding debt balance
during 1999.


<PAGE>


Equity in Loss of HCRC

Equity in loss of HCRC  increased  $388,000  during  the first  quarter  of 1999
compared  with the first  quarter of 1998.  The  increase  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 1999.

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 $181,000
during the first  quarter of 1999 compared with the first quarter of 1998 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  income during the first quarter of 1998 represents the settlement of
a take-or-pay contract claim.


<PAGE>


ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

HEP's primary market risks relate to changes in interest rates and in the prices
received  from sales of oil and  natural  gas.  HEP's  primary  risk  management
strategy is to partially  mitigate the risk of adverse changes in its cash flows
caused by increases in interest rates on its variable rate debt and decreases in
oil and natural gas prices, by entering into derivative  financial and commodity
instruments,  including swaps,  collars and  participating  commodity hedges. By
hedging only a portion of its market risk exposures,  HEP is able to participate
in the increased  earnings and cash flows  associated with decreases in interest
rates and  increases  in oil and natural gas prices;  however,  it is exposed to
risk on the unhedged  portion of its variable  rate debt and oil and natural gas
production.

Historically,  HEP has  attempted to hedge the exposure  related to its variable
rate debt and its  forecasted oil and natural gas production in amounts which it
believes  are prudent  based on the prices of  available  derivatives  and,  the
Partnership's  estimated debt levels and  deliverable  volumes.  HEP attempts to
manage the exposure to adverse  changes in the fair value of its fixed rate debt
agreements by issuing fixed rate debt only when business  conditions  and market
conditions are favorable.

HEP does not use or hold derivative instruments for trading purposes nor does it
use derivative instruments with leveraged features. HEP's derivative instruments
are designated and effective as hedges against its identified  risks, and do not
of themselves  expose HEP to market risk because any adverse  change in the cash
flows associated with the derivative  instrument is accompanied by an offsetting
change in the cash flows of the hedged transaction.

All derivative activity is carried out by personnel who have appropriate skills,
experience and supervision.  The personnel involved in derivative  activity must
follow prescribed  trading limits and parameters that are regularly  reviewed by
the Board of Directors of the general partner and by senior management. HEP uses
only well-known,  conventional derivative instruments and attempts to manage its
credit  risk by entering  into  financial  contracts  with  reputable  financial
institutions.

Following are disclosures  regarding HEP's market risk sensitive  instruments by
major category.  Investors and other users are cautioned to avoid simplistic use
of these  disclosures.  Users should  realize  that the actual  impact of future
interest rate and commodity  price movements will likely differ from the amounts
disclosed  below due to ongoing  changes in risk exposure  levels and concurrent
adjustments  to hedging  positions.  It is not  possible to  accurately  predict
future movements in interest rates and oil and natural gas prices.

Interest Rate Risks  (non-trading)  - HEP uses both fixed and variable rate debt
to partially finance operations and capital expenditures.  As of March 31, 1999,
HEP's debt  consists  of  borrowings  under its  Credit  Agreement  which  bears
interest at a variable  rate. HEP hedges a portion of the risk  associated  with
this  variable  rate debt  through  derivative  instruments,  which  consist  of
interest rate swaps and collars.  Under the swap  contracts,  HEP makes interest
payments on its Credit  Agreement  as scheduled  and receives or makes  payments
based on the differential between the fixed rate of the swap and a floating rate
plus  a  defined  differential.  These  instruments  reduce  HEP's  exposure  to
increases in interest  rates on the hedged portion of its debt by enabling it to
effectively pay a fixed rate of interest or a rate which only fluctuates  within
a predetermined  ceiling and floor. A hypothetical increase in interest rates of
two  percentage  points  would cause a loss in income and cash flows of $760,500
during the remaining nine months of 1999,  assuming that outstanding  borrowings
under the Credit  Agreement  remain at current  levels.  This loss in income and
cash  flows  would be offset by a  $450,000  increase  in income  and cash flows
associated with the interest rate swap and collar  agreements that are in effect
for the remaining nine months of 1999.



<PAGE>


Commodity  Price  Risk  (non-trading)  - HEP  hedges a portion of the price risk
associated  with the sale of its oil and natural gas production  through the use
of  derivative  commodity  instruments,  which  consist  of swaps,  collars  and
participating  hedges.  These instruments  reduce HEP's exposure to decreases in
oil and natural gas prices on the hedged  portion of its  production by enabling
it to effectively receive a fixed price on its oil and gas sales or a price that
only fluctuates between a predetermined  floor and ceiling.  HEP's participating
hedges also  enable HEP to receive 25% of any  increase in prices over the fixed
prices  specified  in the  contracts.  As of May 3, 1999,  HEP has entered  into
derivative  commodity hedges covering an aggregate of 167,000 barrels of oil and
17,934,000 mcf of gas that extend through 2002. Under the these  contracts,  HEP
sells its oil and natural gas  production  at spot market prices and receives or
makes  payments  based on the  differential  between  the  contract  price and a
floating  price which is based on spot market  indices.  The amount  received or
paid upon  settlement  of these  contracts is  recognized  as oil or natural gas
revenues at the time the hedged volumes are sold. A hypothetical decrease in oil
and  natural  gas prices of 10% from the  prices in effect as of March 31,  1999
would cause a loss in income and cash flows of  $2,512,000  during the remaining
nine  months  of 1999,  assuming  that oil and gas  production  remain at levels
during the last nine months of 1998. This loss in income and cash flows would be
offset by a $1,165,000 increase in income and cash flows associated with the oil
and natural gas  derivative  contracts that are in effect for the remaining nine
months of 1999.




<PAGE>


PART II  -OTHER INFORMATION


ITEM 1     -  LEGAL PROCEEDINGS

              Reference  is made to Item 8 - Notes 12 and 13 of Form 10-K for 
              the year ended  December 31, 1998 and Notes 7 and 8 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:  May 11, 1999                              By:  /s/Thomas J. Jung
                                                 Thomas J. Jung, Vice President
                                                   (Chief Financial Officer)