<PAGE>
 
                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549
                                _______________

                                  FORM 10-KSB
                                _______________

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 1998

                                      OR

[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934
    For the transition period from           to

                                                  Commission file number 0-22695

                             SHERIDAN ENERGY, INC.
            (Exact name of registrant as specified in its charter)

               Delaware                              76-0507664
   (State or other jurisdiction of               (I.R.S. Employer-
   incorporation or organization)                Identification No.)

             1000 Louisiana, Suite 800  Houston, Texas     77002
             (Address of principal executive offices)    (Zip Code)

       Registrant's telephone number, including area code (713) 651-7899

       SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:  NONE

          SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

           Title of each class         Name of each Exchange on which registered
      Common Stock, $.01 par value                  Nasdaq Small Cap
                                _______________

  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  [_]

  Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB:  [X]

  The aggregate market value of the voting stock held by non-affiliates as of
March 26, 1999, was approximately $10,001,000.  For this purpose, all shares
held by officers and directors of the registrant are considered to be held by
affiliates, but neither the registrant nor such persons concede that they are
affiliates of the Registrant.

  As of March 26, 1999, there were 6,731,276 shares of Common Stock outstanding.

                      DOCUMENTS INCORPORATED BY REFERENCE

  Portions of the Registrant's definitive Proxy Statement to be filed within 120
days after December 31, 1998, are incorporated by reference into Part III of
this Form 10-KSB.
<PAGE>
 
                                     INDEX

                                                                           Page
Item                                                                      Number
----                                                                      ------

PART I.......................................................................  1
     ITEM 1.  DESCRIPTION OF BUSINESS........................................  1
     ITEM 2.  DESCRIPTION OF PROPERTY........................................ 15
     ITEM 3.  LEGAL PROCEEDINGS.............................................. 15
     ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............ 16

PART II...................................................................... 17
     ITEM 5.  MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS....... 17
     ITEM 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION...... 18
     ITEM 7.  FINANCIAL STATEMENTS........................................... 26
     ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
              ACCOUNTING AND FINANCIAL DISCLOSURE............................ 52

PART III..................................................................... 52
     ITEM 9.  DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
              PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE
               ACT........................................................... 52
     ITEM 10. EXECUTIVE COMPENSATION......................................... 52
     ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
              AND MANAGEMENT................................................. 52
     ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................. 52
     ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K............................... 52

SIGNATURES................................................................... 56
 

     This report contains certain forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended and Section 21E of the
Securities Exchange Act of 1934, as amended, which are intended to be covered by
safe harbors created thereby.  Stockholders are cautioned that all forward-
looking statements involve risks and uncertainty, including without limitation,
statements about the cost of exploring and developing new oil and natural gas
reserves, the price for which such reserves can be sold, the Company's attempts
to reduce overhead and eliminate non-core assets, environmental concerns
affecting the drilling of oil and natural gas wells, the effect of the Merger,
the attempts to acquire producing and non-producing oil and gas properties, the
ability of the Company to make projected capital expenditures, secure required
capital, achieve projected quarterly results, achieve compliance with Year 2000
issues and general market conditions, competition and pricing.

     All statements, other than statements of historical facts, included or
incorporated by reference in this document that address activities, events or
developments that the Company expects or anticipates will or may occur in the
future, including such things as future capital expenditures and acquisitions,
business strategy and measures to implement such strategy, competitive
strengths, goals, expansion and growth of the Company's business and operations,
plans, references to future success as well as other statements which include
words such as "anticipate," "believe," "plan," "estimate," "expect," and
"intend," and other similar expressions constitute forward-looking statements.
Although the Company believes that the assumptions underlying the forward-
looking statements contained herein are reasonable, any of the assumptions could
be inaccurate, and therefore, there can be no assurance that the forward-looking
statements included in this document will prove to be accurate.  In light of the
significant uncertainties inherent in the forward-looking statements included
herein, the inclusion of such information should not be regarded as a
representation by the Company or any other person that the objectives and plans
of the Company will be achieved.


                                       i
<PAGE>
 
                                    PART I

ITEM 1.   DESCRIPTION OF BUSINESS

General

     Sheridan Energy, Inc. ("Sheridan" or the "Company"), a Delaware
Corporation, is a successor to TGX Corporation ("TGX"), a Delaware corporation
that was organized in June 1980.  Sheridan is a domestic independent energy
company engaged in the exploration and production of oil and natural gas.  The
Company's core properties and operations are in the Sacramento Basin of
California and South Texas.  Sheridan is also engaged in intrastate natural gas
gathering and treating.

     TGX commenced operations on July 1, 1981 as the result of the consummation
of an offer in which shares of its common stock (the "TGX Common Stock") were
issued in exchange for certain interests in developed and undeveloped oil and
natural gas properties held by various affiliated and unaffiliated entities.  On
December 5, 1985, TGX acquired Amarex, Inc. ("Amarex"), an oil and gas
exploration company operating primarily through general and limited partnerships
(the "Amarex Partnerships"), in exchange for the payment of approximately $52.0
million in cash and the issuance of approximately 11.5 million shares of TGX
Common Stock to former creditors of Amarex.  Following this acquisition, TGX was
general partner of the Amarex Partnerships until their liquidation or
dissolution in 1994.

     On February 22, 1990, TGX filed a voluntary petition in the United States
Bankruptcy Court for the Western District of Louisiana (the "Bankruptcy Court")
for reorganization (the "Reorganization Proceeding") pursuant to Chapter 11
("Chapter 11") of Title 11 of the United States Bankruptcy Code.
 
     On January 7, 1992, a reorganization plan (the "Reorganization Plan") was
confirmed by the Bankruptcy Court and the Reorganization Plan became effective
on January 21, 1992 (the "Effective Date"). On October 2, 1992, the Bankruptcy
Court's order of substantial consummation regarding the Reorganization Plan
became final and non-appealable.

     Sheridan was organized as a wholly-owned subsidiary of TGX on July 1, 1996,
under the name GeoStrat Resources, Inc.  The Company changed its name to
Sheridan Energy, Inc. on May 7, 1997.  On June 12, 1997, TGX was merged (the
"Merger") into Sheridan and, at that time, all of the persons owning TGX Series
A Senior Preferred Stock (the "TGX Senior Preferred Stock") had such preferred
stock exchanged for Sheridan common stock ("Sheridan Common Stock") on the basis
of 0.5 shares of Sheridan Common Stock for each share of TGX Senior Preferred
Stock.  At that same time, pursuant to the terms of the Merger, holders of all
other classes of equity securities of TGX had their securities eliminated.

     The Company's executive offices are at 1000 Louisiana Street, Suite 800,
Houston, Texas 77002, and its telephone number is (713) 651-7899.  When used
herein, unless the context otherwise requires, the term "Sheridan" or the
"Company" includes activities of its predecessor, TGX as well as Sheridan's
subsidiary companies.

Business Strategy

     After substantial consummation of the Reorganization Plan in 1992, and in
order to maximize stockholder value, the Company embarked on a strategy of
eliminating non-core assets, reducing overhead and restructuring its debt.
During 1993 and 1994, a substantial portion of management's efforts were engaged
in implementing the components of this business plan. Beginning in 1995, the
Company turned its focus to increasing its oil and gas reserves and revenues
through a limited number of strategic acquisitions and the drilling of a small
number of oil and gas exploration and development wells.

     On April 12, 1996, TGX entered into a settlement agreement (the
"Settlement Agreement") with National Fuel Gas Distribution Corporation ("NFG")
and the Public Service Commission of the State of New York to settle a long-
standing significant lawsuit. Pursuant to the Settlement Agreement, TGX received
$7.2 million from NFG, and 
<PAGE>
 
all parties to the Settlement Agreement dismissed all claims and counterclaims
against each other. In conjunction with the Settlement Agreement, TGX recognized
a net litigation settlement gain of $7.1 million, after payment of $100,000 to a
third party entitled to participate in the proceeds. As TGX's financial
condition continued to improve, TGX expanded its drilling and property
acquisition activity resulting in total 1996 capital expenditures of $4.3
million.

     Subsequent to the Merger, Sheridan has engaged in three significant oil and
gas property acquisitions.  In December 1997, but effective as of November 1,
1997, the Company acquired approximately $46.7 million of oil and gas producing
and non-producing properties from Pioneer Natural Resources USA, Inc. (the
"Pioneer Acquisition").  As a result of the Pioneer Acquisition, the Company
obtained an interest in approximately 329 gross (156.9 net) producing oil and
gas wells and approximately 79,000 gross (31,400 net) producing and non-
producing oil and gas leasehold acres in Texas, Oklahoma, Mississippi and
Louisiana.  In order to finance a portion of the Pioneer Acquisition, the
Company renegotiated its bank line of credit and borrowed approximately $28.0
million.  See "Bank Indebtedness."  In addition, the Company entered into an
agreement (the "ECT Agreement") with Enron Capital & Trade Resources Corp.
("ECT"), an unaffiliated party, pursuant to which ECT acquired 1.0 million
shares of the Company's Series A Preferred Stock (the "Sheridan Preferred
Stock") and 1.6 million shares of Sheridan Common Stock.  For information about
the Sheridan Preferred Stock, see "Item 5. Market for Common Equity and Related
Stockholder Matters" and Note 9 of the Notes to Consolidated Financial
Statements.

     On December 31, 1997, but effective as of September 1, 1997, the Company
acquired additional oil and gas producing properties in Louisiana (the "Grand
Gulf Acquisition") for approximately $4.1 million of consideration consisting of
850,000 shares of Sheridan Common Stock and warrants to acquire an additional
150,000 shares of Sheridan Common Stock.  Such warrants expire five years after
the date of issuance and are exercisable in whole or in part from time to time
at a price of $5.50 per share.  The properties were acquired from Grand Gulf
Properties, L.L.C. ("Grand Gulf") and JEDI Hydrocarbon Investments I Limited
Partnership ("JEDI I").  Through a series of transactions among Grand Gulf,
other related parties and Joint Energy Development Investments Limited
Partnership ("JEDI"), a Delaware limited partnership and sole limited partner of
JEDI I, the 850,000 shares of Sheridan Common Stock and the 150,000 warrants are
now owned by JEDI or JEDI I.  JEDI and JEDI I are affiliates of ECT.

     On January 25, 1999, but effective as of November 1, 1998, the Company,
through a newly formed subsidiary, Sheridan California Energy, Inc. ("SCEI"),
acquired approximately $58.0 million of oil and gas producing and non-producing
properties (the "California Properties") from Amerada Hess Corporation (the
"Amerada Transaction").  As a result of the Amerada Transaction, SCEI obtained
an interest in approximately 82 billion cubic feet of proven natural gas
reserves in the Sacramento Basin, California.  In order to finance a portion of
the Amerada Transaction, SCEI received a borrowing base facility from Bank One,
Texas, N.A. ("Bank One") in the amount of approximately $43.0 million, of which
approximately $30.6 million was borrowed in January 1999.  See "Bank
Indebtedness."  In addition, the Company entered into an agreement (the
"Formation Agreement") with Calpine Corporation ("Calpine") and CPN Production
Company ("CPN"), each unaffiliated parties, pursuant to which SCEI was created
to acquire and own the California Properties.  CPN contributed $14.9 million in
cash and received $13.0 million in seven-year redeemable non-voting preferred
stock of SCEI (the "SCEI Preferred Stock") and 20% of the outstanding common
stock of SCEI.  In certain circumstances, the Company may be entitled to acquire
the common stock of SCEI held by CPN.  The Company contributed $3.0 million in
cash and $4.6 million of seismic and oil and gas producing assets in California
and received 80% of the outstanding common stock of SCEI.  For information about
the SCEI Preferred Stock, see "Item 5. Market for Common Equity and Related
Stockholder Matters."

     In 1999, the Company intends to continue its program of reviewing the
possible acquisition of oil and gas producing and non-producing properties,
drilling exploration and development wells and attempting to enhance its current
oil and gas reserve position.  However, in view of recent product prices which
have affected the Company's ability to borrow additional funds, Sheridan does
not currently expect to acquire any significant oil and gas properties or
reserves in 1999.  As part of its overall effort, the Company may seek out
strategic alliances or other opportunities to expand its reserve base and
increase cash flow.  The Company may seek out joint venture partners to spread
the risk and costs of such acquisitions and development, use bank and
institutional debt financing to fund a portion of the costs of the facilities or
properties or raise additional capital through the sale of debt or equity
securities. No assurance can be made that joint venture partners or debt
financing or equity capital will be available to fund the Company's 

                                       2
<PAGE>
 
acquisition or development of additional facilities or properties or that the
Company could obtain debt financing or equity capital on terms that the Company
would consider reasonable or, in the case of a sale of equity securities, on
terms that would not be dilutive to existing stockholders.

Bank Indebtedness

Sheridan

In July 1994, TGX entered into agreements with Bank One whereby Bank One
established a borrowing base facility (the "Bank One Facility") of $2.4 million
under which $1.4 million was paid to the Company's previous bank lender in
satisfaction of the remaining amount due to such lender.  The Bank One Facility
originally bore interest at Bank One's stated rate plus 2% and was to mature on
July 13, 1997. Effective September 30, 1996, the Bank One Facility was amended
and the borrowing base was increased to $5.0 million, with monthly borrowing
base reductions of $100,000, the interest rate was lowered to the stated rate
plus 1.5% and the maturity was extended to June 30, 1999.

     In late 1997, in conjunction with the Pioneer Acquisition, the Bank One
Facility was further amended, with the borrowing base increased to $40.0 million
and the maturity date extended to June 30, 2000.  Under the current facility,
the Company may elect to borrow at Bank One's stated rate or LIBOR plus 2.5%.
The Bank One Facility is secured by substantially all of Sheridan's oil  and gas
properties and is repayable through monthly borrowing base reductions of
$550,000.  The borrowing base is redetermined every six months or at Bank One's
discretion.  At December 31, 1998, the Company's borrowing base under this
facility was $39.0 million, and the Company had $37.5 million borrowed and
letters of credit of $1.2 million outstanding.  In January 1999, the borrowing
base was redetermined to be $38.5 million and year-end Bank One borrowings were
reduced by $2.8 million in conjunction with the completion of the Amerada
Transaction.  Based on year-end borrowings outstanding and the current monthly
facility reduction rate, current maturities for debt of $5.6 million were
reflected at December 31, 1998.

     The Bank One Facility requires the maintenance of certain financial ratios
including ratios relating to working capital, as adjusted pursuant to the credit
facility, tangible net worth, cash flow to debt service of 1.1 to 1.0 and annual
limitations on general and administrative expense and non-oil and gas capital
expenditures.  In addition, the payment of dividends on Sheridan Common Stock
and preferred stock is restricted except that cash dividends may be paid on the
Sheridan Preferred Stock if the Company has a cash flow to debt service ratio of
at least 1.2 to 1.0.  The Company was in default on certain of these financial
ratios at December 31, 1998, but received waivers from Bank One regarding these
covenants.  See Note 4 of the Notes to Consolidated Financial Statements.

SCEI

     In January 1999, in conjunction with the Amerada Transaction, Bank One
extended a borrowing base facility (the "SCEI Facility") to SCEI, initially with
a borrowing base of $43.0 million and a maturity of December 31, 2001.  Under
the SCEI Facility, SCEI may elect to borrow at Bank One's stated rate or LIBOR
plus 2.5%.  The SCEI Facility is secured by substantially all of SCEI's oil and
gas properties and is repayable through monthly borrowing base reductions of
$450,000.  The borrowing base is redetermined every six months or at Bank One's
discretion.  At the funding date of the SCEI Facility, SCEI borrowed $30.6
million and anticipates borrowing an additional $7.1 million upon final closing
of the Amerada Transaction in April 1999.  The SCEI Facility is repayable only
by SCEI and is not an obligation of Sheridan.

     The SCEI Facility requires the maintenance of certain financial ratios
including ratios relating to working capital, tangible net worth, cash flow to
debt service of 1.1 to 1.0 and annual limitations on general and administrative
expense and non-oil and gas capital expenditures of SCEI.  In addition, the
payment of dividends on SCEI common stock and preferred stock is restricted
except that cash dividends may be paid on the SCEI Preferred Stock if SCEI has a
cash flow to debt service ratio of at least 1.2 to 1.0.  See Note 18 of the
Notes to Consolidated Financial Statements.

                                       3
<PAGE>
 
Reorganization Proceeding

     The following is a brief summary of certain information regarding the
Reorganization Plan.  The summary is necessarily incomplete and selective and is
qualified in its entirety by reference to the Reorganization Plan, the full
terms of which are hereby incorporated by reference.

     Pursuant to the Reorganization Plan, TGX satisfied unsecured claims with
cash or TGX Senior Preferred Stock or otherwise retained or provided for such
claims.  In addition, certain executory contracts were assumed or rejected.

     The Reorganization Plan provided for a total of approximately 8.5 million
shares of TGX Senior Preferred Stock to be issued to holders of certain
unsecured claims on the basis of one share of TGX Senior Preferred Stock for
every $10 of certain finally allowed or otherwise agreed-upon claims.  In
addition, certain administrative claimants received shares of TGX Senior
Preferred Stock.  The TGX Senior Preferred Stock entitled its holders to receive
a 10% annual compounded cash dividend, payable quarterly, and had a liquidation
preference in the amount of $10 per share.

     As of the date of the Merger, no dividends had been paid to the holders of
the TGX Senior Preferred Stock, and accrued, but unpaid, dividends on the TGX
Senior Preferred Stock totaled approximately $59.0 million. This dividend
obligation, together with the liquidation preference with respect to the
outstanding 8.7 million shares of TGX Senior Preferred Stock of approximately
$86.8 million, would have required an aggregate payment of approximately $145.8
million to redeem the TGX Senior Preferred Stock.  In order to eliminate these
obligations, the Merger was consummated, whereby the TGX Senior Preferred Stock
was exchanged for Sheridan Common Stock and holders of all other classes of
equity securities of TGX had their securities eliminated.


Business Segment Information

     The only segment in which Sheridan operates is the development and
production of, and to a lesser degree the exploration for, oil and natural gas
plus intrastate natural gas gathering and treating.


Properties

     Oil and Gas Exploration and Production.   Prior to 1995, the Company's
principal post-bankruptcy activity was the production of oil and natural gas. In
1995, the Company began a modest program of oil and natural gas exploration and
development drilling and property acquisition activities as allowed by its
financial condition. In 1996, as the Company's financial condition continued to
improve, the Company expanded its development drilling and property acquisition
activity resulting in total 1996 capital expenditures of $4.3 million. During
1997, capital expenditures totaled $54.9 million, reflecting a significant
expansion of its property acquisition activities through the completion of the
Pioneer Acquisition.  Additionally, in conjunction with the Grand Gulf
Acquisition, the Company issued 850,000 shares of Sheridan Common Stock and
warrants to purchase an additional 150,000 shares of Sheridan Common Stock
valued at $4.1 million.  In 1998, in furtherance of its property acquisitions
and development and exploration drilling activity, the Company incurred capital
expenditures of $17.4 million and sold non-core producing properties for net
proceeds of $12.7 million.  In January 1999, the Company consummated, through
SCEI, the Amerada Transaction.  See Notes 3 and 18 of the Notes to Consolidated
Financial Statements.

     Proved Oil and Natural Gas Reserves.

     (a)  General:

     Estimating economically recoverable crude oil and natural gas reserves and
their future net revenues is not an exact science and is based upon a number of
variables, such as historical production of the subject properties as compared
with similar producing properties, and assumptions such as the effects of
regulation by governmental agencies, future taxes, and development and other
costs, all of which may vary considerably from actual results. All such

                                       4
<PAGE>
 
estimates are to some degree speculative, and classifications of reserves are
only attempts to define the degree of speculation involved. For these reasons,
estimates of economically recoverable reserves of crude oil and natural gas
attributable to any particular group of properties, the classification and risk
of recovering such reserves, and estimates of the future net revenues expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially.

     Proved oil and natural gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Estimates
with respect to proved undeveloped and proved developed non-producing reserves
that may be developed and produced in the future are based upon volumetric
calculations or upon analogy to similar types of reservoirs. Later studies of
the same reservoirs based upon production history may result in variations,
which may be substantial.  The actual production, revenues, severance and excise
taxes, development costs, and operating expenditures with respect to the
Company's reserves as reflected herein may vary from estimates, and such
variances may be material.

     Based on the independent petroleum engineering report of Netherland, Sewell
& Associates, Inc., as of December 31, 1998 and 1997, utilizing year-end product
prices and costs held constant, the Company's proved oil and natural gas reserve
volumes, in thousands of barrels ("MBbls") and billion cubic feet ("Bcf"), and
associated estimated future net revenues, undiscounted and discounted at 10%
("PV 10"), before future income taxes, are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                        1998                               1997
                                        ----                               ----
                             OIL(MBbls)        GAS(Bcf)         OIL(MBbls)        GAS(Bcf)
                             ----------        --------         ----------        --------
<S>                        <C>              <C>               <C>               <C>
Proved developed                  1,253            46.0              1,514            55.3
Proved undeveloped                  294             9.9                724             9.5
                             ----------        --------         ----------        --------
     Total proved reserves        1,547            55.9              2,238            64.8
                             ==========        ========         ==========        ========

                                        1998                               1997
                                        ----                               ----
                            UNDISCOUNTED         PV 10         UNDISCOUNTED        PV 10
                             ----------        --------         ----------        --------
Proved developed             $   70,277        $ 45,074         $  105,088        $ 62,209
Proved undeveloped               11,220           5,411             19,578          10,165
                             ----------        --------         ----------        --------
     Total proved reserves   $   81,497        $ 50,485         $  124,666        $ 72,374
                             ==========        ========         ==========        ========
</TABLE>

     Included in 1998 undiscounted and PV 10 values are $1.4 million and $1.3
million, respectively, representing the estimated value of the Company's natural
gas swap agreements outstanding as of December 31, 1998.  Estimated future
development costs associated with proved developed non-producing and proved
undeveloped reserves for 1998 and 1997 total $8.7 million and $11.9 million,
respectively.  Production of those reserves is dependent upon the Company's
ability to fund such future development costs, which are scheduled to be
incurred over a number of years.  As required by the Bank One Facility and the
ECT Agreement, the Company entered into swap agreements to reduce its exposure
to price fluctuations on a portion of its natural gas sales in 1998, 1999 and
2000 and to achieve a more predictable cash flow.  As of December 31, 1998 the
Company had hedged approximately 3.7 Bcf and 2.2 Bcf of 1999 and 2000 natural
gas production, at a weighted average sales price per Mcf of approximately $2.51
and $2.36, respectively.  In early 1999, the Company hedged an additional 1.1
Bcf of 1999 natural gas production resulting in total 1999 volumes hedged of 4.8
Bcf or 75% of 1999 proved developed producing reserves as estimated by the
Company's independent petroleum engineers at a weighted average sales price per
Mcf of approximately $2.44.  The Company currently has no oil price hedges in
place for 1999 or 2000 production.  See Note 19 of the Notes to Consolidated
Financial Statements for a discussion of the calculation of the estimated future
net revenues on an undiscounted and discounted basis.

                                       5
<PAGE>
 
     The following shows the same information as set forth above, except that
the effect of the Amerada Transaction is included as if such transaction had
been consummated as of December 31, 1998 .

                                           1998
                                           ----
                                OIL(MBbls)       GAS(Bcf)
                               ----------         --------
Proved developed                    1,285            126.0
Proved undeveloped                    294             12.7
                              -----------        ---------
Total proved reserves(1)            1,579            138.7
                              ===========        ========= 

                                            1998
                                            ----
                             UNDISCOUNTED          PV 10
                             ------------          -----
Proved developed              $   203,116        $ 120,802
Proved undeveloped                 15,942            8,066
                              -----------        ---------
Total proved reserves(2)      $   219,058        $ 128,868
                              ===========        =========

--------------
(1)  Includes 6 MBbls and 16.6 Bcf attributable to a 20% minority interest in
     the Amerada Transaction properties.

(2)  Undiscounted and PV 10 value includes $27,512 and $15,677, respectively,
     attributable to a 20% minority interest in the Amerada Transaction
     properties.

     Included in 1998 undiscounted and PV 10 values are $2.4 million and $2.3
million, respectively, representing the estimated value of the Company's natural
gas swap agreements as of December 31, 1998 including hedge value related to the
Amerada Transaction property hedges of $1.0 million and $1.0 million,
respectively.  Estimated future development costs associated with the properties
proved developed non-producing and proved undeveloped reserves for 1998 total
$10.6 million, including $1.9 million related to the Amerada Transaction
properties.  For 1999 the Company has hedged approximately 77% of consolidated
1999 proved developed producing natural gas production, as estimated by
independent petroleum engineers, at a weighted average sales price per Mcf of
approximately $2.43.

     (b)  Tabular Information:

     The table below sets forth an analysis of the change in the Company's
proved oil and natural gas reserves for the periods indicated.

                                           1998                1997
                                     ----------------    ---------------
                                       OIL       GAS       OIL      GAS
                                     (MBbls)    (Bcf)    (MBbls)   (Bcf)
                                     -------    -----    -------   -----
Proved reserves:
 Beginning of year                    2,238      64.8       981     15.8
 Sales of reserves-in-place            (340)    (12.4)       --      (.1)
 Purchases of reserves-in-place         171       5.3     1,322     46.8
 Extensions and discoveries              39       8.1        68      4.3
 Revisions of previous estimates       (359)     (2.7)      (40)      .2
 Production                            (202)     (7.2)      (93)    (2.2)
                                     ------     -----    ------    -----
 End of year                          1,547      55.9     2,238     64.8
                                     ======     =====    ======    =====
Proved developed reserves             1,253      46.0     1,514     55.3
                                     ======     =====    ======    =====


                                       6
<PAGE>
 
     The following shows the same information as set forth above, except that
the effect of the Amerada Transaction is included as if such transaction had
been consummated as of December 31, 1998.

                                           1998                1997
                                     ----------------    ---------------
                                       OIL       GAS       OIL      GAS
                                     (MBbls)    (Bcf)    (MBbls)   (Bcf)
                                     -------    -----    -------   -----
Proved reserves:
 Beginning of year                    2,238      64.8       981     15.8
 Sales of reserves-in-place            (340)    (12.4)       --      (.1)
 Purchases of reserves-in-place         203      88.1     1,322     46.8
 Extensions and discoveries              39       8.1        68      4.3
 Revisions of previous estimates       (359)     (2.7)      (40)      .2
 Production                            (202)     (7.2)      (93)    (2.2)
                                     ------     -----    ------    -----
 End of year(1)                       1,579     138.7     2,238     64.8
                                     ======     =====    ======    =====
Proved developed reserves             1,285     126.0     1,514     55.3
                                     ======     =====    ======    =====
--------------
(1)  1998 includes oil and natural gas reserves of 32 MBbls and 82.8 Bcf,
     respectively, attributable to SCEI in which there is a 20% minority
     interest.

     Except for the data contained in filings with the Securities and Exchange
Commission and information furnished in conjunction with the Reorganization
Proceeding pursuant to the order of the Bankruptcy Court, the Company has not
filed information relating to estimates of its proved oil and natural gas
reserves with any federal agencies.

     Oil and Gas Production.  The following table sets forth information
pertaining to the Company's oil and natural gas production revenues, average
price and average costs per equivalent Mcf of natural gas.  Average natural gas
price is shown per thousand cubic feet of gas ("Mcf") and equivalent Mcf
("Mcfe") is based on one barrel of oil or condensate is equal to six Mcf of
natural gas on a heating value basis.

                                                    YEAR ENDED DECEMBER 31,
                                                    -----------------------
                                                      1998           1997
                                                    --------       --------
Net Production:
     Oil (MBbls)                                        202             93
     Natural gas (MMcf) (includes liquids)            7,165          2,163
     Total production (MMcfe)                         8,376          2,722
     Average daily production (MMcfe)                  23.0           7.50
 
Oil and natural gas revenues (in thousands):
     Oil and condensate sales                      $  2,914         $1,805
     Natural gas sales                             $ 14,987         $5,269
 
Average realized price (including 1998 price hedges):
     Oil and condensate (per Bbl)                  $  14.43         $19.38
     Natural gas (per Mcf)                         $   2.09         $ 2.44
 
Operating costs:
     Lease operating expense (in thousands)        $  5,097         $1,703
     Lease operating expense per Mcfe (excludes    
      production taxes)                            $   0.61         $ 0.63

                                       7
<PAGE>
 
     Wells. The following table summarizes drilling and acquisition well
activity for wells in which the Company owned a working interest, as of December
31 for each year presented:

<TABLE>
<CAPTION>
                                    GROSS WELLS                   NET WELLS
                            ---------------------------    -------------------------                                          
                            PRODUCTIVE    DRY     TOTAL    PRODUCTIVE   DRY    TOTAL
                            ----------    ---     -----    ----------   ---    -----
<S>                           <C>       <C>      <C>        <C>       <C>     <C>
Development wells:
  1998                           11        1       12         2.30      .86     3.16
  1997                            6        1        7          .99      .28     1.27
Exploration wells:
  1998                            5        3        8          .75     1.50     2.25
  1997                            8        3       11         2.07      .75     2.82
Acquisition wells:
  1998(1)                        44       --       44         8.27       --     8.27
  1997                          360       --      360       184.60       --   184.60
</TABLE>
-----------------
(1)  Had the Amerada Transaction been consummated as of December 31, 1998, gross
     and net productive acquisition wells would have been 93 and 49.39,
     respectively.

     Expenditures.  The following table sets forth total net expenditures by the
Company by category for the periods indicated.

                                            YEAR ENDED DECEMBER 31,
                                            -----------------------
                                              1998            1997
                                            -------         -------
                                                 (in thousands)
Unproved properties                         $ 2,623         $   229
Drilling and capital workovers (1)            8,041           2,371
Acquisitions (2) (3)                          6,156          52,293
Other property and equipment                    598             222
                                            -------         -------
Total                                       $17,418         $55,115
                                            =======         =======

---------------
(1)  Excludes $931 and $484 which were expensed as unsuccessful exploration
     costs for the years ended December 31, 1998 and 1997, respectively.

(2)  1997 includes Grand Gulf Acquisition purchased with Sheridan Common Stock
     and warrants to buy Sheridan Common Stock valued at approximately $4.1
     million.

(3)  Table does not include net expenditures of $55.1 million incurred in
     January 1999 by SCEI in connection with the Amerada Transaction.

     Leasehold Acreage and Productive Wells.  The following table sets forth the
Company's interest in undeveloped acreage, developed acreage and productive
wells in which it owns a working interest as of December 31, 1998.  Productive
wells are wells in which the Company has a working interest and are capable of
producing oil or natural gas.  Gross represents the total number of acres or
wells in which the Company owns a working interest.  Net represents the
Company's proportionate working interest resulting from its ownership in the
gross acres or wells.

                                       8
<PAGE>
 
                    UNDEVELOPED ACRES     DEVELOPED ACRES     PRODUCTIVE WELLS
                    -----------------     ---------------     ----------------
                     GROSS      NET       GROSS      NET       GROSS      NET
                    ------    -------     -----     -----     -------    -----
Alabama                  -        -       1,925       197        18       1.94
Arkansas             1,630      471       3,993     1,198        55      23.12
California             159      159       2,700       666        13       3.00
Colorado                 -        -       2,794       511         -          -
Louisiana           42,558   41,542       8,769     4,731        44      32.02
Mississippi            871      496       7,706     2,278        23       6.08
Montana                  -        -         640        18         -          -
North Dakota             -        -          80         1         1          -
Oklahoma             4,765      953      35,963    11,703       102      26.92
Texas                1,748       29      29,221    13,837       145      85.57
                    ------  -------     -------   -------    ------    -------
      Total         51,731   43,650      93,791    35,140       401     178.65
                    ======  =======     =======   =======    ======    =======
     The following shows the same information set forth above for California and
Total, except the effect of the Amerada Transaction is included as if such
transaction had been consummated as of December 31, 1998.

                   UNDEVELOPED ACRES    DEVELOPED ACRES    PRODUCTIVE WELLS
                   -----------------    ---------------    ----------------
                     GROSS     NET       GROSS     NET      GROSS     NET
                   --------- -------    -------  ------    -------   ------
California(1)       17,264   17,264     22,970   20,936        62    44.12
                    ======   ======     ======   ======    ======    ======
Total(1)            68,836   60,755    114,061   55,410       450   219.76
                    ======   ======     ======   ======    ======    ======
-------------
(1)  Includes 20% minority interest in the Amerada Transaction properties.

     The following table provides, as of December 31 for each year presented,
additional information pertaining to the productive wells in which the Company
owns a working interest.  Gross are the total number of wells in which the
Company owns a working interest.  Net represents the Company's proportionate
working interest resulting from its ownership in each gross well.  Of the total
number of 1998 gross wells in which the Company has an interest, 200 are
operated by the Company, and 201 are operated by others.

                       GROSS                       NET
               ----------------------     ----------------------
               OIL      GAS     TOTAL     OIL      GAS     TOTAL
               ---      ---     -----     ---      ---     -----
1998            95      306      401       42      137      179
1997            99      389      488       44      175      219


     The following shows the same information for 1998 as set forth above,
except that the effect of the Amerada Transaction is included as if such
transaction had been consummated as of December 31, 1998.  Of the total number
of 1998 gross wells in which the Company has an interest, 244 are operated by
the Company, and 206 are operated by others.


                       GROSS                       NET
               ----------------------     ----------------------
               OIL      GAS     TOTAL     OIL      GAS     TOTAL
               ---      ---     -----     ---      ---     -----
1998(2)         95      355      450       42      178      220

----------------                                        
(2)  Includes 20% minority interest in the Amerada Transaction properties.

     Natural Gas Treating Plant. Through a joint venture, the Company owns a 35%
interest in a natural gas treating plant located in the Comite Field, East Baton
Rouge Parish, Louisiana. Natural gas from one well operated by the Company and
two wells operated by third parties is transported to the plant where it is
treated to satisfy pipeline 

                                       9
<PAGE>
 
specifications. The plant also provides condensate handling and salt water
disposal facilities. The Company receives cash distributions from the joint
venture for its share of net cash flow. In addition, the joint venture charges
the Company for treating the natural gas produced from a Company-operated well
and such charges are included in treating and transportation operating expenses.
For information concerning this treating plant, see Note 6 of the Notes to
Consolidated Financial Statements.

Competition, Markets and Other External Factors

     Competition and Marketing--Oil and Natural Gas Industry.  The oil and
natural gas industry is highly competitive, both in the search for and
acquisition of oil and natural gas reserves and in the refining, processing and
marketing of petroleum products. Competitors include the major and independent
crude oil and natural gas companies, individual producers and operators, and
major pipeline companies. Other sources of energy, such as coal and nuclear
power, also provide competition, and crude oil and natural gas are subject to
substantial competition from foreign sources.

     The price the Company receives for its oil production depends on many
variables over which it has no control, such as the world supply of, and demand
for, oil, the level of imports, and the political stability of foreign
governments.  The influence exerted by these and other factors has caused
domestic oil prices to fluctuate dramatically.

     The availability of a ready market as well as the price received for
natural gas produced and sold by the Company also depends upon numerous factors
beyond its control, including the proximity of producing natural gas properties
to pipelines, the capacity of such pipelines, fluctuations in seasonal or
overall demand, domestic deliverability, government regulations, and competition
from alternative forms of energy. A trend has emerged recently among major
natural gas marketing companies toward consolidation mergers, both among
themselves as well as in the form of strategic alliances with large producers or
end-users.  These consolidations have the effect of putting control of the
majority of the supply and the market in hands of a few industry participants.
The longer-term ramifications of this trend are difficult to foresee but will
likely have an impact on the way natural gas is bought and sold in the future,
and this impact could be potentially more significant to the smaller independent
producers such as the Company.

     Major Customers. Information concerning sales to customers who accounted
for more than 10% of total revenues, the loss of any of which could have a
material adverse effect on the Company's operations if alternative customers
could not be found, is contained in Note 13 of the Notes to Consolidated
Financial Statements.

     Production and Development Hazards. Hazards such as unexpected formations,
blow-outs, cratering and fires are involved in crude oil and natural gas
drilling, production and development activities. Such hazards, as well as
adverse weather conditions, may hinder or delay drilling and development
operations. Sheridan attempts to obtain and maintain insurance coverage
customary in the crude oil and natural gas industry, but may be subject to
liability for pollution and other damages or may lose substantial portions of
its properties due to hazards against which it is impossible or impractical (due
to prohibitive premium requirements) to maintain insurance. Governmental
regulations relating to environmental matters could also increase Sheridan's
cost of production and development operations or require it to cease production
and development operations in certain areas.

Regulation

     General.  The Company's operations are affected by political developments
and federal and state laws and regulations.  Oil and gas industry legislation
and administrative regulations are periodically changed for a variety of
political, economic and other reasons.  Numerous departments and agencies,
federal, state, local and Indian, issue rules and regulations binding on the oil
and gas industry, some of which carry substantial penalties for failure to
comply.  The regulatory burden on the oil and gas industry increases the
Company's cost of doing business, decreases flexibility in the timing of
operations and may adversely affect the economics of capital projects.

                                       10
<PAGE>
 
     Environmental Regulation.  The Company's operations are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection.  These laws and regulations
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, and impose substantial liabilities for
pollution resulting from the Company's operations. Moreover, the recent trend
toward stricter standards in environmental legislation and regulation is likely
to continue. For instance, legislation has been proposed in Congress from time-
to-time that would reclassify certain crude oil and natural gas exploration and
production wastes as "hazardous wastes" which would make the reclassified wastes
subject to much more stringent handling, disposal and clean-up requirements. If
such legislation were to be enacted, it could have a significant impact on the
operating costs of the Company, and on the oil and gas industry in general.
Initiatives to further regulate the disposal of crude oil and natural gas wastes
are also pending in certain states, and these various initiatives could have a
similar impact on the Company. Management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations, but the Company's operations could nevertheless result in liability
for personal injuries, property damage, oil spills, discharge of hazardous
materials, remediation and clean-up costs and other environmental damages.  The
Company could also be liable for environmental damages caused by previous
property owners. As a result, substantial liabilities to third parties or
governmental entities may be incurred, the payment of which could have a
material adverse effect on the Company's financial condition and results of
operations.  The Company maintains insurance coverage for its operations,
including coverage for sudden environmental damages, but does not believe that
insurance coverage for environmental damages that occur over time is or will be
available at a reasonable cost. Moreover, the Company does not believe that
insurance coverage against the full potential liability that could be caused by
sudden environmental damages is available at a reasonable cost. Accordingly, the
Company may be subject to liability against which it cannot fully insure, but
which could have a material adverse effect on the Company. Oil and gas
operations are subject to extensive governmental regulation, which may be
changed from time-to-time in response to economic or political conditions.  The
Oil Pollution Act of 1990 imposes a variety of regulations on "responsible
parties" related to the prevention of oil spills.  The implementation of new or
the modification of existing environmental laws or regulations, including
regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a
material adverse impact on the Company.

     State Regulation. All states in which the Company conducts oil and natural
gas production operations have statutory provisions regulating the drilling for,
production, transportation, storage and sale of oil and natural gas. Such
statutes, and the regulations promulgated in connection therewith, generally are
intended to prevent the waste of oil and natural gas and to protect correlative
rights and opportunities to produce oil and natural gas as between owners of
interests in a common reservoir. Certain state regulatory authorities also
regulate the amount of oil and natural gas produced by assigning allowable rates
of production to each well or proration unit.

     Federal Regulation.  The Company may conduct operations on federal oil and
natural gas leases, and such operations must comply with numerous regulatory
restrictions and requirements issued by the Mineral Management Service,
including various nondiscrimination statutes, and certain of such operations
must be conducted pursuant to appropriate permits issued by the Bureau of Land
and Management.

     In the past, the federal government has regulated the prices at which oil
and gas could be sold.  Prices of oil and gas sold by the Company are not
currently regulated.  In recent years, the Federal Energy Regulatory Commission
("FERC") has taken significant steps to increase competition in the sale,
purchase, storage and transportation of natural gas.  Under these orders, FERC
has caused pipelines to open up access to transportation, essentially
eliminating pipelines from the role of natural gas merchant and "unbundled"
transportation services so that a buyer can purchase just those services it
needs.  FERC's regulatory programs generally allow more accurate and timely
price signals from the consumer to the producer and, on the whole, have helped
gas become more responsive to changing market conditions, To date, the Company
believes it has not experienced any material adverse effect as the result of
these programs.  Nonetheless, increased competition in gas markets can and does
add to price volatility and inter-fuel competition, which increases the pressure
on the Company to manage its exposure to changing conditions and position itself
to take advantage of changing market forces.

                                       11
<PAGE>
 
Employees

     The Company maintains a staff of professional and support personnel
required to manage its properties. As of December 31, 1998, the Company had 27
employees, including three engineers, one geophysicist, one geologist and five
marketing and land personnel.  None of the Company's employees are represented
by a labor union or collective bargaining agent.  The Company considers its
relations with its employees to be good and has experienced no work stoppages
associated with labor disputes or grievances.

Year 2000

     Historically, certain computer systems, as well as certain hardware
containing embedded chip technology, such as micro controllers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the Year 2000.
This could result in significant system failures.  The Company relies on its
computer-based management information systems, as well as embedded technology,
to operate instruments and equipment in conducting its normal business
activities.  Certain of these computer-based programs and embedded technology
may not have been designed to function properly with respect to the application
of dating systems relating to the Year 2000.

     In response, the Company has developed a "Year 2000 Plan" and has
established an internal group to identify and assess potential areas of risk and
to make any required modifications to its computer systems and equipment used in
oil and gas exploration, production, gathering and gas processing activities.
The Year 2000 Plan is comprised of various phases, including assessment,
remediation, testing and contingency plan development.  After the assessment
phase has been completed and evaluated, the remediation, testing and
certification phases will be implemented to ensure that the material facilities
and business activities will continue to operate safely and reliably, and
without interruption after 1999.  Based upon the results of these activities
contingency plans will be developed to the extent deemed necessary.

     The Company's inventory of computer hardware and primary business software
is substantially Year 2000 compliant.  The Company is currently assessing its
engineering software systems for compliance.  It is anticipated that these
software systems will be Year 2000 compliant.  If any programming modifications
are required, such should be  completed and tested by the second quarter of 1999
with implementation and conversion scheduled for the third quarter of 1999.

     The Company has monitor and control equipment with embedded chip technology
which are utilized in production and gas processing operations.  These various
systems are currently being reviewed in conjunction with the overall Year 2000
Plan and to date no major compliance issues have been discovered.  Other systems
with embedded chip technology are relatively new and should be Year 2000
compliant according to the manufacturers.

     The Company has also undertaken to monitor the compliance efforts of
suppliers, contractors and other third parties with whom it does business and
whose computer-based systems and/or embedded technology equipment interface with
those of the Company to ensure that operations will not be adversely affected by
the Year 2000 compliance problems of others.  There can be no assurance that
there will not be an adverse effect on the Company if vendors, suppliers,
customers, state and federal governmental authorities and other third parties do
not convert their respective systems in a timely manner and in a way that is
compatible with the Company's information systems and embedded technology
equipment.  However, management believes that ongoing communication with and
assessment of the compliance efforts and status of these third parties will
minimize these risks.

     The Company believes that it can provide the resources necessary to ensure
Year 2000 compliance and expects to complete its Year 2000 Plan within a time
frame that will enable its computer-based programs and embedded technology
equipment to function without significant disruption in the Year 2000.  Through
1998, the Company has incurred less than $10,000 in third party costs for
software and equipment costs related to Year 2000 compliance matters and
estimates that the total future third party, software and equipment costs
related to Year 2000 compliance activities, based upon information developed to
date, will be less than $50,000 and will be expensed as incurred.  These costs
have 

                                       12
<PAGE>
 
been and will continue to be funded through operating cash flows and are not
deemed to be material to the operations of the Company. The cost of the
remediation activities and the completion dates are based on management's best
estimates and may be updated as additional information becomes available. The
costs incurred to date and those estimated to be incurred in the future with
respect to Year 2000 issues do not include internal costs. The Company does not
separately track the internal costs incurred with respect to implementation of
the Year 2000 Plan. Such costs are principally internal payroll costs, including
senior management, and field operations personnel involved in the compliance
program and related travel and other out-of-pocket expenses.

     Although the Company anticipates minimal business disruption will occur as
a result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
third parties, should fail to function properly, possible consequences include
but are not limited to, loss of communications links, inability to produce and
process natural gas, loss of electric power, and inability to automatically
process commercial transactions, or engage in similar normal automated or
computerized business activities.

     To date, the Company has not finalized its contingency plans for possible
Year 2000 issues.  As noted above, in the event the Company, after completion of
the assessment, remediation and testing phases of the Year 2000 Plan and review
of the results of monitoring the compliance efforts and status of third parties,
determines that contingency plans are necessary, the Company will finalize such
contingency plans based on its assessment of outside risks.  The Company
anticipates that final contingency plans, as necessary, will be in place by the
fourth quarter of 1999.

     The discussion of the Company's efforts, and management's expectations,
relating to Year 2000 compliance contains forward-looking statements.
Presently, the Company does not anticipate that the Year 2000 issues will have a
material adverse effect on the operations or financial performance of the
Company.  However, there can be no assurance that the Year 2000 will not
adversely affect the Company and its business.

Other Risk Factors

     Stockholders should carefully examine this entire report but should give
particular attention to the following risk factors.

     Volatility of Oil, Gas and Natural Gas Liquid Prices.  The Company's
revenues, profitability, cash flow, future growth and the carrying value of its
oil and gas properties are affected by changes in oil, gas and NGL prices.  The
Company's ability to maintain or increase its borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent upon such
prices.  Prices for oil, gas and NGLs are subject to significant fluctuations in
response to market changes beyond the control of the Company including, but not
limited to, weather conditions, the condition of the United States economy, the
actions of the Organization of Petroleum Exporting Countries, governmental
regulation, political stability in the Middle East and elsewhere, foreign supply
of oil and gas, the price of foreign imports and the availability of alternate
fuel sources.  These influences have resulted in significant fluctuations in
prices in recent years.

     At December 31, 1998, the NYMEX price for natural gas, based on an Mcf
basis, was $2.32, as compared to $2.58 for December 31, 1997.  As of March 22,
1999, the natural gas NYMEX price, based on an Mcf basis, was $1.91.  As of
December 31, 1998, the per barrel posted price for West Texas Intermediate
("WTI") oil production, the benchmark for domestic oil prices, was $9.25, as
compared to $15.50 for the same date in 1997.  As of March 22, 1999, the WTI
price for oil was $13.00 per barrel.  The NYMEX natural gas future prices are
only an indicator of price trends and may not be indicative of prices ultimately
realized at the wellhead.  Volatile oil and gas prices make it difficult to
estimate the value of producing properties for acquisition and to budget for and
project the return on development and exploitation projects.

                                       13
<PAGE>
 
     Estimates of Oil and Gas Reserves.  This report contains estimates of
proved oil and gas reserves and the future net cash flows attributable to those
reserves prepared by independent petroleum and geological engineers.  There are
numerous uncertainties inherent in estimating quantities of proved oil and gas
reserves and cash flows attributable to such reserves, including factors beyond
the control of the Company and their engineers.  Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner.  The accuracy of an estimate of
quantities of reserves, or of cash flows attributable to such reserves, is a
function of the available data, assumptions regarding future oil and gas prices
and expenditures for future development and exploitation activities, and of
engineering and geological interpretation and judgment.  Additionally, reserves
and future cash flows may be subject to material downward or upward revisions,
based upon production history, development and exploration activities and prices
of oil and gas.  Actual future production, revenue, taxes, development
expenditures, operating expenses, quantities of recoverable reserves and the
value of cash flows from such reserves may vary significantly from the
assumptions set forth herein.  In addition, different reserve engineers may make
different estimates of reserves and cash flows based on the same available data.

     Acquisition and Development of Reserves.  The Company's future success
depends upon its ability to find, develop and acquire additional crude oil and
natural gas reserves that are economically recoverable.  Many of the Company's
properties are characterized by a high initial production rate, followed by a
steep decline in production.  As a result, the Company must locate and develop
or acquire new oil and gas reserves to replace those being depleted by
production.  This process is capital-intensive and, for the Company to maintain
its asset base of oil and gas reserves, the Company must reinvest a significant
amount of cash flow from operations in property acquisitions and development and
exploration activities.  To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investments to maintain or expand its asset base
would be impaired.  Without such investment, the Company's oil and gas reserves
could decline.  The Company is also subject to the risks inherent in acquiring
or developing economically recoverable oil and gas reserves, including the need
to invest a significant amount of cash flow in the identification and
acquisition of properties, the drilling and completing of wells and the conduct
of development operations.  Except to the extent that the Company acquires
additional recoverable reserves or conducts successful exploration and
development programs, the proved reserves of the Company will decline over time
as they are produced.  There can be no assurance that the Company will be able
to increase or replace reserves through acquisitions, exploration and
development at an acceptable cost.  The successful acquisition of producing
properties requires an assessment of recoverable reserves, future oil and gas
prices and operating costs, potential environmental and other liabilities and
other factors.  The Company's operations may be curtailed, delayed or canceled
as a result of lack of adequate capital and other factors, such as title
problems, weather, compliance with governmental regulations or price controls,
mechanical difficulties or shortages or delays in the delivery of equipment.
Moreover, the costs of exploration and development may materially exceed initial
estimates.

     Future Capital Needs.  The Company makes, and will continue to make,
substantial capital expenditures for the acquisition, exploration, development
and production of oil and natural gas reserves and the acquisition and
development of gas processing and gas gathering facilities.  The Company may
seek out joint venture partners to spread the risks and costs of such
acquisitions and development, use bank and institutional debt financing to fund
a portion of the costs of the facilities or properties or raise additional
capital through the sale of debt or equity securities.  No assurance can be made
that joint venture partners or debt financing will be available to fund the
Company's acquisition or development of additional facilities or properties or
that the Company could obtain debt financing or equity capital on terms that the
Company would consider reasonable or, in the case of a sale of equity
securities, on terms that would not be dilutive to existing stockholders.  See
"Management's Discussion and Analysis or Plan of Operation."

     Operating Hazards and Uninsured Risks.  The Company's operations are
subject to the risks inherent in the oil and gas industry, such as blowouts,
cratering, explosions, uncontrollable flows of crude oil, natural gas or well
fluids, product spills, leaks, fires, pollution and other environmental risks.
These risks could result in substantial losses to the Company due to injury and
loss of life, severe damage to and destruction of property and equipment,
pollution and other environmental damage and suspension of operations.  The
Company is not fully insured against all risks incident to its business, and the
occurrence of a significant event not fully insured or indemnified against could
materially and adversely affect the Company's financial condition and results of
operations.

                                       14
<PAGE>
 
     Principal Stockholders.  The Susskind Family Trust, The AIF-Lion Group and
ECT and affiliates currently own directly and indirectly in the aggregate 65% of
the Sheridan Common Stock, and ECT owns 100% of the Sheridan Preferred Stock.
Accordingly, these principal stockholders will be able to exercise substantial
influence over the election of the directors and management of Sheridan and over
the operations and affairs of Sheridan, including the ability to exercise
substantial influence to prevent or cause a change in control of Sheridan.
These principal stockholders do not, however, constitute a "group" under Rule
13d of the Exchange Act.  ECT and Susskind, however, have agreed to vote their
shares for the nominees for the Board designated by the other.

     Absence of Active Trading Market.  Sheridan's stock is listed on the Nasdaq
SmallCap System.  Since the Merger, the trading activity in its stock has been
sporadic.  Sheridan can make no assurance that an active trading market for
Sheridan Common Stock will develop or be sustained.  To the extent an active
trading market develops, the market price of Sheridan Common Stock could be
subject to significant fluctuations in response to variations in quarterly and
yearly operating results, the success of Sheridan's business strategy, general
trends in the oil and gas industry, competition, changes in federal regulations
affecting Sheridan or the oil and gas industry and other factors.  In addition,
the stock market in recent years has experienced extreme price and volume
fluctuations that have often been unrelated or disproportionate to the operating
performance of affected companies.  These broad fluctuations may adversely
affect the market price, if any, of Sheridan Common Stock.

     No Anticipated Dividends.  The Company expects to retain cash generated
from future operations to support its cash needs and does not anticipate the
payment of any dividends on Sheridan Common Stock for the foreseeable future.
In addition, dividends or distributions by Sheridan are restricted by the Bank
One Facility and Company redeemable Preferred Stock or may be restricted by
future bank and institutional debt financing.  See "Management's Discussion and
Analysis or Plan of Operation."

     Preferred Stock.  In addition to the Sheridan Preferred Stock, the board of
directors of Sheridan has the authority to issue additional series of preferred
stock and to fix the rights and preferences of the shares of any such series
without stockholder approval.  Any series of preferred stock is likely to be
senior to Sheridan Common Stock with respect to dividends, liquidation rights
and possibly voting rights.  The Company has no present plans to issue any
additional series of preferred stock.

ITEM 2.   DESCRIPTION OF PROPERTY

     For information concerning the Company's properties, see Item 1.
"Description of Business-Properties".

ITEM 3.   LEGAL PROCEEDINGS

     In July 1992, certain unleased mineral interest owners commenced a legal
action in the 19th Judicial District for East Baton Rouge, Parish, Louisiana
Case No. 383844, Division "A," against TGX, as operator of three wells.  The
petition alleged that the unleased owners were entitled to a refund of revenues
paid to TGX and other working interest owners, since first production, which
were attributable to the unleased owners' proportionate unit interest and which
were utilized to offset the plaintiffs' proportionate share of costs associated
with drilling the wells.  The Company argued that any claim which arose prior to
the date of the entry of the order confirming the Reorganization Plan had been
discharged through bankruptcy.  The Company filed a lawsuit in the U.S.
Bankruptcy Court for the Western District of Louisiana (Case No. 96AP-1047)
claiming such a defense.  However, the Bankruptcy Court rejected that defense.
Further, the Company argued that its payout notice to the unleased owners
complied with statutes requirements.  The Louisiana District Court, in August
1998, entered a judgment against the Company for $2.4 million, plus interest and
plaintiff's court cost.  In December 1998, the Company settled with
approximately 85% of the plaintiffs for a cash payment of $1.3 million.  The
Company was required by statute to issue a letter of credit in the amount of
$476,000 to pursue its appeal for the remaining unsettled judgment.  In March
1999 the remaining claimants agreed to settle this matter for $230,000.  Upon
settlement completion, which is anticipated in April 1999, the letter of credit
will be canceled.

                                       15
<PAGE>
 
     In July 1995, certain royalty owners in the same wells commenced a separate
legal action alleging that Sheridan's predecessor, TGX, and other working
interest owners improperly profited under the terms of a Gas Gathering and
Transportation Agreement.  In 1996, the court entered an order granting a motion
on behalf of TGX for a partial summary judgment, holding that all of the royalty
owners' claims preceding the filing of the suit by more than three years were
time-barred.  The Company has asked the court to dismiss the remaining claims
asserted by the royalty owners.  If not dismissed, the Company will vigorously
defend against this lawsuit.

     In May 1982, Samson Resources Company ("Samson") brought suit against
Sheridan's predecessor, TGX, in the United States District Court for the Western
District of Oklahoma alleging that the Company owed Samson for its under
production on a well in Oklahoma.  Sheridan argued that the claim which arose
prior to the date of the entry of the order confirming the Reorganization Plan
had been discharged through bankruptcy.  The Oklahoma District Court in August
1998 entered a judgment against the Company for $205,000, plus interest and
plaintiff court costs.  In February 1999, the Company agreed to settle this
lawsuit by paying $258,000 and receiving a full release regarding this matter.

     In December 1996, Tomcat Exploration, Inc. and others brought suit ("Tomcat
Litigation") against Sheridan's predecessor, TGX, in the 215th District Court of
Harris County, Texas alleging that TGX's operation of the Sinclair No. 1 Well in
Louisiana was negligent and, as a result, caused damage and loss to the
plaintiffs in excess of $10.0 million.  In October 1998, the Company agreed to
settle this lawsuit by paying the plaintiff group $1.5 million and receiving a
full release regarding this matter.

     As a result of management's assessment of the likelihood of losses from the
various litigation matters against the Company, based on advice of legal counsel
and review of the facts, circumstances, and developments surrounding the various
litigation matters, the Company recorded provisions in 1998 and 1997 of $2.4
million and $1.0 million, respectively, representing its estimate of losses
and/or related costs and expenses associated with such litigation matters,
including actual litigation settlements completed through March 26, 1999.

     From time to time, in the normal course of business, the Company is a party
to various other litigation matters the outcome of which, to the extent not
otherwise provided for, should not, in the opinion of management, have a
material adverse effect on the Company's financial position, cash flows or
results of operations.

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     During the fourth quarter of 1998, no matters were submitted to a vote of
the security holders.

                                       16
<PAGE>
 
                                    PART II

ITEM 5.   MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Price Information

     Prior to July 2, 1997, Sheridan Common Stock was listed on the NASD's
"bulletin board".  The shares were sporadically traded.  After the Merger and
commencing July 2, 1997, Sheridan Common Stock was listed on the Nasdaq SmallCap
Market with the trading symbol SHDN.

     As of December 31, 1998, there were approximately 2,300 holders of record
of Sheridan Common Stock.  The following table sets forth bid quotations for TGX
Common Stock prior to the Merger, as reported by the National Quotations Bureau,
Inc. Bid quotations represent bid prices between dealers without retail markup
or markdown or commission and do not reflect actual transactions.  Prices shown
subsequent to July 2, 1997 are high and low closing sales prices of Sheridan
Common Stock, as reported on the Nasdaq SmallCap Market.

QUARTER ENDED                                        HIGH         LOW
1998:
     March 31                                        $6.25       $3.50
     June 30                                          5.62        3.00
     September 30                                     4.00        2.37
     December 31                                      5.12        2.50
 
1997:
     March 31                                        $   *       $   *
     June 30                                             *           *
     September 30                                     3.62        2.25
     December 31                                      8.31        3.50

---------------
     * No reported trading activity for the period noted.

     The Company has not paid, and does not anticipate paying, any cash
dividends with respect to Sheridan Common Stock.  Pursuant to its bank
indebtedness, the Company has certain restrictions on making cash payments on
Sheridan Common Stock or Sheridan Preferred Stock.

     On March 25, 1999, the closing sales price per share of Sheridan Common
Stock, as reported by the Nasdaq SmallCap, was $3.13.

Sheridan Preferred Stock

     In December 1997, Sheridan sold 1.0 million shares of the Sheridan
Preferred Stock to ECT in connection with the Pioneer Acquisition.  The Sheridan
Preferred Stock provides for cash dividends in an amount equal to $0.60 per
share payable semi-annually (a 12% annual rate) or, at the discretion of the
Company, dividends may be paid by issuing additional fully paid shares of
Sheridan Preferred Stock in an amount equal to .0675 additional shares (a 13.5%
annual rate) for each share of Sheridan Preferred Stock then issued and
outstanding.  The Sheridan Preferred Stock also provides for a liquidation
preference of $10 per share.  The Sheridan Preferred Stock is redeemable from
time to time at the discretion of the Company at certain established redemption
prices, and must be redeemed on December 15, 2002, or upon the occurrence of
certain defined situations, including a change of control or a default as
defined in the Sheridan Preferred Stock designation.

                                       17
<PAGE>
 
SCEI Preferred Stock

     On January 25, 1999, SCEI sold 1.3 million shares of SCEI Preferred Stock
to CPN in connection with the Amerada Transaction.  The SCEI Preferred Stock
provides for cash dividends in an amount equal to $0.625 per share payable semi-
annually (a 12.5% annual rate) or, at the discretion of SCEI, dividends may be
paid by issuing additional fully paid and non-assessable shares of SCEI
Preferred Stock (having a capital determined by the Board of Directors of $10
per share) in an amount equal to .07 additional shares (a 14% annual rate) for
each share of SCEI Preferred Stock then issued and outstanding.  The SCEI
Preferred Stock also provides for a liquidation preference of $10 per share.
The SCEI Preferred Stock is redeemable from time to time at the discretion of
SCEI at certain established redemption prices, and must be redeemed on January
15, 2006, or upon the occurrence of certain defined situations, including a
change of control or a default as defined in the SCEI Preferred Stock
designation.

ITEM 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

     The following discussion is intended to assist in an understanding of the
Company's financial position and results of operations for each of the two years
in the period ended December 31, 1998. The Company's consolidated financial
statements and the notes thereto which follow contain detailed information that
should be referred to in conjunction with the following discussion.

     This discussion contains certain forward-looking statements.  Stockholders
are cautioned that all forward-looking statements involve risks and uncertainty,
including without limitation, statements about the cost of exploring and
developing new oil and natural gas reserves, the price for which such reserves
can be sold, the Company's attempts to reduce overhead and eliminate non-core
assets, environmental concerns affecting the drilling of oil and natural gas
wells, the effect of the Merger, the attempts to acquire producing and non-
producing oil and gas properties, the ability of the Company to make projected
capital expenditures and secure required capital and to achieve projected
quarterly results, achieve compliance with Year 2000 issues, and general market
conditions, competition and pricing.

     All statements, other than statements of historical facts, included or
incorporated by reference in this document that address activities, events or
developments that the Company expects or anticipates will or may incur in the
future, including such things as future capital expenditures and acquisitions,
business strategy and measures to implement such strategy, competitive
strengths, goals, expansion and growth of the Company's business and operations,
plans, references to future success as well as other statements which include
words such as "anticipate," "believe," "plan," "estimate," "expect," and
"intend," and other similar expressions constitute forward-looking statements.
Although the Company believes that the assumptions underlying the forward-
looking statements contained herein are reasonable, any of the assumptions could
be inaccurate, and therefore, there can be no assurance that the forward-looking
statements included in this document will prove to be accurate.  In light of the
significant uncertainties inherent in the forward-looking statements included
herein, the inclusion of such information should not be regarded as a
representation by the Company or any other person that the objectives and plans
of the Company will be achieved.

RESULTS OF OPERATIONS

General

     Sheridan Energy, Inc. is the surviving entity resulting from the Merger
with its former parent company, TGX Corporation, effective June 12, 1997 (the
"Merger Effective Date"). Pursuant to the Merger, all persons owning TGX Senior
Preferred Stock had their preferred shares exchanged for Sheridan Common Stock
on the basis of 0.5 shares of Sheridan Common Stock for each share of TGX
Preferred Stock owned. At the same time, holders of all other classes of equity
securities of TGX had their securities eliminated.

     The Company follows the successful efforts method of accounting for its oil
and gas operations. Under the successful efforts method, costs of productive
wells, development dry holes and productive leases are capitalized and 

                                       18
<PAGE>
 
amortized on a unit-of-production basis over the life of remaining proved
reserves. Cost centers for amortization purposes are determined on a field-by-
field basis. See Note 2 of the Notes to Consolidated Financial Statements.

     In addition to the accounting principle described above, the following
events affect the comparative results of operations and financial condition for
the years ended December 31, 1998 and 1997 and may impact future operations and
financial conditions.

     1998 and 1999 Acquisitions.  During 1998, the Company purchased, for cash
and notes payable, $5.9 million of oil and gas properties through numerous
transactions with various effective dates of purchase and closing dates.  On
January 25, 1999, but effective as of November 1, 1998, pursuant to the Amerada
Transaction, the Company through a newly formed subsidiary, SCEI, acquired
approximately $58.0 million of oil and gas producing and non-producing
properties (the "California Properties") from Amerada Hess Corporation.  As a
result of the Amerada Transaction, SCEI obtained an interest in approximately 82
billion cubic feet of proven natural gas reserves in the Sacramento Basin,
California.  In order to finance a portion of the Amerada Transaction, SCEI
received a borrowing base facility (the "SCEI Facility") from Bank One, Texas,
N.A. ("Bank One") in the amount of approximately $43.0 million, of which
approximately $30.6 million was borrowed in January 1999 and an additional $7.1
million is anticipated to be borrowed upon final closing in April 1999.  See
"Bank Indebtedness."  In addition, the Company entered into an agreement (the
"Formation Agreement") with Calpine Corporation ("Calpine") and CPN Production
Company ("CPN"), each unaffiliated parties, pursuant to which SCEI was created
to acquire and own the California Properties.  CPN contributed $14.9 million in
cash and received $13.0 million in seven-year redeemable non-voting preferred
stock of SCEI (the "SCEI Preferred Stock") and 20% of the outstanding common
stock of SCEI.  In certain circumstances, the Company may be entitled to acquire
the common stock held by CPN.  The Company contributed $3.0 million in cash and
$4.6 million of seismic data and oil and gas producing assets in California and
received 80% of the outstanding common stock of SCEI.  This transaction resulted
in no impact on 1998 results of operations.  For further information about the
SCEI Preferred Stock, see "Item 5. Market for Common Equity and Related
Stockholder Matters."

     1998 Property Sales.  In 1998 the Company completed the sales of certain
non-strategic oil and gas producing properties for net sales proceeds of $12.7
million, resulting in net gains on property sales of $1.7 million.

     1997 Acquisitions.  In 1997, the Company purchased $52.5 million of
producing and non-producing properties with effective dates at various times
during the year, including two significant transactions which closed in December
1997.  In one transaction, effective November 1, 1997 but closed December 15,
1997, the Company purchased, for cash, $46.7 million of oil and gas producing
and non-producing properties from Pioneer Natural Resources USA, Inc. (the
"Pioneer Acquisition").  Operations attributable to the last two weeks of
December 1997 are included in the Company's 1997 revenues and expenses.  In a
second transaction, effective September 1, 1997 but closed December 31, 1997,
the Company acquired $4.1 million of oil and gas producing and non-producing
properties from Grand Gulf Production, LLC and JEDI I through the issuance of
850,000 shares of Sheridan Common Stock and warrants to purchase an additional
150,000 shares of Sheridan Common Stock (the "Grand Gulf Acquisition").  This
transaction had no impact on 1997 results of operations.  See Note 3 of the
Notes to Consolidated Financial Statements.

     1997 Sales of Sheridan Common Stock and Sheridan Preferred Stock.  In
connection with the Pioneer Acquisition, the Company issued to ECT 1.6 million
shares of Sheridan Common Stock for $10.0 million ($9.2 million net of expenses)
and 1.0 million shares of Sheridan Preferred Stock for $10.0 million ($9.6
million net of expenses).  The Company also issued 850,000 shares of Sheridan
Common Stock and warrants to purchase an additional 150,000 shares of Sheridan
Common Stock at $5.50 per share as part of the Grand Gulf Acquisition.

Year Ended December 31, 1998, Compared to Year Ended December 31, 1997

     Oil and Gas Operations.  The following table sets forth certain information
with respect to the oil and gas operations of the Company.  Oil and condensate
and natural gas prices are shown on a per barrel and per Mcf basis,
respectively.  Oil and condensate and natural gas volumes are shown in barrels
and million of cubic feet (MMcf), respectively.  Total production is shown on an
equivalent Mcf basis ("Mcfe"), where one barrel of oil or condensate is equal to
six Mcf of natural gas, on a heating value basis.

                                       19
<PAGE>
 
<TABLE> 
<CAPTION> 
                                                                      Year Ended December 31,
                                                               --------------------------------------
                                                                 1998            1997         Change
                                                               -------          ------        -------
<S>                                                           <C>              <C>            <C> 
Production:
  Oil and condensate (MBbls)                                       202              93          117%
  Natural gas (MMcf) (includes liquids)                          7,165           2,163          231%
  Total production (MMcfe)                                       8,376           2,722          208%
  Average daily production (MMcfe/day)                            23.0             7.5          208%
  Natural gas production as a percentage of total production        86%             79%           9%
  
Oil, condensate and natural gas sales (in thousands, 
 except percentages):
  Oil and condensate sales                                     $ 2,914          $1,805           61%
  Natural gas sales                                            $14,987          $5,269          184%
  Total oil, condensate and natural gas sales                  $17,901          $7,074          153%
  Natural gas revenues as a percentage of oil and gas revenues      84%             74%          14%
 
Average realized price (includes 1998 price hedges):
  Oil and condensate (per Bbl)                                 $ 14.43          $19.38          (26%)
  Natural gas (per Mcf)                                        $  2.09          $ 2.44          (14%)
 
Average cost (per Mcfe):
  Operating expenses (excludes production taxes)               $  0.61          $ 0.63           (3%)
  Depreciation, depletion and amortization
   (excludes impairment provision)                             $  1.20          $ 0.95           26%
  General and administrative expense                           $  0.56          $ 1.02          (45%)
</TABLE>

Production

     The natural gas and oil and condensate sales volume increases for 1998
reflect the full period impact of the December 1997 Pioneer and Grand Gulf
Acquisitions and the results of the Company's 1998 drilling, workover and
acquisition activity.  In December 1998, daily average net production was
approximately 20,686 Mcfe as compared to the December 1997 rate of 14,843 Mcfe.

Revenues

     Revenues from the sale of oil, condensate and natural gas for 1998 were
approximately $17.9 million, an increase of $10.8 million, or 153%, over 1997
comparable revenues of approximately $7.1 million.  Of this increase, higher oil
and gas sales volume, primarily the result of 1997 acquisitions, contributed
$14.0 million of additional revenues which was partially offset by significant
price declines.  The average oil price per barrel for 1998, including price
hedging benefits, was $14.43, a decrease of $4.95 per barrel, or 26%, as
compared to the 1997 price of $19.38.  Oil price hedging for 1998 increased oil
revenues by $500,000, or $2.48 per barrel.  The average realized price per Mcf
of natural gas for 1998, including price hedging benefits, was $2.09, a decrease
of $0.35 per Mcf, or 14%, from the 1997 price per Mcf of $2.44.  Natural gas
price hedging during 1998 increased the average realized price per Mcf by $0.05,
or natural gas revenues by $371,000.  The Company as of March 15, 1999, had
hedged 1999 and 2000 gas net volumes of approximately 4,750 MMcf and 2,222 MMcf,
respectively, at weighted average prices per Mcf of $2.44 and $2.36,
respectively, excluding the California Properties hedge.  In addition, SCEI has
a hedge of 5,179 MMcf at a weighted average price per Mcf of $2.43 regarding the
California Properties resulting in 77% of consolidated 1999 proved developed
producing natural gas production being hedged at $2.43 per Mcf.

     In 1998 the Company completed the sale of certain non-strategic oil and gas
producing properties for net sales proceeds of $12.7 million, resulting in net
gains on property sales of $1.7 million.  These property sales were primarily
effective June 1, 1998.

                                       20
<PAGE>
 
Cost and Expenses

     Operating expenses.  For 1998, total operating expenses, which include
through the wellhead production costs (lifting costs), severance taxes and
workover costs, increased approximately $4.1 million, or 204%, to approximately
$6.1 million, as compared to approximately $2.0 million for the comparable 1997
period.  This increase was primarily due to higher production volumes as a
result of 1997 acquisitions and 1998 capital expenditure activity.  Production
taxes for 1998 and 1997 totaled $1.1 million and $324,000, respectively.  On a
per Mcfe basis, production taxes were $0.13 and $0.12, respectively, or 6% and
5%, respectively, of oil and natural gas sales.  Operating expenses, excluding
production taxes, for 1998 and 1997 totaled approximately $5.1 and $1.7 million,
respectively.  Operating expenses per Mcfe decreased 3%, from $0.63 in 1997 to
$0.61 in 1998 due to lower per unit operating costs related to the 1997
acquisition properties.  Workover costs, which are included as part of operating
expenses, for 1998 and 1997 totaled $685,000 and $179,000, respectively, and
primarily represent discretionary remedial well activities that were implemented
to enhance or increase production from existing producing zones.

     Treating and transportation expenses.  Treating and transportation expenses
for 1998 totaled $795,000, as compared to $611,000 for the comparable 1997
period and represent post-wellhead expenses incurred primarily to treat gas to
comply with pipeline specifications or to transport the gas to market.  For 1998
and 1997, approximately 92% and 94%, respectively, of this expense is associated
with the Company's Comite Field.

     Depletion, depreciation and amortization ("DD&A").  DD&A expense for 1998
was $10.1 million, as compared to $2.6 million for 1997, an increase of $7.5
million or 288%.  Approximately $5.4 million of this increase is attributable to
an increase in equivalent volumes produced, and the remaining $2.1 million
relates to an increase in the DD&A rate per Mcfe.  The DD&A rate per Mcfe for
1998 was $1.20 as compared to $0.95 for 1997.  The increase in the per Mcfe rate
reflects the production and cost characteristics of the 1997 acquisitions and
lower year-end reserves resulting from a decline in year-end prices from 1997.

     Impairment provision for oil and gas properties.  The 1998 impairment
provision of $3.2 million represents a non-cash charge related to write-down of
oil and gas properties pursuant to Statement of Financial Accounting Standards
No. 121 ("SFAS 121").  As a result of low year-end 1998 oil and gas prices,
certain of the Company's oil and gas properties' recorded values were reduced to
current fair value as determined from estimated discounted future net cash flows
based on current prices, as adjusted.  As a result of this impairment provision,
future DD&A per unit costs will be reduced.

     General and administrative expenses.  General and administrative expenses
for 1998 were approximately $4.7 million, an increase of $1.9 million from $2.8
million for the comparable 1997 period.  This increase was primarily
attributable to 1998 staff additions as a result of the 1997 Pioneer and Grand
Gulf Acquisitions and increases in legal and other professional fees.  Legal
expenses for 1998 increased $132,000 to a total of $630,000 due primarily to the
activity related to the Tomcat Litigation and other legal matters resolved in
1998.  See Note 5 of the Notes to Consolidated Financial Statements.  Legal
costs are expected to decline in 1999 due to the various settlements completed
in 1998 and early 1999.  General and administrative expenses for 1997 also
included one-time net termination expenses of $186,000 related to the former
president and another officer's resignation and $181,000 of one-time costs and
fees related to the Merger.  These 1997 one-time expenses were partially offset
by the recovery of $75,000 of previously allowed for doubtful accounts
receivable.

     Exploration Costs.  Pursuant to successful efforts accounting, unsuccessful
exploration well costs are expensed.  For 1998, exploration costs totaled
$931,000, representing unsuccessful activities on 3 gross (1.5 net) wells.  For
1997, exploration costs totaled $484,000, representing unsuccessful activities
on 3 gross (.75 net) wells.  Though total exploration costs increased, such
expenses declined in proportion to total drilling expenditures.  Exploration
costs were 10.4% of 1998 total exploration and development costs as compared to
17.0% for 1997.

                                       21
<PAGE>
 
Other Income (Expense)

     Provision for litigation expense.  In 1998 the Company increased its
provision for litigation expense by $2.4 million based on its assessment of the
likelihood of losses, settlements and/or related costs and expenses associated
with various litigation matters against the Company.  In 1998 the Company agreed
to settle the Tomcat Litigation and a majority of the Edwards Litigation through
the payment of $2.8 million.  In early 1999, the Company agreed to settle the
Samson Litigation and remaining Edwards Litigation claims for $498,000, the
amount of which is included in the 1998 provision for litigation expense.  See
Note 5 of Notes to Consolidated Financial Statements.

     Equity earnings in natural gas treating plant.  Equity earnings in the
Comite Field Plant Venture increased by 19% to a combined total of $601,000 for
1998, compared to $507,000 for the comparable 1997 period.  This increase was
primarily attributable to lower plant operating expenses and the full period
impact of wells added to the Comite Plant in 1997 as the result of adjacent
field development.

     Interest and other income.  Interest and other income for 1997 is comprised
primarily of the sale of an option to purchase a pipeline for $50,000, interest
income of $24,000 and other miscellaneous revenues.

     Interest expense.  Interest expense for 1998 increased to approximately
$2.8 million from $344,000 in 1997, primarily due to an increase in long term
debt resulting from the 1997 acquisitions.  Included in 1998 and 1997 interest
expense is approximately $157,000 and $46,000, respectively, of amortization of
credit facility establishment costs which are being amortized over the remaining
term of the facility.

Preferred Dividends and Accretion of Preferred Stock

     Pursuant to the terms of the Reorganization Plan, dividends accrued on the
TGX Senior Preferred Stock at 10%, compounded annually, and on the TGX Old
Preferred at 9% payable through the issuance of additional TGX Old Preferred
shares.  The accretion of the TGX Senior Preferred Stock redemption value, also
a non-cash item, was calculated based on the interest method.  Effective with
the Merger, all dividends and accretion obligations were eliminated; however,
all pre-Merger Effective Date dividend and accretion charges continue to be
reflected in the historical results of 1997.  Pursuant to the Merger each share
of TGX Senior Preferred Stock was exchanged for 0.5 shares of Sheridan Common
Stock, and the TGX Old Preferred was canceled.

     The 1998 preferred stock dividend expense is the result of the $10.0
million of Sheridan Preferred Stock issued in conjunction with the Pioneer
Acquisition.  The 1998 preferred stock dividend expense reflects cash dividends
paid of $600,000 at an annual rate of 12% and $675,000 of paid-in-kind dividends
calculated at an annual rate of 13.5% through December 15, 1998.  Also included
in 1998 expense is $72,000 of amortization expense related to Sheridan Preferred
Stock fees, which are being amortized over the five-year redemption period.  At
current product prices, the Company anticipates that 1999 dividends will
continue to be paid-in-kind.

FINANCIAL CONDITION

     At December 31, 1998, the Company had a working capital deficit of
approximately $4.8 million, which includes current maturities of long term debt
of $5.6 million and $5.8 million of acquisition deposit related to the Amerada
Transaction.  Upon closing the Amerada Transaction on January 25, 1999, $2.8
million of the deposit was returned to the Company and debt outstanding under
the Bank One Facility was reduced.  The remaining $3.0 million acquisition
deposit was transferred to SCEI as part of the Company's required capital
contribution pursuant to the Formation Agreement.  Had the Amerada Transaction
been consummated as of December 31, 1998, the Company's working capital deficit
would have been $5.0 million, including current maturities of long-term debt of
$2.8 million.

     At December 31, 1998, the Bank One Facility had a borrowing base of $39.0
million with approximately $37.5 million of borrowings and letter of credit
commitments of approximately $1.2 million outstanding.  In conjunction with the
Amerada Transaction financing and closing in January 1999, the Company received
a cash deposit refund of $2.8 million.  Also in January 1999, the Company's
borrowing base under the Bank One Facility was redetermined to be $38.5 million
due to continued product price declines.  As a result of the Amerada Transaction
deposit refund and 

                                       22
<PAGE>
 
borrowing base adjustment, the Company had an adjusted availability under the
Bank One Facility, after letter of credit commitments, of approximately $2.7
million at December 31, 1998. After consideration of year-end borrowings
outstanding and the current monthly facility reduction rate, current maturities
for debt of $5.6 million were reflected at December 31, 1998. Considering the
Company's working capital deficit position, expected operating results at
current product prices and availability under the Bank One Facility, capital
resources are deemed adequate to support only reduced capital program activity
in 1999. The Company anticipates that if product prices either continue at
current levels for an extended period of time or decline further, it will be
required to seek additional financing sources to maintain its current
operational and capital program activity.

     The Bank One Facility requires the maintenance of certain financial ratios
relating to working capital, as adjusted pursuant to the credit facility,
tangible net worth, cash flow to debt service of 1.1 to 1.0, and an annual
limitation on general and administrative expense and non-oil and gas
expenditures.  In addition, the payment of dividends on Sheridan Common Stock
and Sheridan Preferred Stock is restricted except that cash dividends may be
paid on the Sheridan Preferred Stock if the Company has a cash flow to debt
service ratio of at least 1.2 to 1.  At December 31, 1998, the Company was in
default of financial ratio covenants regarding tangible net worth, cash flow to
debt service and limitation on general and administrative expense and non-oil
and gas expenditures.  The Company has received a waiver from Bank One regarding
such covenant defaults.

     The Company has certain dividend and redemption obligations related to the
Sheridan Preferred Stock.  For financial reporting purposes, the Sheridan
Preferred Stock has both debt and equity characteristics and, accordingly, is
not classified as a component of stockholders' equity.  At December 31, 1998,
the Sheridan Preferred Stock redemption value was $10.7 million.  At the
discretion of the Company, dividends may be paid in kind through the issuance of
additional fully paid shares at the rate of 13.5%.  At current product prices,
the Company anticipates paying 1999 dividends through the issuance of additional
shares.  The Company has no redemption obligation, except in certain defined
situations, on the Sheridan Preferred Stock until December 15, 2002, at which
time all of the Sheridan Preferred Stock then outstanding, plus any accrued
dividends, must be redeemed.  See "Sheridan Preferred Stock."

     On January 25, 1999, but effective as of November 1, 1998, pursuant to the
Amerada Transaction, the Company acquired, through SCEI,  approximately $58.0
million of California Properties from Amerada Hess Corporation.  As a result of
the Amerada Transaction, SCEI obtained an interest in approximately 82 billion
cubic feet of proven natural gas reserves in the Sacramento Basin, California.
In order to finance a portion of the Amerada Transaction, SCEI borrowed through
the SCEI Facility approximately $43.0 million, of which approximately $30.6
million was borrowed in January 1999 and an additional $7.1 million is
anticipated to be borrowed upon final closing in April 1999.  See "Bank
Indebtedness."  In addition, the Company entered into the Formation Agreement
with Calpine and CPN, each unaffiliated parties, pursuant to which SCEI was
created to acquire and own the California Properties.  CPN contributed $14.9
million in cash and received $13.0 million in seven-year redeemable non-voting
SCEI Preferred Stock and 20% of the outstanding common stock of SCEI.  In
certain circumstances, the Company may be entitled to acquire the common stock
held by CPN.  The Company contributed $3.0 million in cash and $4.6 million of
seismic and oil and gas producing assets in California and received 80% of the
outstanding common stock of SCEI.  This transaction resulted in no impact on
1998 results of operations.

LIQUIDITY AND CAPITAL RESOURCES

     For 1998, operating activities resulted in a use of net cash of $270,000
primarily due to litigation settlement payments of $2.8 million.  Excluding
working capital changes, gains on property sales and litigation settlement
payments and provisions, cash provided by operating activities for 1998 was
approximately $3.7 million.

     As required by the Bank One Facility and ECT Agreement, the Company entered
into swap agreements to reduce its exposure to price fluctuations on a portion
of its natural gas and oil sales and to achieve a more predictable cash flow.
As of December 31, 1998, the Company had hedged approximately 3.7 Bcf and 2.2
Bcf of 1999 and 2000 natural gas production, at a weighted average sales price
per Mcf of approximately $2.51 and $2.36, respectively.  In early 1999, the
Company hedged an additional 1.1 Bcf of 1999 natural gas production resulting in
total 1999 volumes hedged of 4.8 Bcf or 75% of corresponding proved developed
producing reserves as estimated by the Company's independent petroleum engineers
at a weighted average sales price per Mcf of approximately $2.44.

                                       23
<PAGE>
 
     At December 31, 1998, the Bank One Facility had a borrowing base of $39.0
million with $37.5 million of borrowings and letter of credit commitments
totaling approximately $1.2 million outstanding.  In conjunction with the
Amerada Transaction financing and closing in January 1999, the Company received
a cash deposit refund of $2.8 million.  Also in January 1999, the Company's
borrowing base under the Bank One Facility was redetermined to be $38.5 million
due to continued product price declines.  As a result of the Amerada Transaction
acquisition deposit refund and borrowing base adjustment, the Company had an
adjusted availability under the Bank One Facility, after letter of credit
commitments, of approximately $2.7 million at December 31, 1998.  After
consideration of year-end borrowings outstanding and the current monthly
facility reduction rate, current maturities for debt of $5.6 million were
reflected at December 31, 1998.  Considering the Company's working capital
deficit position, expected operating results at current product prices and
availability under the Bank One Facility, capital resources are deemed adequate
to support a reduced capital program in 1999.  The Company anticipates that if
product prices either continue at current levels for an extended period of time
or significantly decline further, it will be required to seek additional
financing sources to maintain its current operational and capital program
activity.

     As of December 31, 1998 the Company had 1.1 million shares of Sheridan
Preferred Stock outstanding with a redemption value of $10 per share.  Cash
dividends of $0.60 per share are payable semi-annually each June 15 and December
15 (a 12% annual rate).  At the option of the Company, dividends may be paid-in-
kind, semi-annually, in an amount equal to 0.0675 shares for each share then
issued and outstanding (a 13.5% annual rate).  The Company has an obligation to
redeem the Sheridan Preferred Stock on December 15, 2002.  Based on the current
economic environment, the Company anticipates paying all 1999 preferred stock
dividends through the issuance of additional shares.

     The Company anticipates that continued development drilling and workovers
will maintain or increase current production volumes.  The current projected
cash flows from existing properties and borrowings available under the Company's
current line of credit are considered adequate to fund current operating
activities.  Any sizeable acquisitions or expansion of capital expenditures will
have to be financed through a combination of bank borrowings, mezzanine
financing, production payments, property sales and/or additional equity
issuance.  Effective implementation of the Company's development and acquisition
plans is expected to meet the Company's long-term operating and liquidity
requirements.

     The SCEI Facility and SCEI Preferred Stock restrict the utilization of SCEI
borrowing capacity or cash flow for the benefit of Sheridan except for
designated payments to Sheridan regarding general and administrative
reimbursements, as defined.  However, the SCEI Facility and SCEI Preferred Stock
is repayable only by SCEI and is not an obligation of Sheridan.

Accounting for Derivative Instruments and Hedging Activities

     In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which requires
that companies recognize all derivatives as either assets or liabilities in the
balance sheet and measure those instruments at fair value.  SFAS No. 133
provides, if certain conditions are met, that a derivative may be specifically
designated as (1) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment (fair value
hedge) or (2) a hedge of the exposure to variable cash flows of a forecasted
transaction (cash flow hedge).  Under SFAS No. 133, the accounting for changes
in fair value of a derivative depends on its intended use and designation.  For
a fair value hedge, the gain or loss is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item.  For a cash
flow hedge, the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income and subsequently
reclassified into earnings when the forecasted transaction affects earnings.
For all other items not designated as hedging instruments, the gain or loss is
recognized in earnings in the period of change.  The Company is required to
adopt this Statement by the first quarter of 2000 and is currently assessing its
effect on the consolidated financial statements.

                                       24
<PAGE>
 
Inflation and Changes in Prices

     The Company's revenues have been and will continue to be affected by
changes in oil and natural gas prices, which have declined substantially from
1997.  Although the futures markets provide some indication of crude oil and
natural gas prices for the subsequent 12 to 18 months, prices in the future
markets are subject to substantial changes in relatively short periods of time.
For management purposes, the Company assumes that oil and natural gas prices
will continue to fluctuate but ultimately trend upward and that operating costs
and expenses will escalate at or above the current inflation per annum rate.
The principal effects of inflation on the Company relate to the costs required
to drill, complete and operate oil and natural gas properties.  Drilling costs,
which until 1998 had been on a general upward trend, have recently been
decreasing primarily due to an industry-wide decline in drilling activity.  This
decrease in drilling costs is not anticipated to significantly benefit the
Company's current operations due to its anticipated reduction in 1999 drilling
activity.

Year 2000

     Historically, certain computer systems, as well as certain hardware
containing embedded chip technology, such as micro controllers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the Year 2000.
This could result in significant system failures.  The Company relies on its
computer-based management information systems, as well as embedded technology,
to operate instruments and equipment in conducting its normal business
activities.  Certain of these computer-based programs and embedded technology
may not have been designed to function properly with respect to the application
of dating systems relating to the Year 2000.

     In response, the Company has developed a "Year 2000 Plan" and has
established an internal group to identify and assess potential areas of risk and
to make any required modifications to its computer systems and equipment used in
oil and gas exploration, production, gathering and gas processing activities.
The Year 2000 Plan is comprised of various phases, including assessment,
remediation, testing and contingency plan development.  After the assessment
phase has been completed and evaluated, the remediation, testing and
certification phases will be implemented to ensure that the material facilities
and business activities will continue to operate safely and reliably, and
without interruption after 1999.  Based upon the results of these activities
contingency plans will be developed to the extent deemed necessary.

     The Company's inventory of computer hardware and primary business software
is substantially Year 2000 compliant.  The Company is currently assessing its
engineering software systems for compliance.  It is anticipated that these
software systems will be Year 2000 compliant.  If any programming modifications
are required, such should be completed and tested by the second quarter of 1999
with implementation and conversion scheduled for the third quarter of 1999.

     The Company has monitor and control equipment with embedded chip technology
which are utilized in production and gas processing operations.  These various
systems are currently being reviewed in conjunction with the overall Year 2000
Plan and to date no major compliance issues have been discovered.  Other systems
with embedded chip technology are relatively new and should be Year 2000
compliant according to the manufacturers.

     The Company has also undertaken to monitor the compliance efforts of
suppliers, contractors and other third parties with whom it does business and
whose computer-based systems and/or embedded technology equipment interface with
those of the Company to ensure that operations will not be adversely affected by
the Year 2000 compliance problems of others.  There can be no assurance that
there will not be an adverse effect on the Company if vendors, suppliers,
customers, state and federal governmental authorities and other third parties do
not convert their respective systems in a timely manner and in a way that is
compatible with the Company's information systems and embedded technology
equipment.  However, management believes that ongoing communication with and
assessment of the compliance efforts and status of these third parties will
minimize these risks.

     The Company believes that it can provide the resources necessary to ensure
Year 2000 compliance and expects to complete its Year 2000 Plan within a time
frame that will enable its computer-based programs and embedded 

                                       25
<PAGE>
 
technology equipment to function without significant disruption in the Year
2000. Through 1998, the Company has incurred less than $10,000 in third party
costs for software and equipment costs related to Year 2000 compliance matters
and estimates that the total future third party, software and equipment costs
related to Year 2000 compliance activities, based upon information developed to
date, will be less than $50,000 and will be expensed as incurred. These costs
have been and will continue to be funded through operating cash flows and are
not deemed to be material to the operations of the Company. The cost of the
remediation activities and the completion dates are based on management's best
estimates and may be updated as additional information becomes available. The
costs incurred to date and those estimated to be incurred in the future with
respect to Year 2000 issues do not include internal costs. The Company does not
separately track the internal costs incurred with respect to implementation of
the Year 2000 Plan. Such costs are principally internal payroll costs, including
senior management, and field operations personnel, involved in the compliance
program and related travel and other out-of-pocket expenses.

     Although the Company anticipates minimal business disruption will occur as
a result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
third parties, should fail to function properly, possible consequences include
but are not limited to, loss of communications links, inability to produce and
process natural gas, loss of electric power, and inability to automatically
process commercial transactions, or engage in similar normal automated or
computerized business activities.

     To date, the Company has not finalize its contingency plans for possible
Year 2000 issues.  As noted above, in the event the Company, after completion of
the assessment, remediation and testing phases of the Year 2000 Plan and review
of the results of monitoring the compliance efforts and status of third parties,
determines that contingency plans are necessary, the Company will finalize such
contingency plans based on its assessment of outside risks.  The Company
anticipates that final contingency plans, as necessary, will be in place by the
fourth quarter of 1999.

     The discussion of the Company's efforts, and management's expectations,
relating to Year 2000 compliance contains forward-looking statements.
Presently, the Company does not anticipate that the Year 2000 issues will have a
material adverse effect on the operations or financial performance of the
Company.  However, there can be no assurance that the Year 2000 will not
adversely affect the Company and its business.

ITEM 7.  FINANCIAL STATEMENTS

     The Company's Consolidated Financial Statements as of December 31, 1998 and
1997 and for each of the two years ended December 31, 1998, and the report of
PricewaterhouseCoopers LLP, independent accountants, follow.

                       REPORT OF INDEPENDENT ACCOUNTANTS

     In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, of stockholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Sheridan Energy, Inc. and its subsidiary (the "Company") at December 31, 1998
and 1997, and the results of their operations and their cash flows for the years
then ended in conformity with generally accepted accounting principles.  These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits.  We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement.  An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation.  We
believe that our audits provide a reasonable basis for the opinion expressed
above.


PRICEWATERHOUSECOOPERS LLP

Houston, Texas
March 26, 1999

                                       26
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

                          CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
                            ASSETS                                          DECEMBER 31,
                                                                      -------------------------
                                                                        1998             1997
                                                                      --------          -------
<S>                                                              <C>              <C>
                                                                           (in thousands, 
                                                                       except for share data)
Current assets:
  Cash and cash equivalents                                           $    639          $   274
  Accounts receivable, net of allowance for doubtful accounts
   of $120 (1998) and $90 (1997)                                         4,097            3,109
  Deferred tax asset                                                        --              165
  Acquisition deposit                                                    5,800                -
  Other current assets                                                     563              244
                                                                      --------          -------
    Total current assets                                                11,099            3,792
                                                                      --------          -------
Property and equipment:
  Oil and natural gas properties                                        75,331           70,139
  Other property and equipment                                           1,025              427
  Accumulated depletion, depreciation and amortization                 (20,398)          (7,694)
                                                                      --------          -------
    Property and equipment, net                                         55,958           62,872
                                                                      --------          -------

Investment in natural gas treating plant                                   336              505
Deferred tax asset                                                         930              765
Other assets, net of accumulated amortization of $356 (1998)               
 and $127 (1997)                                                           554              765
                                                                      --------          -------
    Total other assets                                                   1,820            2,035
                                                                      --------          -------
TOTAL ASSETS                                                          $ 68,877          $68,699
                                                                      ========          =======
             LIABILITIES AND STOCKHOLDERS' EQUITY
 
Current liabilities:
  Accounts payable and accrued liabilities                            $ 10,318          $ 4,836
  Current portion of long-term debt                                      5,550               --
                                                                      --------          -------
    Total current liabilities                                           15,868            4,836
 
Long-term debt                                                          31,950           31,500
                                                                      --------          -------
    Total liabilities                                                   47,818           36,336
                                                                      --------          -------
Commitments and contingencies (Note 5)                                       -                -
Redeemable Sheridan Preferred Stock, 1,067,500 (1998) and
  1,000,000 (1997)  shares outstanding; redemption value $10,675         
  and $10,000, respectively                                             10,675           10,000

Stockholders' equity:
  Common stock, 6,731,331 shares outstanding                                67               67
  Additional paid-in capital                                            29,005           29,005
  Accumulated deficit                                                  (18,688)          (6,709)
                                                                      --------          -------
    Total stockholders' equity                                          10,384           22,363
                                                                      --------          -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                            $ 68,877           68,699
                                                                      ========          =======
</TABLE>

         See accompanying notes to consolidated financial statements.

                                       27
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

                     CONSOLIDATED STATEMENT OF OPERATIONS

<TABLE> 
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                                        1998             1997
                                                                      --------          -------
<S>                                                                 <C>              <C>
                                                                            (in thousands,
                                                                      except for per share data)
REVENUES:
  Oil and natural gas sales                                           $ 17,901         $  7,074
  Natural gas gathering                                                    258              224
  Net gains on property sales                                            1,672               29
                                                                      --------          -------
                                                                        19,831            7,327
                                                                      --------          -------
COST AND EXPENSES:
  Operating expenses                                                     6,162            2,027
  Treating and transportation expenses                                     795              611
  Depletion, depreciation and amortization                              10,057            2,592
  Impairment provision on oil and gas properties                         3,244               --
  General and administrative expenses                                    4,669            2,767
  Exploration costs                                                        931              484
                                                                      --------          -------
                                                                        25,858            8,481
                                                                      --------          -------
OPERATING LOSS                                                          (6,027)          (1,154)
Other income (expenses):
  Provision for litigation expense                                      (2,349)          (1,000)
  Equity earnings in natural gas treating plant                            601              507
  Interest and other income                                                  2              124
  Interest expense                                                      (2,826)            (344)
                                                                      --------          -------
                                                                        (4,572)            (713)
                                                                      --------          -------
LOSS BEFORE INCOME TAXES                                               (10,599)          (1,867)
Income tax expense                                                          --               --
                                                                      --------          -------
NET LOSS                                                               (10,599)          (1,867)
Preferred stock dividends                                               (1,380)          (5,894)
Accretion of TGX Senior Preferred redemption value                          --           (3,205)
                                                                      --------          -------
NET LOSS APPLICABLE TO COMMON STOCK                                   $(11,979)        $(10,966)
                                                                      ========         ========
LOSS PER SHARE:
  Basic and diluted                                                   $  (1.78)           (2.51)
                                                                      ========         ======== 
WEIGHTED AVERAGE SHARES:
  Basic and diluted                                                      6,731            4,365
                                                                      ========         ========
</TABLE>

         See accompanying notes to consolidated financial statements.

                                       28
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

                     CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                       YEAR ENDED DECEMBER 31,
                                                                      -------------------------
                                                                        1998             1997
                                                                      --------          -------
<S>                                                                  <C>             <C>
                                                                            (in thousands)
Cash flow from operating activities:
  Net loss                                                                $(10,599)       $ (1,867)
  Adjustments to reconcile net loss to cash provided by
   operating activities:
   Depletion, depreciation and amortization                                 10,057           2,592
   Impairment provision on oil and gas properties                            3,244              --
   Provision for litigation expense                                          2,349           1,000
   Cash paid to settle litigation matters                                   (2,802)             --
   Amortization of debt transaction costs and stock compensation               157              31
   Net gains on property sales                                              (1,672)            (29)
   Distribution in excess of equity earnings                                   169              91
   Changes in current operating assets and liabilities:
     Increase in accounts receivable                                          (988)          (1,818)
     Increase in acquisition deposit                                        (5,800)               -
     Increase in other current assets                                         (319)            (127)
     Increase in accounts payable and accrued liabilities                    5,934              787
   Deferred tax asset                                                           --               --
                                                                          --------         --------
Net cash provided by (used in) operating activities                           (270)             660
                                                                          --------         -------- 
Cash flow from investing activities:
  Capital expenditures                                                     (17,419)         (50,988)
  Proceeds from property sales                                              12,685              283
                                                                          --------         --------
  Net cash used in investing activities                                     (4,734)         (50,705)
                                                                          --------         -------- 
Cash flow from financing activities:
  Proceeds from issuance of redeemable preferred shares                         --           10,000
  Proceeds from issuance of common shares, net                                  --            9,153
  Payments on revolving credit facility                                    (25,775)          (7,950)
  Borrowings under revolving credit facility                                31,775           37,950
  Payment of preferred share dividends                                        (600)              --
  Debt and preferred stock transaction costs and other                         (31)            (758)
                                                                          --------         --------
  Net cash provided by financing activities                                  5,369           48,395
                                                                          --------         --------
Net increase (decrease) in cash and cash equivalents                           365           (1,650)
Cash and cash equivalents at beginning of period                               274            1,924
                                                                          --------         --------
Cash and cash equivalents at end of period                                $    639         $    274
                                                                          ========         ======== 
Supplemental Disclosure of Non-Cash Investing and Financing Activities:
  Common shares and warrants issued for oil and gas properties, net       $    --          $  4,127
  Preferred stock dividends paid through issuance of additional shares    $    675         $     --
</TABLE>

         See accompanying notes to consolidated financial statements.

                                       29
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

                CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

                For the Years Ended December 31, 1998 and 1997
                                (in thousands)
<TABLE>
<CAPTION>                                                                                Additional                       Total    
                              Old Preferred           TGX               Sheridan          Paid-in     Accumulated     Stockholders'
                                  Stock           Common Stock         Common Stock       Capital       Deficit     Equity (Deficit)
                                  -----           ------------         ------------       -------       -------     ----------------
                            Shares     Amount    Shares    Amount      Shares   Amount
                            ------     ------    ------    ------      ------   ------
<S>                         <C>      <C>       <C>        <C>         <C>     <C>         <C>          <C>               <C>
Balance, December 31, 1996     485     $ 485     24,956     $ 290          --   $  --       $ 1,665      $(72,116)         $(69,676)
  Preferred dividends payable     
   with additional shares of    
   Old Preferred                12        12         --        --          --       --          108          (120)               --
  Dividends on TGX Senior
   Preferred Stock              --        --         --        --          --       --           --        (5,721)           (5,721)
  Accretion of TGX Senior
   Preferred Stock redemption
   value                        --        --         --        --          --       --           --        (3,205)           (3,205)
  Adjustments due to Merger    
   (Note 1)                   (497)     (497)   (24,956)     (290)      4,281       43       14,006        76,373            89,635
  Issuance of shares for cash   --        --         --        --       1,600       16        9,137            --             9,153
  Issuance of shares for oil
   and gas properties           --        --         --        --         850        8        4,089            --             4,097
  Dividends on Sheridan
   Preferred Stock              --        --         --        --          --       --           --           (53)              (53)
  Net loss                      --        --         --        --          --       --           --        (1,867)           (1,867)
                               ---    ------    -------    ------      -------    ----      -------      --------          --------
Balance, December 31, 1997     --        --         --        --       6,731       67       29,005        (6,709)           22,363
                              ---    ------    -------    ------      -------    ----      -------      --------          --------
  Dividends on
   Sheridan Preferred Stock    --        --         --        --          --       --           --        (1,380)           (1,380)
  Net loss                     --        --         --        --          --       --           --       (10,599)          (10,599)
                              ---    ------    -------    ------      -------    ----      -------      --------          --------
Balance, December 31, 1998     --    $   --         --    $   --        6,731    $ 67      $29,005      $(18,688)         $ 10,384
                              ===    ======    =======    ======      =======    ====      =======      ========          ========
</TABLE>

                                       30
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   BUSINESS, REORGANIZATION PROCEEDINGS AND EQUITY RESTRUCTURING

Business

  Sheridan Energy, Inc. ("Sheridan" or the "Company") is the successor to its
former parent company, TGX Corporation ("TGX"), and is a domestic independent
energy company engaged in the production of oil and natural gas.  The Company is
also engaged in intrastate natural gas gathering and treating.

Reorganization Proceeding

  On February 22, 1990, TGX filed a voluntary petition for reorganization
pursuant to Chapter 11, Title 11 of the United States Code (the "Reorganization
Proceeding").  On January 7, 1992, the bankruptcy court confirmed a
reorganization plan ("Reorganization Plan") for TGX, and the confirmation order
became effective on January 21, 1992.  On September 21, 1992, the bankruptcy
court determined that the Reorganization Plan had been substantially
consummated, and the bankruptcy court's order of substantial consummation became
final and non-appealable on October 2, 1992.  The effects of the Reorganization
Proceeding were accounted for in accordance with the fresh start reporting
standards of AICPA Statement of Position 90-7 "Financial Reporting by Entities
in Reorganization Under the Bankruptcy Code."

  In conjunction with implementing fresh start reporting, a reorganization value
of TGX's assets and liabilities as of October 2, 1992 was determined by
management on the basis of its best judgment of the fair market value of TGX's
assets and liabilities at the time, after reviewing relevant facts concerning
the price at which similar assets were being sold.  Accordingly, the balance
sheet includes amounts reflecting reorganization values.

  Under the Reorganization Plan, creditors of TGX received shares of TGX's
Series A Senior Preferred Stock (the "TGX Senior Preferred Stock") which were
mandatorily redeemable on or before January 21, 2002.  The Reorganization Plan
provided that the holders of TGX 9% Cumulative Convertible Preferred Stock ("Old
Preferred") and TGX common stock ("TGX Common Stock") would retain their shares
primarily to preserve their interest in a potential recovery from TGX's
litigation with National Fuel Gas Distribution Corporation ("NFG Litigation").
The NFG Litigation was settled on April 12, 1996, and TGX, after payments to
other non-affiliated parties entitled to share in the settlement, retained
approximately $3.5 million from such settlement.  Because TGX's net assets,
including proceeds from the NFG Settlement and expected cash flows were clearly
insufficient to redeem the TGX Senior Preferred Stock, TGX effected an equity
restructuring (the "Merger") on June 12, 1997.

Equity Restructuring

  Pursuant to the Merger, holders of TGX Senior Preferred Stock received 0.5
shares of Sheridan common stock ("Sheridan Common Stock") for each share of TGX
Senior Preferred Stock, resulting in the issuance of approximately 4.3 million
shares of Sheridan Common Stock.  The Old Preferred Stock and TGX Common Stock
(collectively "Other TGX Stock") were eliminated pursuant to the Merger.  The
Merger was accounted for as a reorganization of related parties with carryover
basis of assets and liabilities.  The Sheridan Common Stock was recorded at the
combined carrying value of Other TGX Stock and the initial value ascribed to the
TGX Senior Preferred Stock upon their issuance on the date of the Merger.
Accordingly, upon cancellation, all recorded TGX preferred stock liabilities,
including accretion and unpaid dividends, were credited to accumulated deficit.
No gain or loss was recognized upon consummation of the Merger, and all pre-
Merger results, including TGX Senior Preferred Stock dividends and accretion
charges, were reflected as Sheridan activity.  The costs of soliciting proxies
and effecting the Merger were charged to expense as incurred.  All prior period
per share data and amounts have been restated to reflect issuance of Sheridan
Common Stock on a retroactive basis.

                                       31
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


  The following table reflects pro forma earnings per share of Sheridan Common
Stock as if the Merger had been effective as of January 1, 1997 and all TGX
Senior Preferred Stock and Old Preferred Stock dividends and related accretion
charges had been eliminated as of such date (in thousands, except per share
data):
                                                             1997
                                                             ----
Pro forma net loss per share - basic and diluted           $(0.44)
                                                           ======
Weighted average shares outstanding                         4,365
                                                           ======

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

  The accompanying consolidated financial statements include the accounts of
Sheridan and its subsidiary, TEIC.  All significant intercompany accounts and
transactions have been eliminated.  Companies owned 20% to 50% are accounted for
under the equity method of accounting.

Oil and Natural Gas Properties

  The Company follows the successful efforts method of accounting for oil and
natural gas operations.  Under the successful efforts method, capitalized costs
relating to proved properties are amortized using the units-of-production method
based on estimated proved reserves.  The cost of unsuccessful exploration wells
is charged to operations.

Other Property and Equipment

  Other property and equipment is stated at cost.  Depreciation of other
property and equipment is provided on the straight-line method over the
estimated useful lives of the related assets which range from 3 to 10 years.

Impairment of Long-Lived Assets

  Long-lived assets with recorded values that are not expected to be recovered
through future cash flows are written down to estimated fair value in accordance
with Statement of Financial Accounting Standards ("SFAS") No. 121.  Fair value
is generally determined from estimated discounted future net cash flows.

Revenue Recognition

  Revenue from the sale of crude oil is recognized upon the passage of title,
net of royalties.  Revenue from natural gas production is recognized using the
sales method, net of royalties.  Pursuant to the terms of various agreements,
the Company, as a working interest owner, is responsible for marketing its share
of natural gas production from certain properties.  If the Company or other
working interest owners are unable or unwilling to market its share of natural
gas production from a property, the Company or other working interest owners may
market such gas subject to balancing with other working interest owners who have
sold more than their proportionate share of natural gas production.  Any
balancing recoupments or settlements, which will typically be over an extended
period of time, are not anticipated to be material to future operating results.

                                       32
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Derivative Financial Instruments

  The Company has limited involvement with derivative financial instruments and
does not use them for trading purposes.  They are used to manage well-defined
natural gas and crude oil price and interest rate risk.  Gains and losses on
natural gas and oil swaps are recognized in oil and gas revenues when the hedged
production is sold.

  Interest rate swap agreements are used to reduce the potential impact of
increases in interest rates on the Company's variable rate revolving credit
facility.  Amounts receivable or payable under interest rate swaps are settled
in cash and are reflected as adjustments to interest expense.

Stock Based Compensation

  As allowed by SFAS No. 123, the Company has elected to continue to follow the
accounting prescribed by Accounting Principles Board Opinion No. 25 "Accounting
for Stock Issued to Employees," whereby compensation costs are recognized only
in situations where stock compensation plans award intrinsic value to recipients
at the date of grant, rather than the fair value method of SFAS No. 123.  Pro
forma disclosure of the estimated effects on net income and earnings per share
had the fair value method prescribed by SFAS No. 123 been followed are included
in Note 10.

Per Share Amounts

  In accordance with SFAS 128, basic earnings per share is computed by dividing
net income (loss) applicable to common stock by the weighted average number of
common shares outstanding.  Diluted earnings per share is computed by dividing
net income (loss) applicable to common stock by the weighted average number of
common shares outstanding plus dilutive potential common shares.  The Company's
potentially dilutive securities are stock options awarded to employees and
Sheridan Common Stock warrants.

Cash and Cash Equivalents

  The Company records as cash equivalents all highly liquid short-term
investments with original maturities of three months or less.

Income Taxes

  The Company follows SFAS No. 109, "Accounting for Income Taxes," which
requires recognition of deferred tax assets and liabilities for the expected
future tax consequences of events that have been included in the financial
statements or tax returns.  Under this method, deferred tax liabilities and
assets are determined based on the difference, if any, between the financial
reporting and tax bases of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse.

Accounting Estimates

  The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make certain estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities.  Actual
results could differ from those estimates.

Accounting for Derivative Instruments and Hedging Activities

  In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which requires
that companies recognize all derivatives as either assets or 

                                       33
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


liabilities in the balance sheet and measure those instruments at fair value.
SFAS No. 133 provides, if certain conditions are met, that a derivative may be
specifically designated as (1) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment
(fair value hedge) or (2) a hedge of the exposure to variable cash flows of a
forecasted transaction (cash flow hedge). Under SFAS No. 133, the accounting for
changes in fair value of a derivative depends on its intended use and
designation. For a fair value hedge, the gain or loss is recognized in earnings
in the period of change together with the offsetting loss or gain on the hedged
item. For a cash flow hedge, the effective portion of the derivative's gain or
loss is initially reported as a component of other comprehensive income and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. For all other items not designated as hedging instruments, the gain or
loss is recognized in earnings in the period of change. The Company is required
to adopt this Statement by the first quarter of 2000 and is currently assessing
its effect on the consolidated financial statements.

Reclassifications

  Certain amounts from prior years have been reclassified to conform to the
current year presentation.

3.   PROPERTY AND EQUIPMENT

Acquisitions

  During 1998, the Company purchased, for cash and notes payable, $5.9 million
of oil and gas properties through numerous transactions with various effective
dates of purchase and closing dates.

  During 1997, the Company purchased, for cash and securities of the Company,
$52.5 million of oil and gas properties.  In one transaction, closed December
15, 1997, the Company acquired oil and gas producing and non-producing
properties from Pioneer Natural Resources USA, Inc. (the "Pioneer Acquisition")
for $46.7 million, which was funded through the issuance of $10.0 million of
Series A Preferred Stock ("Sheridan Preferred Stock"), $10.0 million of Sheridan
Common Stock and approximately $28.0 million in bank borrowings.  In a second
transaction, closed December 31, 1997, the Company acquired additional oil and
gas producing and non-producing properties from Grand Gulf Resources, L.L.C.
("Grand Gulf") and JEDI Hydrocarbon Investments I Limited Partnership ("JEDI I")
(the "Grand Gulf Acquisition") through the issuance of 850,000 shares of
Sheridan Common Stock and warrants to acquire an additional 150,000 shares of
Sheridan Common Stock at $5.50 per share.  The Grand Gulf Acquisition was valued
at $4.1 million, based on the estimated value of the assets acquired and an
analysis of the value of the securities given in consideration.

  The 1998 and 1997 acquisitions were accounted for using the purchase method of
accounting, effective at date of closing.

Pro Forma Acquisition Information (Unaudited)

  Had all 1997 acquisitions been consummated as of January 1, 1997, the impact
would have been an increase in revenues of $13.6 million and an increase in the
loss applicable to common stock of $1.3 million.  The pro forma impact of the
1998 acquisitions was not material to the Company's 1998 revenues or results of
operations.

  The following table summarizes certain pro forma condensed consolidated
results of operations data that give effect to the 1997 acquisitions as if they
had occurred on January 1, 1997, including the associated impact of financing
costs, including dividends, and incremental general and administrative costs for
the year ended December 31, 1997 (in thousands, except per share data):

                                       34
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Total revenues                                                $ 20,962
Net loss applicable to common stock                           $(12,271)
Net loss per share of common stock - basic and diluted        $  (1.80)

Provision for Impairment Loss

     In 1998, the Company recognized a non-cash impairment provision on
certain oil and gas properties of $3.2 million resulting from its application of
SFAS No. 121.  The impairment was due to a decline in crude oil and natural gas
prices.  Fair value was determined through reference to future net cash flows,
discounted at 10%.

4.   LONG-TERM DEBT

     As of December 31, 1998 and 1997, the components of long-term debt were as
follows:

                                                        1998          1997
                                                       -------       -------
                                                          (in thousands)
Secured bank debt under revolving credit facility      $37,500       $31,500
Less current maturities                                 (5,550)           --
                                                       -------       -------
Long-term debt                                         $31,950       $31,500
                                                       =======       =======

     Prior to 1997, the Company entered into a borrowing base facility
("Facility") with Bank One, Texas, N.A. ("Bank One"). The Bank One Facility, as
of December 31, 1998, had a borrowing base of $39.0 million and is scheduled to
mature on June 30, 2001. The Company may elect to borrow at Bank One's stated
rate (7.75% at December 31, 1998) or LIBOR (5.06% at December 31, 1998) plus
2.5%. In addition, the Company pays a commitment fee of 0.375% per annum on the
unused portion of the borrowing base. The Facility is secured by substantially
all of the Company's oil and gas properties and is repayable through monthly
borrowing base reductions of $550,000. The borrowing base is redetermined every
six months or at Bank One's discretion. In January 1999 the borrowing base was
redetermined to be $38.5 million and year-end Bank One borrowings were reduced
by $2.8 million in conjunction with the completion of the Amerada Transaction
(Note 18). After consideration of the current borrowing base and monthly
facility reduction rate, current maturities of $5.6 million were reflected in
the consolidated balance sheet at December 31, 1998.

     The Bank One Facility requires the maintenance of certain ratios relating
to working capital, as adjusted pursuant to the Facility, tangible net worth,
cash flow to debt service of 1.1 to 1.0 and annual limitations on general and
administrative expenses and non-oil and gas capital expenditures. In addition,
the payment of dividends on Sheridan Common Stock and Sheridan Preferred Stock
is restricted except that cash dividends may be paid on the Sheridan Preferred
Stock if the Company has a cash flow to debt service of at least 1.2 to 1. The
Company was in default on certain of these financial covenant ratios at December
31, 1998 but received waivers from Bank One regarding these covenants.

     As of December 31, 1998, the Company had letters of credit outstanding of
$1.2 million under the Bank One Facility, which reduced the Company's
availability under the Facility.

     Costs incurred regarding the establishment of the Bank One Facility are
included in other assets and are being amortized over the term of the facility.
As of December 31, 1998 and 1997, the remaining unamortized costs totaled
$264,000 and $392,000, respectively.

                                       35
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)     

     Cash paid for interest during 1998 and 1997 totaled approximately $2.5
million and $264,000, respectively.

5.   COMMITMENTS AND CONTINGENCIES

Litigation

     (a) In July, 1992, certain unleased mineral interest owners commenced
a legal action in the 19th Judicial District for East Baton Rouge, Parish,
Louisiana Case No. 383844, Division "A," against TGX, as operator of three
wells.  The petition alleged that the unleased owners were entitled to a refund
of revenues paid to TGX and other working interest owners, since first
production, which were attributable to the unleased owners' proportionate unit
interests and were utilized to offset the plaintiffs' proportionate share of
costs associated with drilling the wells.  The Company argued that any claim
which arose prior to the date of the entry of the order confirming the
Reorganization Plan had been discharged through bankruptcy.  The Company filed a
lawsuit in the U.S. Bankruptcy Court for the Western District of Louisiana (Case
No. 96AP-1047) claiming such a defense.  However, the Bankruptcy Court rejected
that defense.  Further, the Company argued that its payout notice to the
unleased owners complied with statutes requirements.  The Louisiana District
Court, in August 1998, entered a judgment against the Company for $2.4 million,
plus interest and plaintiff's court cost.  In December 1998, the Company settled
with approximately 85% of the plaintiffs for a cash payment of $1.3 million.
The Company was required by statute to issue a letter of credit in the amount of
$476,000 to pursue its appeal for the remaining unsettled judgment.  In March,
1999, the remaining claimants agreed to settle this matter for $230,000.  Upon
settlement, the letter of credit will be canceled.

     (b) In July 1995, certain royalty owners in the same wells commenced a
separate legal action alleging that Sheridan's predecessor, TGX, and other
working interest owners improperly profited under the terms of a Gas Gathering
and Transportation Agreement.  In 1996, the court entered an order granting a
motion on behalf of TGX for a partial summary judgment, holding that all of the
royalty owners' claims preceding the filing of the suit by more than three years
were time-barred.  The Company has asked the court to dismiss the remaining
claims asserted by the royalty owners.  If not dismissed, the Company will
vigorously defend against this lawsuit.

     (c) In May 1982, Samson Resources Company ("Samson") brought suit
against Sheridan's predecessor, TGX, in the United States District Court for the
Western District of Oklahoma alleging that the Company owed Samson for its
under-production on a well in Oklahoma.  Sheridan argued that the claim which
arose prior to the date of the entry of the order confirming the Reorganization
Plan had been discharged through bankruptcy.  The Oklahoma District Court, in
August 1998, entered a judgment against the Company for $205,000, plus interest
and plaintiff court costs.  In February 1999, the Company agreed to settle this
lawsuit by paying $258,000 and receiving a full release regarding this matter.

     (d) In December 1996, Tomcat Exploration, Inc. and others brought suit
against Sheridan's predecessor, TGX, in the 215th District Court of Harris
County, Texas alleging that TGX's operation of the Sinclair No. 1 Well in
Louisiana was negligent and, as a result, caused damage and loss to the
plaintiffs in excess of $10.0 million.  In October 1998, the Company agreed to
settle this lawsuit by paying the plaintiff group $1.5 million and receiving a
full release regarding this matter.

     As a result of management's assessment of the likelihood of losses
from the various litigation matters against the Company, based on advice of
legal counsel and review of the facts, circumstances, and developments
surrounding these litigation matters, the Company recorded provisions in 1998
and 1997 of $2.4 million and $1.0 million, respectively, representing its
estimate of losses and/or related costs and expenses associated with such
litigation matters, including actual litigation settlements completed through
March 26, 1999.

                                       36
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

     From time to time, in the normal course of business, the Company is a party
to other litigation matters, the outcome of which, to the extent not otherwise
provided for, should not, in the opinion of management, have a material adverse
effect on the Company's financial position, cash flows or results of operations.

Leases

     As of December 31, 1998, future minimum lease payments for office and
equipment, under noncancellable operating leases, are as follow:

                Year Ended
               December 31,                                Amount
               ------------                                ------
                                                       (in thousands)

                  1999...........................            $308
                  2000...........................             312
                  2001...........................             254
                  2002...........................               4
                  2003...........................               -
                                                             ----
                  Total minimum lease payments...            $878
                                                             ====

     Rent expense for the years ended December 31, 1998 and 1997 was $233,000
and $90,000, respectively.

6.   INVESTMENT IN NATURAL GAS TREATING PLANT

     The Company owns a 35% interest in the Comite Field Plant Venture, an
Oklahoma general partnership, formed in April 1982 for the purpose of
constructing and operating a natural gas treating plant to serve the Comite
Field in East Baton Rouge Parish, Louisiana.  Natural gas produced from one well
operated by the Company and two wells operated by third parties are transported
to the Comite Plant where contaminants are extracted to satisfy pipeline
specifications.  In addition, the plant also provides condensate handling and
salt water disposal facilities.  The Company receives cash distributions for its
share of net cash flow.  Further, the Company is charged for gas treating and
transportation for its share of throughput.  Such charges are included in the
consolidated statement of operations as treating and transportation expenses.

                                       37
<PAGE>
 
     A summary of the Comite Plant's financial position as of December 31, 1998
and 1997 and the results of its operations for the years then ended is as
follows (unaudited):

                                                              1998        1997
                                                             ------      ------ 
                                                                (in thousands)
SUMMARY BALANCE SHEET
Current assets.........................................      $  484      $  783
Net property and equipment.............................         486         885
                                                             ------      ------ 
    Total assets.......................................      $  970      $1,668
                                                             ======      ======

Current liabilities....................................      $  178      $  225
Partners' capital......................................         792       1,443
                                                             ------      ------ 
    Total liabilities and partners' capital............      $  970      $1,668
                                                             ======      ======
 
SUMMARY STATEMENT OF OPERATIONS
Fees earned............................................      $2,845      $2,631
Operating expenses.....................................       1,122       1,158
                                                             ------      ------ 
Net income.............................................      $1,723      $1,473
                                                             ======      ======

7.   ACCOUNTS RECEIVABLE

     As of December 31, 1998 and 1997, the primary components of accounts
receivable were:

                                                              1998        1997
                                                             ------      ------ 
                                                                (in thousands)
Accrued oil and gas sales                                    $3,201      $1,783
Joint interest billing and other                                914         493
Receivables for pre-closing activity for purchased              102         923
 properties
Allowance for doubtful accounts                                (120)        (90)
                                                             ------      ------ 
                                                             $4,097      $3,109
                                                             ======      ======

                                       38
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

8.   ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

     As of December 31, 1998 and 1997, the primary components of accounts
payable and accrued liabilities were:

                                                              1998        1997
                                                             ------      ------ 
                                                                (in thousands)
Accounts payable                                            $ 2,934      $  953
Undistributed net oil and natural gas revenues                2,782       1,457
Acquisition cost accruals                                     1,881          --
Accrued operating and tax expenses                            1,172         638
Provision for litigation expenses                               648       1,100
Interest payable                                                218          91
Accrued professional fees                                       142         350
Miscellaneous accruals                                          541         247
                                                            -------      ------ 
                                                            $10,318      $4,836
                                                            =======      ======

9.   REDEEMABLE PREFERRED STOCK

Sheridan Preferred Stock

     The Company is authorized to issue 5.0 million shares of preferred stock
with a par value of $.01 per share.  In order to finance a portion of the
Pioneer Acquisition, Sheridan issued 1.0 million shares of preferred stock to
Enron Capital & Trade Resources Corp. ("ECT") for $10.0 million.  The preferred
stock provides for cash dividends in an amount equal to $0.60 per share payable
semi-annually (a 12% annual rate) or, at the discretion of the Company,
dividends may be paid by issuing additional fully paid shares of preferred stock
in an amount equal to 0.0675 additional shares for each share of preferred stock
then issued and outstanding (a 13.5% annual rate).  The preferred stock also
provides for a liquidation preference of $10 per share.  The preferred stock is
redeemable from time to time at the discretion of the Company under certain
conditions and at certain established redemption prices and must be redeemed on
December 15, 2002 or upon the occurrence of certain defined situations,
including a change of control or a default, as defined in the preferred stock
designation.  The Company paid ECT a financing fee of $1.0 million, relative to
the Sheridan Common Stock and preferred stock issued to ECT, of which $300,000
was attributed to the preferred stock.  The total fees incurred related to the
preferred stock were $363,000 and are being amortized over the five-year
redemption period as additional dividends and are included in other assets.  As
of December 31, 1998 and 1997, such unamortized deferred costs totaled $290,000
and $363,000, respectively.

TGX Senior Preferred Stock

     TGX was authorized to issue 10.0 million shares of senior preferred stock
with a par value of $1 per share.  The senior preferred stock entitled its
holders to receive a 10% annual compounded cash dividend, payable quarterly,
provided that the payment of such dividend did not violate Delaware law or
certain covenants in TGX's bank loan agreements.  TGX did not pay any of the
quarterly dividends required.  The senior preferred stock had a liquidation
preference of $10 per share and had priority over the liquidation preference
afforded the holders of Series B Preferred Stock (the "Junior Preferred"), Old
Preferred and TGX Common Stock.  The senior preferred stock was scheduled to be
redeemed on January 21, 2002.  The accretion of the difference between the
recorded value and the redemption amount of the senior preferred stock was
reflected as a reduction of income applicable to common stockholders.  Holders
of senior preferred stock had 95% of the voting rights of TGX, with the
remaining 5% being allocated among 

                                       39
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

the holders of the Junior Preferred, Old Preferred and TGX Common Stock. The TGX
Senior Preferred stockholders received 0.5 shares of Sheridan Common Stock
pursuant to the Merger and Equity Restructuring (Note 1).

     Since December 31, 1996, changes in the number of shares and associated
values of TGX Senior Preferred Stock are as follows:
<TABLE>
<CAPTION>
 
                                                                 Number   Recorded
                                                               of Shares    Value
                                                               ---------    -----
                                                                 (in thousands)
<S>                                                          <C>          <C>
     Balance, December 31, 1996...........................       8,788    $ 80,726
                                                                ------    --------
     Accrued and unpaid dividends.........................          --       5,721
     Accretion on redemption value and dividends..........          --       3,205
     Compensation benefit due to management forfeitures...        (110)        (13)
     Shares canceled......................................        (115)         (2)
     Other adjustments....................................          --          (2)
                                                                ------    --------
     Subtotal.............................................       8,563      89,635
     Cancellation of shares due to Merger.................      (8,563)    (89,635)
                                                                ------    --------
     Balance, December 31, 1997...........................          --    $     --
                                                                ======    ========
</TABLE>

10.  STOCKHOLDERS' EQUITY

Sheridan Common Stock

     The Company is authorized to issue 20.0 million shares of common stock with
a $0.01 par value.  All outstanding shares of common stock are fully paid and
non-assessable.  The holders of common stock are entitled to one vote per share
upon all matters presented to them and are entitled to dividends in such amounts
as may be declared from time to time out of any funds legally available for such
purposes.  However, no dividends are payable until all accrued Sheridan
Preferred Stock dividends have been paid. In the event of liquidation,
dissolution or winding up of the affairs of the Company, whether voluntary or
involuntary, after payment of debts and liquidation preferences on the Sheridan
Preferred Stock, all remaining assets, if any, will be divided and distributed
among the holders of common stock pro rata according to the number of shares
owned by them.  The common stock does not have preemptive rights and is not
subject to redemption.  In order to finance a portion of the Pioneer
Acquisition, the Company entered into an agreement with ECT, a previously
unaffiliated party, pursuant to which ECT acquired 1.6 million shares of common
stock for $10.0 million.  The Company paid ECT a financing fee of $1.0 million,
of which $700,000 was attributed to the common stock.  Total fees incurred
related to the common stock issuance were $847,000, which were netted against
the proceeds received and included in paid-in-capital on the consolidated
balance sheet.

     Effective as of December 31, 1997, pursuant to the Grand Gulf Acquisition,
the Company issued  850,000 shares of common stock and warrants to acquire an
additional 150,000 shares of common stock. Such warrants expire five years after
the date of issuance and are exercisable in whole or in part from time to time
at a price of $5.50 per share.  The properties were acquired from Grand Gulf and
JEDI I.

TGX 9% Cumulative Convertible Preferred Stock

     TGX was authorized to issue 10.0 million shares of Old Preferred Stock with
a $1 par value and a liquidation preference of $10 per share, convertible at any
time at the rate of one Old Preferred Stock share for four shares of TGX Common
Stock.  All Old Preferred Stock was eliminated pursuant to the Merger and Equity
Restructuring (Note 1).


                                       40
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


TGX Common Stock

     TGX was authorized to issue 100.0 million shares of TGX Common Stock, with
a $.01 par value.  All shares of TGX Common Stock were eliminated pursuant to
the Merger and Equity Restructuring (Note 1).

Stock Incentive Plan

     Pursuant to the Company's 1997 and 1998 Flexible Incentive Plans
("Incentive Plans"), the Company is authorized to issue up to 700,000 options
for the purchase of Sheridan Common Stock to directors, officers and key
employees of the Company.  These stock options may be granted subject to
exercise terms not to exceed 10 years at a price equal to the fair market value
of the stock at the date of grant.  Of the incentive options outstanding at
December 31, 1998, 300,000 vest over three years and 304,000 vest over four
years at exercise prices ranging from $2.50 to $4.43 per share.

     Following is an analysis of all incentive and non-qualified option activity
under the 1997 and 1998 Incentive Plans:

<TABLE>
<CAPTION>
                                                   1998                          1997
                                      ----------------------------   ----------------------------
                                                      WEIGHTED                       WEIGHTED
                                                       AVERAGE                        AVERAGE
                                       SHARES       EXERCISE PRICE     SHARES      EXERCISE PRICE
                                      --------      --------------   --------      --------------
<S>                               <C>             <C>            <C>            <C>
Beginning stock options outstanding    304,000           $2.50             --             --
            
Stock options granted                  309,000            3.27        304,000          $2.50
Stock options canceled                  (9,000)           3.75             --             --
                                      --------           -----       --------          -----
Ending stock options outstanding       604,000           $2.83        304,000          $2.50
                                      ========           =====       ========          =====
Ending stock options exercisable       217,316           $2.50             --          $  --
                                      ========           =====       ========          =====            
 
Weighted average fair value of
options granted                                          $1.67                         $1.82
                                                         =====                         =====
</TABLE>

In connection with the 1997 Grand Gulf Acquisition and issuance of common shares
to ECT, the Company issued an additional 55,000 options to a consultant.  Of
these options, 25,000 have an exercise price of $6.50 per share and 30,000 an
exercise price of $6.00 per share resulting in a weighted average exercise price
of $6.23 per share.  These options are 100% vested and expire January 1, 2004.
The weighted average fair value of these options is $2.16 per share.
Compensation costs of these options was approximately $119,000, of which $67,000
was capitalized in conjunction with the Grand Gulf Acquisition and $52,000 as
cost of issuance of the ECT common shares.

  The fair value of each 1998 and 1997 option grant is estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted-
average assumptions for 1998 and 1997; expected stock price volatility of 57%;
risk-free interest rate of 5.2% and 5.5%, respectively; and an expected option
life of 10 years.  Had compensation expense for stock-based compensation been
determined based on the fair value at the date of grant under SFAS No. 123, the
Company's net income and earnings per share would have been reduced to the pro
forma amounts indicated below (in thousands except per share information):

                                       41
<PAGE>
 
<TABLE>
<CAPTION>
                                            YEAR ENDED                     YEAR ENDED
                                         DECEMBER 31, 1998              DECEMBER 31, 1997
                                         -----------------              -----------------
                                    AS REPORTED       PRO FORMA      AS REPORTED     PRO FORMA
                                    -----------       ---------      -----------     ---------
<S>                                 <C>            <C>             <C>             <C>
Net Loss                               $(11,979)       $(12,480)       $(10,966)     $(11,519)
Loss per common share - basic          $  (1.78)       $  (1.85)       $  (2.51)     $  (2.64)
 and diluted
</TABLE>

11.  FINANCIAL INSTRUMENTS

Natural Gas and Crude Oil Swaps

  Pursuant to the ECT Agreement and Bank One Facility, the Company enters into
natural gas swap agreements to reduce its exposure to price fluctuations on a
portion of natural gas sales and to achieve a more predictable cash flow.  These
swap agreements provide for monthly settlements on specified production volumes,
based on the difference between the price specified in the agreements and the
price received for such production.  With respect to any particular swap
agreement, the counterparty is required to make a payment to the Company in the
event the price received for a specified production volume is less than the
price specified in the agreement, and the Company is required to make a payment
to the counterparty in the event the price received for a specified production
volume is greater than the price specified in the agreement.  While the use of
hedging transactions limits the downside risk of adverse price movements, they
may also limit future revenues from favorable price movements.  To date, all of
the Company's hedging transactions have been carried out with an affiliate of
ECT.  The Company accounts for these transactions as hedging activities and,
accordingly, gains or losses are included in oil and gas revenues when the
hedged production is sold.

  As of December 31, 1998, the Company had hedged approximately 3.7 billion
cubic feet ("Bcf") of 1999 and 2.2 Bcf of 2000 natural gas production at a
weighted average sales price per Mcf of approximately $2.51 and $2.36,
respectively.  The fair value of the swap agreements is the amount at which they
could be settled at December 31, 1998, based on the difference between the price
specified in the swap agreements and the NYMEX futures contract prices existing
at December 31, 1998.  At December 31, 1998, the Company would have received
approximately $1.4 million if it had elected to terminate its natural gas swap
agreements.  Subsequent to December 31, 1998, the Company hedged an additional
1.1 Bcf of natural gas production for 1999 resulting in total 1999 volumes
hedged of 4.8 Bcf or 75% of 1999 proved developed producing reserves as
estimated by the Company's independent petroleum engineers, at a weighted
average price per Mcf of approximately $2.44.  The Company currently has no oil
price hedges in place for 1999 or 2000 production.

  As of December 31, 1997, the Company had hedged 3.9 BCF, or approximately 45%
of 1998 projected production.  The weighted average sales price per Mcf under
the swap agreements was approximately $2.19.  Based on the fair value of the
swap agreements at December 31, 1997, the Company would have been required to
pay approximately $405,000 to terminate its natural gas swap agreements.
Subsequent to December 31, 1997, the Company had entered into oil swap
agreements for the period March through December 1998 on volumes of 120,000
barrels, or approximately 48% of 1998 projected production.  The weighted
average oil sales price under the swap agreements was approximately $17.89 per
barrel.

  The Company has an unsecured line of credit of $500,000 with an affiliate of
ECT in connection with its commodities hedging program.

                                       42
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


Interest Rate Swap Agreement

  On December 19, 1997, pursuant to the Bank One Facility, the Company entered
into an interest rate swap to manage its exposure to changes in interest rates.
Pursuant to the interest rate swap, the Company contracted a fixed rate, based
on the one-month LIBOR, of 6.03% for $20.0 million ("Notional Amount") which is
reduced monthly by $400,000 over the term of the swap, which expires June 19,
2000.  At December 31, 1998 and 1997, the Notional Amount was $15.2 million and
$20.0 million, respectively, or 41% and 63%, respectively, of year-end bank debt
outstanding.  The average LIBOR floating rate at December 31, 1998 and 1997 was
5.06% and 5.97%, respectively.  The Company would have been required to pay
approximately $177,000 and $72,000, respectively, to terminate its interest rate
swap agreement.

Counterparty Risk

  The Company is exposed to credit losses under its natural gas and crude oil
and interest rate swaps in the event of non-performance by the counterparties to
these hedging activities.  The Company anticipates, however, that counterparties
will be able to fully satisfy their obligations under the swap agreements based
on their credit standing.  Natural gas and crude oil swaps are with an affiliate
of ECT (Note 14).  The interest rate swap is with Bank One.

12.  INCOME TAXES

     The valuation of the Company's deferred tax asset is based on assumptions
concerning future oil and gas prices, limited Company history of positive
financial results and other factors unique to the Company.

     For the periods ended December 31, 1998 and 1997, the Company recorded no
current or deferred income tax expense.

     The issuance of additional shares of Sheridan Common Stock in late 1997
("1997 Ownership Change") resulted in a change of ownership for tax purposes.
As a result of the change of ownership, the Company's use of available net
operating loss carryovers, alternative minimum tax credit carryovers, investment
tax credit carryovers and other tax attributes are subject to limitation.  The
Company had previously undergone an ownership change in 1992 as a result of the
Reorganization Plan.  The Company is required to redetermine the annual
limitation and will no longer have available, as a carryover, the unused annual
limitation amounts resulting from the 1992 ownership change.

     The Company has pre-ownership change net operating losses totaling $162.8
million which expire through the year 2012.  In addition, the Company has a
post-ownership change loss carryforward of $5.9 million which expires in 2018.
Because of the 1997 Ownership Change, the Company is subject to an annual
limitation (the "382 Limitation") of $1.1 million on  the use of pre-"change of
ownership" loss carryovers.  The annual Section 382 Limitation results in a
maximum available net operating loss carryover of approximately $14.9 million,
including the current loss which is not subject to the limitation.

     In addition to the Section 382 Limitation, the Company has approximately
$20.0 million of potential net operating loss utilization attributable to
unrealized built-in gains.  The built-in gain net operating loss utilization is
only available if the gains on identified assets are realized within five years
of the 1997 Ownership Change.  The Company has depletion carryforwards as of
December 31, 1998 of $14.6 million which are limited annually to 65% of taxable
income.

     Deferred tax assets (liabilities) are comprised of the following at
December 31:

                                       43
<PAGE>
 
<TABLE>
<CAPTION>
                                                               1998            1997
                                                               ----            ----
                                                                  (in thousands)
<S>                                                       <C>             <C>
Oil and gas properties                                         $ 1,080         $(1,466)
Loss carryovers                                                  5,064           3,077
Alternative minimum tax credit carryover and other                 187             187
                                                               -------         -------
Net deferred tax asset                                           6,331           1,798
Valuation allowance                                             (5,401)           (868)
                                                               -------         -------
Net deferred tax asset after valuation reserve                 $   930         $   930
                                                               =======         =======
</TABLE>

Income tax expense differs from the amounts computed by applying the statutory
federal rate as follows:

<TABLE>
<CAPTION>
                                                               1998            1997
                                                               ----            ----
                                                                  (in thousands)
<S>                                                          <C>             <C>
Income taxes computed at statutory federal rate (34%)          $(4,073)       $   (635)
Change in valuation allowance for deferred tax asset             4,533           4,515
Decrease in available net operating loss limitation                  -          (4,454)
Provision adjustment for 1997 and 1996 actual                     (469)            359
Provision for state deferred taxes                                   -             165
Alternative minimum tax and other                                    9              99
State income taxes net of federal tax benefit                        -             (49)
                                                               -------         -------
Total income tax expense (benefit)                             $     -         $    --
                                                               =======         =======
</TABLE>

13.  MAJOR CUSTOMERS

     The Company's revenues are derived principally from uncollateralized sales
to customers in the oil and natural gas industry. The concentration of credit
risk in a single industry affects the Company's overall exposure to credit risks
since customers may be similarly affected by changes in economic and other
conditions.

     Customers which accounted for greater than 10% of oil and gas sales are as
follows:

                                                       1998            1997
                                                      ------          ------
Lion Oil Company                                         6%             20%
Chesapeake Energy Marketing, Inc.                        5%             16%
Producers Energy Marketing, Inc.                        16%             --%
Duke Energy, Inc.                                        9%             15%

14.  RELATED PARTY TRANSACTIONS

     As discussed in Note 11, the Company has natural gas and crude oil swap
agreements with ECT. The swap agreements were, in the opinion of management,
conducted at arm's-length terms based on comparable prices confirmed with
another third party at the time such agreements were executed. At December 31,
1998 the Company had a receivable, related to 1998 swap agreements, of $342,000.

     As discussed in Note 3, in connection with the Grand Gulf Acquisition, the
Company issued 850,000 shares of Sheridan Common Stock and 150,000 warrants to
purchase additional shares of Sheridan Common Stock to Grand Gulf and JEDI I.
Through a series of transactions among Grand Gulf, other related parties and
JEDI I, the 850,000 

                                       44
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

shares and 150,000 warrants are now held by JEDI I or Joint Energy Development
Investments Limited Partnership, both of which are affiliates of ECT. As
discussed in Notes 9 and 10, the Company paid ECT a $1.0 million fee in
connection with the issuance of common and preferred shares to ECT related to
the Pioneer Acquisition.

15.  EARNINGS PER SHARE

     The following table presents information necessary to calculate basic and
diluted earnings per share for the periods indicated:

<TABLE>
<CAPTION>
                                                         FOR THE YEAR ENDED DECEMBER 31,
                                                         -------------------------------
                                                              1998             1997
                                                              ----             ----
<S>                                                      <C>              <C>
                                                               (in thousands, except
                                                                  per share data)
LOSS PER SHARE - BASIC AND DILUTED:
Weighted average common shares outstanding                     6,731            4,365
                                                            ========         ========
Loss per share                                              $  (1.78)        $  (2.51)
                                                            ========         ========
EARNINGS FOR BASIC AND DILUTED COMPUTATION:
Net loss before preferred dividends and accretion           $(10,599)        $ (1,867)
Preferred stock dividends                                     (1,380)          (5,894)
Accretion of TGX Senior Preferred Stock redemption value          --           (3,205)
                                                            --------         --------
Net loss applicable to common stock per share               
 (basic and diluted)                                        $(11,979)        $(10,966)
                                                            ========         ========
</TABLE>

     All warrants and stock options issued were not included in the earnings per
share calculation as they were anti-dilutive for 1998 and 1997.

16.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     The Company's financial instruments comprise cash, receivables and
payables, bank loans and swap agreements. For trade receivables and accrued
receivables and payables, the carrying values approximate fair values due to the
liquidity and short-term nature of these instruments. Carrying value of
outstanding bank debt under the revolving credit facility approximates fair
value as the interest rates are variable market rates.

     Fair value of natural gas and crude oil swaps and interest rate swaps used
for hedging are estimated by obtaining quotes from brokers to estimate the
amounts the Company would be entitled to receive or required to pay at the
reporting date to cancel the swap agreements (Note 11).

     The carrying value of the Sheridan Preferred Stock, which was issued on
December 15, 1997, approximates its fair value at December 31, 1998 and 1997.

                                       45
<PAGE>
 
17.  INTERIM FINANCIAL DATA (UNAUDITED)

     The unaudited interim results of operations, are summarized below.

<TABLE>
<CAPTION>
                                                                           THREE MONTHS ENDED
                                                         ------------------------------------------------------
                                                         MARCH 31,     JUNE 30,    SEPTEMBER 30,   DECEMBER 31,
                                                         ---------     --------    -------------   ------------
<S>                                                      <C>          <C>            <C>             <C>
                                                                  (in thousands, except per share data)
1998:
 Revenues                                                 $ 4,508      $ 4,675         $ 4,338         $ 4,638
 Gain on property sales                                       178            8           1,444              42
 Impairment provision on oil and gas properties               --           --              --            3,244
 Operating income (loss)                                     (670)        (458)            443          (5,342)
 Provision for litigation expense (benefit)                   --           --            2,750            (401)
 Net loss applicable to common stock                      $(1,547)     $(1,382)        $(3,149)        $(5,901)
 Net loss per common share-basic and diluted              $ (0.23)     ( (0.21)        $ (0.47)        $ (0.88)
 
1997:
 Revenues                                                 $ 1,846      $ 1,450         $ 1,630         $ 2,362
 Gain (loss) on property sales                                 --           46               5             (22)
 Operating income (loss)                                      320          120             (19)         (1,575)
 Provision for litigation expense                              --           --              --          (1,000)
 Net income (loss) applicable to common stock             $(4,566)     $(4,047)        $    56         $(2,409)
 Net income (loss) per common share-basic and diluted     $ (1.06)     $ (0.94)        $  0.01         $ (0.53)
</TABLE>

18.  SUBSEQUENT EVENT

     On January 25, 1999, but effective as of November 1, 1998, the Company,
through a newly formed subsidiary, Sheridan California Energy, Inc. ("SCEI")
acquired approximately $58.0 million of oil and gas producing and non-producing
properties (the "California Properties") from Amerada Hess Corporation (the
"Amerada Transaction").  In order to finance a portion of the Amerada
Transaction, SCEI received a borrowing base facility ("SCEI Facility") from Bank
One in the amount of approximately $43.0 million, of which approximately $30.6
million was borrowed in January 1999.  In addition, the Company entered into an
agreement (the "Formation Agreement") with Calpine Corporation ("Calpine") and
CPN Production Company ("CPN"), each unaffiliated parties, pursuant to which
SCEI was created to acquire and own the California Properties.  CPN contributed
$14.9 million in cash and received $13.0 million in seven-year redeemable non-
voting preferred stock of SCEI (the "SCEI Preferred Stock") and 20% of the
outstanding common stock of SCEI.  In certain circumstances, the Company may be
entitled to acquire the common stock held by CPN.  The Company contributed $3.0
million in cash and $4.6 million of seismic data and oil and gas producing
assets in California and received 80% of the outstanding common stock of SCEI.

                                       46
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Pro Forma Acquisition Information (Unaudited)

     The net cost of the Amerada Transaction properties was approximately $55.2
million including direct costs of the acquisition of approximately $1.7 million.
The acquisition will be accounted for by the purchase method.  Accordingly, the
results of operations of the acquired properties will be included with those of
the Company for periods subsequent to the date of acquisition.  Had the Amerada
Transaction been consummated as of January 1, 1998, the impact would have been
an increase in total revenues of $13.9 million and an increase in net income of
$1.6 million.

     The unaudited pro forma combined condensed balance sheet of the Company and
the Amerada Transaction as of December 31, 1998 after giving effect to certain
pro forma adjustments is as follows (in thousands):

                       ASSETS
 
Current assets                                           $  8,099
Property and equipment, net                               111,128
Other assets                                                2,250
                                                         --------
                                                         $121,477
                                                         ========
       LIABILITIES AND SHAREHOLDERS' EQUITY
 
Current liabilities                                      $ 15,868
Long-term debt                                             69,650
Redeemable preferred stock                                 23,675
Minority interest                                           1,900
Shareholders' equity                                       10,384
                                                         --------
                                                         $121,477
                                                         ========

     The following table summarizes certain pro forma condensed consolidated
results of operations data that give effect to the Amerada Transaction as if
such had occurred on January 1, 1998 including pro forma adjustments for
financing costs and associated preferred share dividends:

Total Revenues                                           $ 33,684
                                                         ========
Net loss applicable to common stock                      $(10,417)
                                                         ========
Net loss per common share - basic and diluted            $  (1.55)
                                                         ========

                                       47
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


19.    INFORMATION ON OIL AND GAS ACTIVITIES

       Following are supplemental disclosures relating to the Company's oil and
natural gas exploration and production activities.

Oil and Gas Related Costs and Operating Results

       The following schedules present capitalized costs and costs incurred,
whether capitalized or expensed, and operating results for the periods then
ended.
<TABLE>
<CAPTION>
                                                                1998          1997
                                                                ----          ----
                                                                 (IN THOUSANDS)
<S>                                                       <C>             <C>
Capitalized costs:
 Unproved properties                                           $  3,896        $   229
 Proved properties                                               71,435         69,911
 Accumulated depletion and depreciation and impairment          (20,118)        (7,537)
                                                               --------        -------
                                                               $ 55,213        $62,603
                                                               ========        =======
Costs incurred:
 Acquisition properties:
  Unproved                                                     $  2,623        $   229
  Proved                                                          6,156         52,293
 Exploration                                                      1,100          1,067
 Development                                                      6,941          1,304
                                                               --------        -------
                                                               $ 16,820        $54,893
                                                               ========        ======= 
Operating results(1):
Revenues                                                       $ 17,901        $ 7,074
Costs and expenses:
  Production costs                                                6,957          2,638
  Exploration costs                                                 931            484
  Depletion and depreciation expense and
   impairment provision(2)                                       13,301          2,563
                                                               --------        -------
                                                                 21,189          5,685
                                                               --------        -------
  Operating income (loss) before income taxes                    (3,288)         1,389
  Income tax expense (benefit)                                       --             --
                                                               --------        -------
  Operating earnings (loss)                                    $ (3,288)       $ 1,389
                                                               ========        =======
</TABLE>
----------------

(1)  Excludes general and administrative and interest expense
(2)  1998 includes impairment provision of $3,244.

                                       48
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Proved Reserves (Unaudited)

     The following schedule presents estimates of proved oil and natural gas
reserves attributable to the Company, all of which are located in the United
States. Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. Reserves are stated in thousands of barrels of oil and Bcf of natural
gas.

<TABLE>
<CAPTION>
                                                  1998                           1997
                                        ----------------------          ----------------------
                                          OIL             GAS             OIL             GAS
                                        ------          ------          ------          ------
<S>                                    <C>             <C>             <C>             <C>
Proved reserves:
     Beginning of year                   2,238            64.8             981            15.8
     Sales of reserves-in-place           (340)          (12.4)             --            (0.1)
     Purchase of reserves-in-place         171             5.3           1,322            46.8
     Extensions and discoveries             39             8.1              68             4.3
     Revisions of previous estimates      (359)           (2.7)            (40)            0.2
     Production                           (202)           (7.2)            (93)           (2.2)
                                        ------          ------          ------          ------
     End of Year                         1,547            55.9           2,238            64.8
                                        ======          ======          ======          ======
Proved developed reserves                1,253            46.0           1,514            55.3
                                        ======          ======          ======          ======
</TABLE>

     Estimating economically recoverable crude oil and natural gas reserves and
the future net revenues therefrom is not an exact science.  It is based upon a
number of variables such as historical production of the subject properties, as
compared with similar producing properties, and assumptions, such as the effects
of Company regulation by governmental agencies, future taxes, and development
and other costs, all of which may vary considerably from actual results.  All
such estimates are to some degree speculative, and classifications of reserves
are only attempts to define the degree of speculation involved. For these
reasons, estimates of economically recoverable reserves of crude oil and natural
gas attributable to any particular group of properties, the classification and
risk of recovering such reserves, and estimates of the future net revenues
expected therefrom, prepared by different engineers or by the same engineers at
different times, may vary substantially.

     Proved oil and natural gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions.  Estimates
with respect to proved undeveloped and proved developed non-producing reserves
that may be developed and produced in the future are based upon volumetric
calculations or upon analogy to similar types of reservoirs.  Later studies of
the same reservoirs based upon production history may result in variations,
which may be substantial.  The actual production, revenues, severance and excise
taxes, development costs, and operating expenditures with respect to the
Company's reserves as reflected herein may vary from estimates, and such
variances may be material.

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

     The following schedules present the standardized measure of estimated
discounted future net cash flows attributable to the Company's proved oil and
gas reserves ("Standardized Measure"), and an analysis of the changes in these
amounts and quantities for the periods indicated.  The Standardized Measure was
computed on the basis of (a) contractual prices, including escalations for
natural gas, in effect at year end for oil and natural gas (b) the market price
for natural gas and the posted price for oil in effect at year end for the area
in the case of properties being commercially 

                                       49
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


developed but not covered by existing contracts, (c) estimated deliverability,
which not only considers the physical characteristics of the well or property,
but also the amount and timing of future production estimated to be taken by its
purchasers, and (d) where applicable, the premise that future prices and
deliveries will be in accordance with existing contractual terms which may
require arbitration or litigation to ultimately assure compliance. Estimated
future production and development costs are based on economic conditions at the
respective year ends. Estimated future development costs associated with proved
developed non-producing and proved undeveloped reserves were $8.7 million for
1998 and $11.9 million for 1997. Production of those reserves is dependent upon
the Company's ability to fund such future development costs, which are scheduled
to be incurred over a number of years. Future income taxes, if any, are computed
by applying statutory income tax rates to the difference between the future pre-
tax cash flows and the tax basis of proved oil and gas properties, after
considering investment tax credits and depletion carry-forwards and net
operating loss carryovers associated with these properties.

     Since the Standardized Measure was prepared using the prevailing economic
conditions existing at each applicable year end, it is emphasized that such
conditions continually change, as evidenced by the fluctuations in oil and
natural gas prices during recent years.  Weighted average year-end oil and
natural gas prices per barrel and Mcf utilized in computing the Standardized
Measure for 1998 were $9.91 and $2.18, respectively, and for 1997 were $16.54
and $2.51, respectively.  Accordingly, such information should not serve as a
basis in making any judgment on the potential value of the Company's recoverable
reserves, or in estimating future results of operations.
<TABLE>
<CAPTION>
                                                              1998          1997
                                                            --------      --------
                                                               (in thousands)
Future net cash flows:
<S>                                                       <C>           <C>
     Future revenues                                        $138,506      $203,740
                                                            --------      --------
     Future production costs                                  48,285        67,136
     Future development costs                                  8,724        11,938
                                                            --------      --------
                                                              57,009        79,074
                                                            --------      --------
     Future pre-tax cash flows                                81,497       124,666
     Future income taxes                                      (4,272)      (25,288)
                                                            --------      --------
     Future net cash flows                                    77,225        99,378
     10% discount factor                                     (27,751)      (41,240)
                                                            --------      --------
Standardized Measure of future net cash flows
 discounted   at 10%                                        $ 49,474      $ 58,138
                                                            ========      ======== 
 
Changes in Standardized Measure:
     Standardized Measure, beginning of year                $ 58,138      $ 27,244
                                                            --------      --------
     Purchases of reserves-in-place                            5,738        49,470
     Extensions and discoveries                                8,239         5,171
     Revisions of previous quantity estimates                 (3,512)          456
     Changes in future development costs                       2,605        (1,392)
     Development costs incurred during the period that
          reduce future development costs                      1,121            56
     Net changes in prices and production costs              (15,424)      (10,869)
     Sales of oil and natural gas produced, net of           (10,944)       (4,436)
      production costs
     Net change in income taxes                               13,226       (12,224)
     Accretion of discount                                     5,814         2,707
     Sales of reserves-in-place                              (13,098)         (179)
     Changes in production rates and other, net               (2,429)        2,134
                                                            --------      --------
     Net increase (decrease)                                  (8,664)       30,894
                                                            --------      --------
     Standardized Measure, end of year                      $ 49,474      $ 58,138
                                                            ========      ========
</TABLE>

                                       50
<PAGE>
 
                     SHERIDAN ENERGY, INC. AND SUBSIDIARY

           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

     Included in 1998 Standardized Measure is $1.3 million representing the
estimated value of the Company's natural gas swap agreements outstanding as of
December 31, 1998.  The impact of the Company's 1997 natural gas and crude oil
hedges on the Standardized Measure was not material.

     Since year end 1998, natural gas prices have declined while oil prices have
increased.  At March 22, 1999, the NYMEX price for natural gas, on an Mcf basis,
was approximately $1.91 and the per barrel posted price for West Texas
Intermediate oil was $13.00.

                                       51
<PAGE>
 
ITEM 8.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
          FINANCIAL DISCLOSURE

     During 1998, there were no disagreements with the Company's independent
accountants regarding accounting or financial disclosure matters.


                                   PART III

ITEM 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
          COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

     The information regarding Directors and Executive Officers of the
Registrant as required by Items 401 and 405 of Regulation S-B is set forth under
the caption "Election of Directors" in the Company's definitive Proxy Statement
(the "Proxy Statement") for the Company's 1999 annual meeting of stockholders
which will be filed with the Securities and Exchange Commission not later than
120 days after December 31, 1998, and is hereby incorporated by this reference.


ITEM 10.  EXECUTIVE COMPENSATION

     The information required by Item 402 of Regulation S-B is set forth under
the captions "Compensation of Executive Officers," "Compensation Committee of
the Board of Directors Report on Executive Compensation," and "Compensation
Committee Interlocks and Insider Participation" in the Proxy Statement, and is
hereby incorporated by this reference.


ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     The information required by Item 403 of Regulation S-B is set forth under
the captions "Security Ownership of Management" and "Security Ownership of
Certain Other Stockholders" in the Proxy Statement, and is hereby incorporated
by this reference.


ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information regarding certain relationships and related transactions as
required by Item 404 of Regulation S-B is set forth in the Proxy Statement under
the captions "Compensation of Executive Officers" and "Related Transactions" and
is hereby incorporated by this reference.


ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K
<TABLE> 
<CAPTION> 
<S>                 <C>   
1.   Exhibits:

     Exhibit  2.1    Amended Plan of Reorganization and Disclosure Statement as
                     revised and filed by TGX, as debtor-in-possession, on January
                     7, 1992. (Incorporated by reference to Exhibit 2.1 of TGX's
                     Current Report on Form 8-K dated February 4, 1992, File  No.
                     1-10201.)
 
     Exhibit  2.2    Order Confirming Amended Plan of Reorganization dated January
                     7, 1992. (Incorporated by reference to Exhibit 2.2 of TGX's
                     Current Report on Form 8-K dated February 4, 1992, File No.
                     1-10201.)
</TABLE> 

                                       52
<PAGE>
 
<TABLE> 
<CAPTION> 
<S>                 <C>  
     Exhibit  2.3    Agreement of Merger between the Company and TGX (Incorporated
                     by reference to Exhibit 2.1 to the Registrant's Registration
                     Statement No. 333-10729, and all amendments thereto).
 
     Exhibit  3.1    Certificate of Incorporation of the Company. (Incorporated by
                     reference to Exhibit 3.1 to the Registrant's Registration
                     Statement No. 333-10729 and all amendments thereto).
 
     Exhibit  3.2    Amended and Restated By-Laws of the Company. (Incorporated by
                     reference to Exhibit 3.2 to the Registrant's Registration
                     Statement No. 333-10729).
 
     Exhibit  4.1    Specimen Certificate representing shares of Common Stock
                     (Incorporated by reference to Exhibit 4 to the Registrant's
                     Registration Statement No. 333-10729).

     Exhibit 4.2     Designation of the Preferences relating to the Sheridan
                     Preferred Stock. (Incorporated by reference to Exhibit 4.2 
                     of Form 10-KSB for the year ended December 31, 1997.)           

     Exhibit 4.3     Specimen Certificate representing shares of the Registrant's
                     Preferred Stock.  (Incorporated by reference to Exhibit 4.3 
                     of Form 10-KSB for the year ended December 31, 1997.)           

     Exhibit 4.4     Certificate of Designation of Series NA Preferred Stock of
                     Sheridan California Energy, Inc. (Incorporated by reference to
                     Exhibit 4.4 to the Registrant's Report on Form 8-K dated
                     January 25, 1999).

     Exhibit 10.1    Amended and Restated Credit Agreement effective as of February
                     1, 1992 between TGX and the Bank of Montreal and the First
                     Amendment thereto.  (Incorporated by reference to Exhibit 10.1
                     of TGX's Annual Report on Form 10-K for the year ended
                     December 31, 1991, File No. 0-10201).

     Exhibit 10.2    Amended and Restated Security Agreement effective as of
                     February 1, 1992 between TGX and the Bank of Montreal.
                     (Incorporated by reference to Exhibit 10.2 of TGX's Annual
                     Report on Form 10-K for the year ended December 31, 1991, File
                     No. 0-10201).
 
     Exhibit 10.3    Amended and Restated Security Agreement (Partnerships)
                     effective as of February 1, 1992 between TGX and the Bank of
                     Montreal.  (Incorporated by reference to Exhibit 10.3 of TGX's
                     Annual Report on Form 10-K for the year ended December 31,
                     1991, File No. 0-10201).

     Exhibit 10.4    Amendment and Restated Stock Pledge Agreement effective as of
                     February 1, 1992 between TGX and the Bank of Montreal.
                     (Incorporated by reference to Exhibit 10.4 of TGX's Annual
                     Report on Form 10-K for the year ended December 31, 1991, File
                     No. 0-10201).

     Exhibit 10.5    Amended and Restated Pledge of Secured Notes effective as of
                     February 1, 1992 between TGX and the Bank of Montreal.
                     (Incorporated by reference to Exhibit 10.5 of TGX's Annual
                     Report on Form 10-K for the year ended December 31, 1991, File
                     No. 0-10201).

     Exhibit 10.6    Purchase and Sale Agreement between TGX and Belden and Blake
                     Corporation dated as of December 17, 1993 (Incorporated by
                     reference to Exhibit C of Form 8-K dated January 14, 1994 of
                     TGX File No. 0-10201).

     Exhibit 10.7    Limited Forbearance Agreement between TGX and Bank of Montreal
                     dated as of January 10, 1994 (Incorporated by reference to
                     Exhibit C of Form 8-K of TGX dated January 14, 1994, File No.
                     0-10201).
</TABLE> 

                                       53
<PAGE>
 
<TABLE> 
<CAPTION> 
<S>                 <C>  
     Exhibit 10.8    Second Amended and Restated Credit Agreement between the
                     Company and BMO Financial, Inc. dated as of July 13, 1994
                     (Incorporated by reference to Exhibit 10.1 of TGX's Form 8-K
                     dated July 13, 1994).

     Exhibit 10.9    Amended and Restated Credit Agreement between the Company and
                     Bank One, Texas, N.A. dated as of July 13, 1994 (Incorporated
                     by reference to Exhibit 10.4 of the Registrant's report on
                     Form 8-K dated July 13, 1994).

     Exhibit 10.10   First Amendment to Second Amended and Restated Credit
                     Agreement dated as of December 31, 1995.  (Incorporated by
                     reference to Exhibit 10.25 of TGX's Form 10-K for the year
                     ended December 31, 1995, File No. 0-10201).

     Exhibit 10.11   Settlement Agreement among TGX, National Fuel Gas Distribution
                     Company, and the New York Public Service Commission dated as
                     of April 12, 1996.  (Incorporated by reference to Exhibit C of
                     TGX's Form 8-K dated April 30, 1996, File No. 0-10201).

     Exhibit 10.12   Third Amendment to Amended and Restated Credit Agreement
                     between Sheridan Corporation and Bank One, Texas, N.A.
                     effective as of October 1, 1996.  (Incorporated by reference
                     to Exhibit 10.27 of Form 10-KSB for the year ended December
                     31, 1996, File No. 0-10201).

     Exhibit 10.13   Settlement, Release and Confidentiality Agreement between the
                     Company and Larry H. Carpenter dated as of March 31, 1997.
                     (Incorporated by reference to Exhibit 10.28 of Form 10-KSB for
                     the year ended December 31, 1996, File No. 0-10201).

     Exhibit 10.14   1997 Flexible Incentive Plan (Incorporated by reference to
                     Appendix "F" of the Registration Statement No. 333-10729, and
                     all amendments thereto).

     Exhibit 10.15   Employment Agreement dated June 5, 1997 between the Company
                     and B.A. Berilgen (Incorporated by reference to Exhibit 10.29
                     of the Company's Form 10-KSB filed August 14, 1997).

     Exhibit 10.16   Acquisition Agreement dated November 13, 1997, between the
                     Company and Pioneer Natural Resources USA, Inc. (Incorporated
                     by reference to Exhibit 10-1 of the Company's Form 8-K filed
                     December 2, 1997).

     Exhibit 10.17   Agreement between the Company and ECT relating to the sale of
                     shares of the Company's Common Stock and Preferred Stock,
                     dated November 28, 1997 (Incorporated by reference to Exhibit
                     10.1 of the Company's Form 8-K filed December 2, 1997).

     Exhibit 10.18   Grand Gulf Acquisition Agreement dated as of December 31, 1997
                     (Incorporated by reference to Exhibit 10.1 of the Company's
                     Form 8-K filed on January 6, 1998).

     Exhibit 10.19   Shareholder Agreement among the Company, ECT et al.,
                     (Incorporated by reference to Exhibit 10.2 of the Company's
                     Form 8-K filed on December 2, 1997).

     Exhibit 10.20   Agreement for Purchase and Sale dated as of January 25, 1999
                     between Amerada Hess Corporation and the Company, as amended
                     (Incorporated by reference to Exhibit 10.1 of the Company's
                     Form 8-K dated January 25, 1999).
</TABLE> 

                                       54
<PAGE>
 
<TABLE> 
<CAPTION> 
<S>                 <C>  
     Exhibit 10.21   Agreement regarding formation of corporation by and among the
                     Company, SCEI, Calpine Corporation and CPN Production Company
                     (Incorporated by reference to Exhibit 10.2 of the Company's
                     Form 8-K dated January 25, 1999).

     Exhibit 10.22   Credit Agreement dated as of January 21, 1999 among SCEI, Bank
                     One, as Agent for itself and as a lender and the lenders from
                     time to time a part thereto (Incorporated by reference to
                     Exhibit 10.3 of the Company's Form 8-K dated January 25, 1999).

     Exhibit 10.23   Gas Purchase and Sale Agreement between SCEI and Calpine Fuels
                     Company Incorporated by reference to Exhibit 10.4 of the
                     Company's Form 8-K dated January 25, 1999).

     Exhibit 18      Letter regarding Change in Accounting Principles.
                     (Incorporated by reference to Exhibit 18 of Form 10-K for the
                     year ended December 31, 1992, File No. 0-10201).

     Exhibit 23      Consent of PricewaterhouseCoopers LLP - filed herewith.

     Exhibit 24      Power of Attorney - filed herewith.

     Exhibit 27      Financial Data Schedule - filed herewith.
</TABLE> 
          (b) Reports on Form 8-K for the quarter ended December 31, 1998:

          (i)  a)   On November 9, 1998, the Company reported on Item 5
                    concerning information on the Amerada Transaction;

               b)   On January 25, 1999, the Company reported on Form 8-K, Item
                    2, the completion of the Amerada Transaction.

                                       55
<PAGE>
 
                                  SIGNATURES

     In accordance with Section 13 or 15(d) of the Securities Exchange Act of
1934, the Registrant caused this Report to be signed on its behalf by the
undersigned thereunto duly authorized, on March 30, 1999.

                         SHERIDAN ENERGY, INC.
                         (Registrant)


                         By: /s/    B. A. BERILGEN
                             ---------------------
                              B. A. Berilgen
                              President

     In accordance with the Securities Exchange Act of 1934, this report has
been signed below by the following persons on behalf of the registrant and in
the capacities and on the dates indicated.

 Signature                           Title                        Date
 ---------                           -----                        ----
 By: /s/ B.A. BERILGEN         President, Chief              March 30, 1999
    -------------------------  Executive Officer and
 B. A. Berilgen                Director
 

 By: /s/ MICHAEL A. GERLICH    Vice President,               March 30, 1999
    -------------------------  Chief Financial Officer, 
 Michael A. Gerlich            Chief Accounting Officer and
                               Director
                               

* By: /s/ JONATHAN P. CARROLL  Director                      March 30, 1999
     -------------------------
 Jonathan P. Carroll


* By: /s/ W. CRAIG CHILDERS    Director                      March 30, 1999
     ------------------------
 W. Craig Childers


* By: /s/ D. BRADLEY DUNN      Director                      March 30, 1999
     ------------------------
 D. Bradley Dunn


* By: /s/ DAVID H. SCHEIBER    Director                      March 30, 1999
     ------------------------
 David H. Scheiber


* By: /s/ JEFFREY E. SUSSKIND  Director                      March 30, 1999
     ------------------------
 Jeffrey E. Susskind


* By: MICHAEL A. GERLICH                                     March 30, 1999
     ------------------------
 Michael A. Gerlich
 Attorney-in-fact

                                       56