<PAGE>   1
                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 10-K


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

                  For the Fiscal Year Ended December 31, 1996

                                       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: 0-26484

                              DLB OIL & GAS, INC.
             (Exact name of Registrant as specified in its charter)

                       OKLAHOMA                             73-1358299
            (State or other jurisdiction of              (I.R.S. Employer
            incorporation or organization)               Identification No.)

         1601 NORTHWEST EXPRESSWAY, SUITE 700               73118-1401
                OKLAHOMA CITY, OKLAHOMA                     (Zip Code)
       (Address of principal executive offices)


        Registrant's telephone number, including area code: 405-848-8808
        Securities registered pursuant to Section 12(b) of the Act: None
    Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK


    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 II of this Form 10-K or any
amendment to this Form 10-K.

    The aggregate market value of the voting stock held by non-affiliates of
the Registrant on March 26, 1997 was $29,962,968.

    The number of common shares, $.001 par value, of the Registrant outstanding
on March 26, 1997 was 12,975,000.

    Documents incorporated by reference: Proxy Statement of Registrant for the
Annual Meeting to be held on May 21, 1997 (to be filed within 120 days of the
close of the Registrant's fiscal year), which is incorporated into Part III of
this Form 10-K.

<PAGE>   2

                               TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                                       Page
<S>                                                                                                      <C>
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS......................................................    1

PART I   ............................................................................................    1
         Item 1.           Business..................................................................    1
         Item 2.           Properties................................................................   19
         Item 3            Legal Proceedings.........................................................   24
         Item 4.           Submission of Matters to a Vote of Security Holders.......................   25
         Item 4A.          Executive Officers of the Registrant......................................   25

PART II
         Item 5.           Market for Registrant's Common Stock and Related
                           Shareholder Matters.......................................................   27
         Item 6.           Selected Financial Data...................................................   27
         Item 7.           Management's Discussion and Analysis of Financial
                           Condition and Result of Operations........................................   30
         Item 8.           Financial Statements and Supplementary Data...............................   40
         Item 9.           Changes in and Disagreements with Accountants on
                           Accounting and Financial Disclosure.......................................   40

PART III ............................................................................................   40
         Item 10.          Directors and Executive Officers of the Registrant........................   40
         Item 11.          Executive Compensation....................................................   40
         Item 12.          Security Ownership of Certain Beneficial Owners
                           and Management............................................................   40
         Item 13.          Certain Relationships and Related Transactions............................   40

PART IV
         Item 14.          Exhibits, Financial Statement Schedules and Reports
                           on Form 8-K...............................................................   40


                           Signature Page............................................................   42
                           Exhibit Index.............................................................   43
                           Index to Consolidated Financial Statements................................  F-1
</TABLE>

    As used in this report, "Bbl" means barrel, "MBbls" means thousand barrels,
"MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" mean
million cubic feet, "Bcf" means billion cubic feet, "BOE" means barrel of oil
equivalent determined using a ratio of six Mcf of gas for each Bbl of oil,
"MBOE" means thousand barrels of oil equivalent, and "MMBOE" means million
barrels of oil equivalent.



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                DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

         This Form 10-K includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act and Section 21E of the Securities
Exchange Act of 1934 (the "Exchange Act"). All statements, other than
statements of historical facts, included in this From 10-K that address
activities, events or developments that the Company expects or anticipates will
or may occur in the future, including such things as estimated future net
revenues from oil and gas reserves and the present value thereof, future
capital expenditures (including the amount and nature thereof), business
strategy and measures to implement strategy, competitive strengths, goals,
expansion and growth of the Company's business and operations, plans,
references to future success, references to intentions as to future matters and
other such matters are forward-looking statements. These statements are based
on certain assumptions and analyses made by the Company in light of its
experience and its perception of historical trends, current conditions and
expected future developments as well as other factors it believes are
appropriate in the circumstances. However, whether actual results and
developments will conform with the Company's expectations and predictions is
subject to a number of risks and uncertainties; general economic, market or
business conditions; the opportunities (or lack thereof) that may be presented
to and pursued by the Company; competitive actions by other oil and gas
companies; changes in laws or regulations; and other factors, many of which are
beyond the control of the Company. Consequently, all of the forward-looking
statements made in this Form 10-K are qualified by these cautionary statements
and there can be no assurance that the actual results or developments
anticipated by the Company will be realized or, even if substantially realized,
that they will have the expected consequences to or effects on the Company or
its business or operations. All subsequent written or oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by such continuing statements.


                                     PART I


ITEM 1.  BUSINESS

         DLB Oil & Gas, Inc. ("DLB" or the "Company") is an independent energy
company engaged primarily in the exploration, development, production and
acquisition of oil and gas properties in the Mid-Continent region and the
coastal and shallow onshore regions of south Louisiana, two of the most
prolific oil and gas producing regions in the United States. The Company's
principal producing fields are presently concentrated in Oklahoma. Since
commencing operations in 1991, the Company has experienced rapid and profitable
growth as a result of its strategic acquisitions and exploration and
development drilling programs. As of January 1, 1997, the Company had estimated
proved reserves of 20.1 MMBOE, which consisted of 6.7 MMBbls of oil and 80.4
Bcf of gas, with a present value of future net reserves of $204.8 million and a
reserve life of 9.7 years. On a BOE basis, 33% of the Company's estimated
proved reserves as of January 1, 1997 were oil and 67% were natural gas, and
72% of the Company's proved reserves were classified as proved developed. In
addition, through its wholly owned subsidiaries Bonray Drilling Company
("Bonray"), which was acquired in February 1997, and Gathering Energy Marketing
Company, LLC ("GEMCO"), the Company is engaged in the land contract drilling of
oil and gas wells and in the gathering, processing, transportation and
marketing of hydrocarbons, respectively.

         DLB places special emphasis on the application of advanced geological
technologies to areas it believes are undervalued and underanalyzed. As a
result of the Company's successful exploration and acquisition efforts,
including through the incorporation of these technologies, the Company's
estimated




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proved reserves, production, revenues and EBITDA (defined as earnings before
interest, taxes, depreciation and amortization) have increased in each of the
last six years. From 1991 through 1996, the Company achieved substantial growth
in each of the following areas:

         o Estimated proved reserves increased from 1.8 MMBOE to 20.1 MMBOE.

         o Production increased from 0.1 MMBOE to 1.6 MMBOE.

         o Revenues increased from $0.5 million to $28.4 million.

         o EBITDA increased from $0.8 million to $18.1 million.

         Management believes that the Company benefits from favorable operating
margins per BOE relative to its peers in the oil and gas industry. For the year
ended December 31, 1996, the Company received an average sales price of $17.02
per BOE produced and incurred lease operating expenses (inclusive of gross
production taxes), general and administrative expenses and interest expense of
$4.62, $1.56 and $0.99 per BOE produced, respectively, resulting in the Company
earning cash margin per BOE produced of $9.85. The Company believes that this
margin reflects the success of the Company's exploration strategy and operating
performance and has provided the Company with financial resources that it has
utilized in pursuing its business strategy.

BACKGROUND

         The Company was formed by Mike Liddell and Mark Liddell and commenced
operations in 1991. Prior to forming the Company, Mike Liddell and Mark Liddell
were the controlling shareholders and principal officers of DLB Energy
Corporation ("DLB Energy"). From 1980 through 1990, DLB Energy drilled over 240
wells for itself, Charles E. Davidson (DLB Energy's largest and most active
participant) and third party, non-industry participants. These wells were
primarily developmental wells located in the Mid-Continent area. DLB Energy
generated prospect locations and operated a majority of the completed wells.

         In December 1990, DLB Energy, Davidson and certain other third party
participants sold their oil and gas properties to Louis Dreyfus Natural Gas
Corp. for approximately $35.0 million, and DLB Energy discontinued
substantially all of its operations. Shortly after that sale, the Company
commenced operations and entered into a joint venture with Davidson to conduct
exploratory activities in the Mid-Continent area. Since then, DLB has been one
of the most active independent operators in the Mid-Continent area. Making
extensive use of technological advances in geological and geophysical
applications and utilizing a regional perspective in managing prospects and
related petroleum assets, DLB's approach has led to 23 new field discoveries in
the Mid-Continent area. DLB's activities have also involved the gathering,
processing, transportation and marketing of hydrocarbons, the acquisition of
mineral interests and secondary oil recovery.

         On July 20, 1995, in connection with its initial public offering, the
Company effected the Merger pursuant to which Davidson Oil & Gas Company, Inc.
was merged with and into DLB, the surviving corporation (the "Merger"). Unless
the context otherwise requires, the consolidated historical financial and other
business information presented in this Annual Report on Form 10-K give effect
to the Merger as if such event occurred as of January 1, 1991.

         The Company's principal executive offices are located at 1601
Northwest Expressway, Suite 700, Oklahoma City, Oklahoma 73118-1401, and its
telephone number at that location is (405) 848-8808.




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BUSINESS STRATEGY

         The Company's objective is to maximize shareholder value by seeking
growth in its reserves, production, cash flow and intrinsic value per share
through exploration and development activities as well as opportunistic
acquisitions. The Company's strategy to achieve this objective includes (i)
exploring and developing new oil and gas reserves, (ii) acquiring producing oil
and gas properties, (iii) utilizing advanced technology and experienced
explorationists and (iv) maximizing net margins per BOE.

         EXPLORING AND DEVELOPING NEW OIL AND GAS RESERVES. The Company seeks
to increase reserves and production on its properties and the properties it
acquires. Since 1991, the Company has made 23 new field discoveries, drilling
133 gross (71.95 net) exploration wells and 74 gross (31.61 net) development
wells with a success rate of 52% and 84%, respectively. Drilling efforts
replaced 331% of production in 1996. Development efforts include workovers and
recompletions of existing wells; the initiation of, or improvement to,
secondary recovery projects, particularly through the use of waterflooding; and
the drilling of lower risk development wells. The Company has budgeted $27.0
million for exploration and development activities in 1997.

         ACQUIRING PRODUCING OIL AND GAS PROPERTIES. The Company seeks to
acquire oil and gas properties through strategic business transactions that it
believes offer potential for increases in reserves, production and cash flow,
including transactions in which management believes the target is undervalued
or underutilized. In 1996, the Company acquired substantially all of the
Oklahoma oil and gas producing properties, mineral rights and leasehold acreage
of Amerada Hess Corporation, and in March 1997 the Company purchased an
undivided 50% interest in the West Cote Blanche Bay field and certain related
assets from Texaco Exploration and Production, Inc. ("Texaco"). See "--Recent
Events" and "--The Texaco Acquisition." As of January 1, 1997, estimated proved
reserves attributable to the properties acquired in these transactions were
21.6 MMBOE. In evaluating potential transactions, the Company utilizes the
expertise of its senior management, including the Company's Chairman of the
Board, Charles E. Davidson, who is also the managing partner of Wexford Capital
LLC,a diverse capital management firm managing over $1.5 billion of assets. The
Company and Wexford Capital LLC, on behalf of certain affiliated funds
(collectively, "Wexford"), are currently proponents of a joint plan of
reorganization for WRT Energy Corporation ("WRT Energy"). See "--Recent Events"
And "--WRT Energy."

         UTILIZING ADVANCED TECHNOLOGY AND EXPERIENCED EXPLORATIONISTS. The
Company seeks to acquire large amounts of geological and geophysical data to
which it applies advanced technology to analyze the data for potential target
areas. The information acquired by the Company includes geological studies and
3-D and high resolution 2-D seismic surveys. The Company currently owns
approximately 385 square miles of 3-D seismic data focused primarily in the
Mid-Continent region and in south Louisiana. Additionally, the Company's
proprietary data base contains approximately 42,000 linear miles of
conventional and high resolution 2-D seismic data and over 176,000 digitized
well logs, core samples, pressure tests, petrographic studies and reservoir
performance data. DLB believes that its use of this advanced technology to
analyze its extensive, region-specific data base leads to a more accurate and
detailed analysis of prospect opportunities than is available by using more
conventional techniques. In particular, the Company believes that the use of
these technologies facilitates the optimal placement of development wells, more
clearly identifies elements of prospect risk and aids in the prediction of
geological conditions and potential reserves, thereby lowering finding costs
and improving the economics of oil and gas exploration. The Company currently
utilizes 13 geologists and geophysicists. DLB believes that these scientists
are among the most experienced explorationists using advanced geological and
geophysical technology in these



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areas. In addition, the Company's explorationists are experienced in
conventional interpretive techniques, reflecting the Company's philosophy that
advanced geological and geophysical technology should extend, rather than
replace, conventional methodologies.

         MAXIMIZING NET MARGINS PER BOE. An important element of the Company's
business strategy is its concentrated regional approach to asset management. In
making capital allocation decisions, management focuses on the creation of core
operating areas in which DLB can achieve competitive advantages through
concentration of (i) geologic and geophysical data, which lead to greater
regional knowledge, (ii) production, which leads to beneficial marketing and
transportation arrangements, and (iii) operations, which lead to more efficient
use of general and administrative expenditures. In addition, DLB seeks to
control ancillary activities that can enhance net margins per BOE, such as the
marketing of its oil and gas as well as oil and gas of third parties and the
installation or purchase of gathering, processing and pipeline systems.

RECENT EVENTS

         Since the beginning of 1996, the Company has undertaken several
significant transactions that have increased, or are expected to increase, the
Company's reserves, production, cash flow and intrinsic value per share. These
transactions include the following:

          AMERADA HESS ACQUISITION. In a transaction completed in May 1996, DLB
purchased substantially all of the Oklahoma oil and gas producing properties,
mineral rights and leasehold acreage of Amerada Hess Corporation ("Amerada
Hess"), including ownership interests in 44 fields containing approximately
1,200 wellbores. In addition, the acquisition included approximately 11,000 net
acres of perpetual mineral rights, 15,100 miles of proprietary seismic data,
geologic and well data and interests in certain gas gathering and processing
assets. All of the assets are located in Oklahoma, the Company's historical
core operating area. The purchase price, as adjusted, was approximately $32.1
million. As of January 1997, estimated proved reserves associated with the
acquired properties represented 9.4 MMBOE, or 47% of the Company's total
estimated proved reserve base of 20.1 MMBOE.

          BONRAY ACQUISITION. In February 1997, the Company acquired Bonray in
a negotiated $12.7 million transaction involving a cash tender offer and
subsequent merger of Bonray with a wholly-owned subsidiary of the Company (the
"Bonray Acquisition"). As a result of the Bonray Acquisition, the Company
acquired 15 land drilling rigs, including six rigs capable of drilling wells
over 20,000 feet and nine rigs capable of drilling wells from 7,500 to 15,000
feet. Two of the six deep drilling rigs are presently being remobilized and are
expected to be in operation by the second quarter of 1997. Ten of the remaining
13 rigs were in service or available for service at the time of acquisition and
are currently employed in the Mid-Continent region, with three in stacked
status. The Company believes that the Bonray Acquisition is of significant
strategic importance to the Company because it (i) increases rig availability
for use in DLB's exploration and development program; (ii) gives DLB control of
rigs to allow it to hedge against increases in drilling costs, and (iii)
creates new growth opportunities for the Company, including the ability to
enter new core areas through joint ventures with companies requiring rig
availability to protect expiring leasehold positions. See Item 2.
"Properties--Contract Drilling Operations."

          TEXACO ACQUISITION. On March 11, 1997, the Company purchased from
Texaco an undivided 50% interest in approximately 4,600 producing acres in the
West Cote Blanche Bay field, which includes 53 producing and 343 shut-in wells
as well as certain related equipment and facilities and 3-D and 2-D seismic,
geophysical, geological and other technical data (the "Texaco Acquisition"). As
a result of the Texaco Acquisition, the Company is the operator of the field
which is located in the shallow onshore waters of south Louisiana, in Saint
Mary's Parish, Louisiana. The interest in the West Cote Blanche Bay




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field purchased by the Company from Texaco contained estimated proved reserves
of 12.2 MMBOE as of January 1, 1997, all of which are oil and 71% of which are
classified as proved developed. As discussed below, the Company has agreed to
contribute the 50% interest in the West Cote Blanche Bay field and certain
related assets to WRT Energy as part of the joint reorganization plan proposed
for WRT Energy by the Company, Wexford and WRT Energy.

          WRT ENERGY. During 1996, the Company and Wexford acquired $34.3
million principal amount of WRT Energy debt securities and $2.2 million of
secured claims. The Company's share of the debt securities and liens was $21.5
million for which it paid $7.9 million. Subsequently, DLB and Wexford,
together with WRT Energy, proposed a joint plan of reorganization for WRT
Energy. WRT Energy is an independent energy company that owns and operates
mature oil and gas properties primarily in the Louisiana Gulf area. WRT Energy
has reported estimated proved reserves as of December 31, 1996 of 16.4 MMBOE as
determined by an independent engineering firm. In February 1996, WRT Energy
sought protection under Chapter 11 of the Federal Bankruptcy Code. Under the
plan of reorganization jointly proposed by the Company, Wexford and WRT Energy,
as currently proposed, among other things, the Company would contribute its 50%
interest in the West Cote Blanche Bay field and certain related assets to WRT
Energy, which owns the remaining 50% undivided interest, in exchange for an
additional equity interest in the post-bankruptcy WRT Energy, and the Company
and Wexford would own at least approximately 46% and 9%, respectively, of the
outstanding common stock of WRT Energy on the Effective Date as defined herein.
If the plan is approved, the Company believes that the resulting 100% operating
control of the West Cote Blanche Bay field, when combined with the Company's
management and technical expertise and WRT Energy's improved financial
condition, will facilitate the development of the property and lead to
increases in reserves, production and cash flow. See "--WRT Energy."

          BARBADOS TRANSACTION. On November 27, 1996, the Company purchased a
20.8% equity interest in Waggoner (Barbados) Ltd. ("WBL") and a promissory note
of WBL in the principal amount of $2.4 million payable to the Company, for
approximately $3.2 million. WBL has entered into a series of agreements with
the Barbados National Oil Company, Ltd. and one of its subsidiaries (together,
"BNOC"), relating to the exploration, development and production of the onshore
oil and gas reserves of Barbados by applying advanced technological methods.
Pursuant to the terms of these agreements, WBL will be entitled to 60% of the
profits from the joint venture, after the recovery of costs and subject to a
production bonus paid to BNOC and an overriding royalty of 3% of certain
revenues from sales. The 1997 drilling program approved by WBL and BNOC
includes 22 developmental wells, 60 advanced stimulation treatments, 35
recompletions and two horizontal wells. Operations are scheduled to begin
during the first quarter of 1997.

PRINCIPAL PRODUCING AREAS

         The following table presents information regarding the Company's
estimated proved reserves in its principal producing areas as of January 1,
1997 and the present value of future net reserves attributable thereto.




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<TABLE>
<CAPTION>
                                                                 NET PROVED RESERVES (1)
                                                      ------------------------------------------   PRESENT VALUE
                                                        OIL         GAS       TOTAL   PERCENTAGE    OF FUTURE
                                                      (MBBLS)      (MMCF)     (MBOE)   OF TOTAL    NET REVENUES (2)
                                                      --------   --------   --------   --------    --------------
PRODUCING AREA                                                                                     (IN THOUSANDS)
<S>                                                      <C>       <C>        <C>            <C>   <C>
Anadarko Basin and Shelf                                 2,691     55,771     11,986         60%   $      134,014
Golden Trend and Southern Oklahoma                       3,379     20,458      6,789         34%           57,764
All Other                                                  600      4,128      1,288          6%           12,985
                                                      ========   ========   ========   ========    ==============
      Total                                              6,670     80,357     20,063        100%   $      204,763
                                                      ========   ========   ========   ========    ==============
</TABLE>

-------------------

          (1)  Excludes estimated proved reserves of 12.2 MMBOE attributable to
               Texaco's 50% undivided interest in the West Cote Blanche Bay
               field which was acquired by the Company in March 1997.

          (2)  Present value of future net revenues is before income taxes and
               discounted at 10% per annum.

         MID-CONTINENT REGION. The Company's Mid-Continent producing properties
are primarily located in two geological areas: (i) the Anadarko Basin and Shelf
and (ii) the Golden Trend and Southern Oklahoma.

         Anadarko Basin and Shelf. The Anadarko Basin is a major Mid-Continent
oil and natural gas producing area in western Oklahoma and the Texas Panhandle.
The greatest concentration of oil fields occurs on the eastern flank of the
basin, with natural gas fields dominating the shelf to the west, the Texas
Panhandle area and the deep basin located in southwestern Oklahoma. Oil and
natural gas are produced in this area from depths of only a few hundred feet to
over 20,000 feet. The Company's wells in this area produce from depths between
6,000 and 16,000 feet. Since 1991, DLB has drilled 96 gross (37.08 net)
exploratory wells and 62 gross (25.22 net) development wells in the Anadarko
Basin and Shelf area and, as of March 1, 1997, held interests in 181,083 gross
(97,184 net) leasehold acres. As of the same date, DLB held interests in 433
gross (132.37 net) wells in this area, 136 gross (79.46 net) of which it
operated.

         Golden Trend and Southern Oklahoma. The Golden Trend and Southern
Oklahoma area is a highly faulted, geologically complex province that extends
across 11 counties in south-central Oklahoma. The Company's production in this
area is mainly from the Pennsylvanian Hoxbar, Deese, Simpson and Springer sands
and the Hunton and Viola carbonates. The Company's wells in this region produce
from depths ranging from 5,000 to 17,000 feet. Since 1991, DLB has drilled 11
gross (3.16 net) exploratory wells and 4 gross (.49 net) development wells in
the Golden Trend and Southern Oklahoma area and, as of March 1, 1997, held
interests in 72,222 gross (42,357 net) leasehold acres. As of the same date,
DLB held interests in 864 gross (136.6 net) wells in this area, 93 gross (68.55
net) of which it operated.

         DLB has over 42,000 miles of 2-D, and over 325 square miles of 3-D,
seismic data over significant portions of the Anadarko Basin and Shelf and
Golden Trend areas. The application of technology to these areas has resulted
in the Company experiencing success rates of 52% and 84% on exploratory and
development drilling, respectively, through 1996. These areas are serviced by
interstate pipelines and numerous intrastate pipelines and gathering facilities
providing the Company with multiple marketing options.

         LOUISIANA GULF COAST REGION (WEST COTE BLANCHE BAY). The Company's
strategic acquisition of Texaco's interest in the West Cote Blanche Bay field
established a new core area for the Company in the coastal onshore shallow
water region of Louisiana. The West Cote Blanche Bay field was discovered in




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1940 and lies approximately five miles off the coast of Louisiana in Saint
Mary's Parish in a shallow bay with water depths averaging seven to eight feet.
The Company's activities in this field are expected to focus on both shallow
development and deeper exploration drilling targets. The complexly faulted and
prolific salt dome dominated region possesses multiple proven reservoir
targets. The area is served by interstate pipelines and many intrastate
pipeline and gathering systems. The assignment of leasehold by Texaco was
limited to a depth of approximately 10,500 feet as defined by a geologic
marker. Texaco has retained all of its leasehold rights below this depth. See
"--Recent Events--Texaco Acquisition." The Company's net interest in the
Louisiana Gulf region would be increased by the completion of the proposed
transaction with WRT Energy, which has interests in 19 fields in southern
Louisiana. See "--WRT Energy."

AREAS OF FUTURE EXPLORATION AND DEVELOPMENT ACTIVITIES

         The Company has identified numerous exploratory prospects as a result
of its extensive regional mapping undertaken to identify potential new field
areas. In addition, the Company has developed a large inventory of development
projects. The Company has budgeted $27.0 million for exploration and
development costs in 1997. The Company expects that a significant amount of
these budgeted capital expenditures will be deployed in the areas described
below. However, the actual level of capital expenditures and the areas in which
they are expended is highly dependent upon the Company's success rate on these
projects and prevailing conditions in the oil and gas industry. Accordingly,
the actual level of capital expenditures and areas of exploration and
development activity may vary materially from those described herein. See Item
7. "Management's Discussion and Analysis of Financial Condition and Result of
Operations."

         PROJECTS IN THE MID-CONTINENT REGION - ANADARKO BASIN AND SHELF

         Sheridan - Hunton. DLB geoscientists have completed a 3,000 square
mile regional study of the Hunton formation in the Anadarko Basin and the
Anadarko Shelf. The Hunton formation is one of the most prolific natural gas
reservoirs in the region. Exploratory wells drilled to the Hunton, in the study
area, have penetrated several other potentially productive zones including the
Red Fork, Chester and Mississippi. Total depths for planned Hunton exploratory
tests range from approximately 7,500 to 11,000 feet. Management has approved
the drilling of three wildcat wells in 1997 based on the regional geological
study and interpretation of 20 miles of proprietary high resolution 2-D seismic
data.

         South Elk City. The Company has also completed an evaluation of over
6,000 miles of 2-D seismic data located in the deep Anadarko Basin and intends
to participate in the drilling of a 13,000 foot Atoka Wash exploratory well.
The Atoka Wash is being actively developed to the east of the Company's acreage
position with recent completions averaging 3,000 Mcf of gas per day. Additional
potential pay zones to be tested include the Des Moinesian Wash and Springer
formations.

         Sahara. In 1995, DLB discovered and is now developing the Sahara area
which produces from the Tonkawa and Chester formations located at depths of
approximately 5,000 to 6,000 feet, respectively. Through December 31, 1996, the
Company successfully completed 19 of 20 of its wells in this area. Based on its
success in this area, DLB conducted a regional study of these productive
formations over a 750 square mile area and leased over 15,000 net leasehold
acres. Current plans contemplate the drilling of ten exploratory wells based on
this study with the objective of enhancing the economics of the area.
Additional potential pay zones to be tested by these exploratory wells include
the Cottage Grove, Oswega and Mississippi formations.





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         South Peek. Discovered in 1967, the South Peek field has produced over
100 Bcf of gas and 1.0 MMBbl of oil primarily from the Tonkawa formation at a
depth of 8,400 feet. DLB operates 16 wells in the field and has non-operated
interests in ten more. Average daily production from the field, net to DLB's
interest, was approximately 1,200 Mcf of gas per day during the first quarter
of 1997 (through March 20, 1997). In 1996, DLB drilled three exploratory wells
in the field, and DLB controls at least 74% of the working interest in each of
these wells. All of the wells were drilled to the Cottage Grove formation, a
deeper zone known to be productive in the area. The result of these efforts
yielded a new field discovery in the Cottage Grove from two of the wells which
tested at initial rates of approximately 230 barrels of oil and 100 Mcf of gas
per day and 100 barrels of oil and 100 Mcf of gas per day, respectively. All of
the wells had productive Tonkawa pay. DLB plans to continue its development of
this field and intends to drill at least six wells in 1997. Potential future
development drilling could include eight additional new wells. The field also
has further exploratory potential including the Lower Pennsylvanian Red Fork
and Morrow sandstones and the Hunton limestone.

         PROJECTS IN THE MID-CONTINENT REGION - GOLDEN TREND AND SOUTHERN
         OKLAHOMA

         Sholem Alechem Anticline. This field, discovered in 1927, produces gas
from multiple pays from the Pennsylvanian through the Ordovician formations.
Current exploratory efforts are centered on horizontal drilling of the Sycamore
and McClish formations located at true vertical depths of approximately 7,500
and 10,000 feet, respectively. There are presently approximately 12 proposed
horizontal drilling locations in these reservoirs. Total measured depths for
these wells are up to 15,000 feet. DLB owns working interests ranging from 1%
to 60% in these locations. The Company's capital budget contemplates that it
will participate in five horizontal wells in this field in 1997, three of which
it will operate.

         Cement Field - Springer. The Cement field covers approximately 53,000
acres and produces from over 35 different pay zones. Current exploratory work
in this field is centered on the Springer and Pre-Pennsylvanian carbonates
located at depths of over 15,000 and over 18,000 feet, respectively. The
Springer formation is being developed from east to west. The Company has
acreage positions in over 15 sections in this field including a significant
position on the west end of the field. See "--Cement West" below. A geologic
study, including the potential use of 3-D seismic, is in progress to determine
the optimum location for a 19,000 foot Springer exploratory well expected to be
drilled on this acreage block in 1997.

         Cement West. The Company's most concentrated acreage position in the
Cement field is located on the west end where it operates 11 wells in which it
controls in excess of 90% of the working interests. These wells have produced
nearly 50 Bcf of gas since 1956 from multiple reservoirs in the Middle
Pennsylvanian sandstones found at depths from 7,000 to 8,600 feet. Average
daily production for the first quarter of 1997 (through March 20, 1997), net to
DLB, from these wells is about 4,800 Mcf of gas per day. Production from this
field was approximately 1,500 Mcf of gas per day when DLB assumed operation at
mid-year. The Company executed a successful workover program and drilled three
gross (2.2 net) developmental wells in the field in late 1996 and early 1997 to
achieve these gains. DLB plans to drill two additional development wells and
perform four workovers in Cement West during the remainder of 1997.

         Dibble/Newcastle. The Dibble/Newcastle prospect consists of an area
covering approximately 6,000 acres. DLB controls approximately 4,000 net
leasehold acres in the area and in 1996 completed a 14 square mile 3-D seismic
shoot. In 1997, DLB completed two wildcat wells, the Givens 34-3 and the Kidd
13-4, in each of which it holds a 100% working interest. Initial flow rates for
the Givens 34-3 were 350 Mcf of gas per day and 115 barrels of oil per day.
The Kidd 13-4 is currently in the testing stage with




                                       8
<PAGE>   11


good shows of oil and gas. These wells are presently completed in the Hunton
and Viola formations and appear to have productive pay behind pipe in the Hart
and Osborne formations. The Company believes that potential development in this
prospect could reach 20 locations.

         Fitts. The Fitts field, discovered in 1933, covers in excess of seven
square miles and has cumulative production of over 45 MMBOE. This field is
being waterflooded from multiple zones, with the Cromwell, Hunton and Viola
formations exhibiting the best performance. Current production is approximately
3,500 barrels of oil per day (210 net to DLB). A proposed plan to drill 56
additional wells to increase sweep efficiency has been proposed to the unit
operator. If enacted, the infill drilling program is expected to significantly
increase the field's estimated proved reserves which at January 1, 1997 were
15.9 MMBOE (1.03 MMBOE net to DLB).

         LOUISIANA GULF REGION

         West Cote Blanche Bay. The West Cote Blanche Bay field, discovered in
1940, is an intermediate depth salt dome feature which covers approximately
nine square miles in area. This extremely faulted feature has produced oil from
over 80 hydrocarbon bearing sands. Productive formations range from 1,200 to
12,700 feet, although the Company only has an interest in the field down to
approximately 10,500 feet. Current production from the field (above 10,500
feet) is approximately 1,000 barrels of oil per day. In the Texaco Acquisition
completed in March 1997, the Company acquired 53 producing and 343 shut-in
wells, as well as related production and marketing facilities. DLB also
obtained seismic, geophysical, geological and other technical data, which
includes approximately 65 square miles of 3-D seismic data. See "--Texaco
Acquisition."

         BARBADOS

         On November 27, 1996, the Company purchased preferred stock
representing 20.8% of the total outstanding equity of WBL and a promissory note
of WBL in the original principal amount of approximately $2.4 million for an
aggregate purchase price of approximately $3.2 million. At such time as the
Company has received dividends, interest and principal equal to the sum of all
equity and debt contributions made by it, the preferred stock will be converted
into common stock of WBL.

         WBL has entered into a series of agreements with BNOC relating to the
exploration, development and production of the onshore oil and gas reserves of
Barbados by applying advanced technological methods. Pursuant to the terms of
these agreements, WBL will be entitled to 60% of the profits from the joint
venture, after the recovery of costs and subject to a production bonus paid to
BNOC and an overriding royalty of 3% of certain revenues from sales.

         WBL and BNOC jointly have the right to conduct activities for the
exploration, development and production of oil and gas on Barbados. WBL has
agreed to provide all of the financial and technical resources required and
BNOC has agreed to be responsible as operator for all such petroleum
operations. All of the petroleum operations will be managed by a committee
consisting of one representative appointed by WBL and one representative
appointed by BNOC, with BNOC's representative serving as chairman of the
Committee and both representatives being elected as members of the board of
directors of BNOC . In addition, the Company and each of the other equity
holders of WBL have jointly and severally guaranteed the performance by WBL of
its obligations under the agreements up to the



                                       9
<PAGE>   12


amount of funds committed but unpaid by WBL to the next date that WBL is
entitled to terminate the agreements.

         The agreements between WBL and BNOC establish exploration and
development plans for the island. The five phase exploration plan relates to
all of the onshore territory of Barbados that is above the low water line.
During Phase I (the first three years of the venture), WBL is obligated to
spend at least $1.0 million to drill and acquire data from at least one
exploratory well. During Phase II (the subsequent four year period), WBL is
obligated to spend at least $2.0 million to drill at least two additional
exploratory wells. In each of Phase III and Phase IV (each a subsequent four
year period), WBL is obligated to spend at least $2.0 million for exploration
activities. During Phase V (the subsequent ten year period), any proposals for
work and expenditures are subject to approval of the parties. The current
exploration plan calls for the drilling of two horizontal wells to test the
Scotland sands located from approximately 4,000 to 6,200 feet. Productive pay
sections from the two primary reservoirs found in existing production often
exceed 200 feet in thickness. Extreme faulting and thrusting has created areas
where these zones are dipping at 60 to 70 degrees making them excellent
candidates for horizontal wells. BNOC may terminate the agreement at the end of
Phase II if such phase expires without the establishment of a commercial
discovery. The venture has exclusive exploratory rights during Phase I and a
right of first refusal during Phase II through IV.

         The four phase development plan to enhance existing production of oil
and gas relates to 16,189 acres and is premised on application of advanced oil
field technology and more efficient operating practices to develop new reserves
and maximize production and net margins per barrel. WBL and BNOC Sub jointly
have the exclusive right to develop the area. Phase I of the development plan
(the first six months of the venture), requires development of an engineering
study and a plan of action. During Phase II (the remainder of the first three
years of the venture), WBL is obligated to spend at least $11.5 million ($8.0
million of which is to be spent during the first two years) in drilling 25 new
wells, performing 10 stimulations, reactivating 35 existing, inactive wells and
beginning a pressure maintenance program. During Phase III (the subsequent four
year period), WBL is obligated to spend at least $9.5 million in drilling 15
new wells, reactivating 15 existing inactive wells and performing a secondary
recovery program. During the last phase, WBL is obligated to spend at least
$2.0 million in each of the years eight to 15, $1.5 million in each of the
years 16 to 23 and $1.0 million in each of the years 24 and 25. If no
incremental production is achieved by the end of the first year, WBL may either
relinquish its rights and be relieved of its obligations or request an
extension for an additional year. If no incremental production is achieved by
the end of the second year, the right to perform these development activities
automatically terminates. The agreements provide that WBL will share in
production increases above current levels adjusted for normal declines.

TEXACO ACQUISITION

         On March 11, 1997, the Company and Texaco entered into that certain
Purchase, Sale and Cooperation Agreement (the "PS&C Agreement") pursuant to
which the Company purchased, among other things, (i) Texaco's 50% undivided
interest in the shallow contract area of the West Cote Blanche Bay field as
well as related facilities and seismic, geophysical, geological and other
technical data (the "WCBB Assets") for $12.3 million and (ii) certain
pre-petition claims against WRT Energy (the "Texaco Claim"), for approximately
$6.0 million. In addition, the Company assumed certain operational liabilities,
including Texaco's plugging and abandonment obligations related to the WCBB
Assets. In connection with these obligations, the Company (i) contributed $1.0
million to an escrow account (the "P&A Trust") established to satisfy the costs
of such plugging and abandonment obligations, (ii) agreed to contribute to the
P&A Trust approximately $18,000 per month for the next seven years and (iii)
granted to Texaco as security for the plugging and abandonment obligations, a
security interest (not to exceed $15.0 million) in (A) 50% of



                                      10
<PAGE>   13


the production from the shallow contract area of the West Cote Blanche Bay
field, as well as the proceeds therefrom, and (B) the Company's present and
future interest in the P&A Trust.

         The PS&C Agreement also provides that on the effective date of the WRT
Plan (the "Effective Date"), among other things, (i) the Company will transfer
the WCBB Assets to New WRT Energy, (defined herein) (ii) New WRT Energy will
transfer its interest in approximately 400 acres of non-producing land at West
Cote Blanche Bay and certain related facilities to the Company, which will in
turn transfer them to Texaco, (iii) New WRT Energy will issue to the Company
five million shares of common stock of New WRT Energy, plus the additional
number of shares of such common stock obtained by dividing the amount of
capital expenditures incurred by the Company as of the Effective Date as owner
of the WCBB Assets, to the extent not disapproved by the Bankruptcy Court by a
purchase price of $3.50 per share, (iv) the Company will receive common stock
of New WRT Energy for the Texaco Claim, and (v) New WRT Energy will assume all
liabilities, duties and obligations of the Company that arise, or may arise,
under the PS&C Agreement and related agreements. See "--WRT Energy" below for
additional information concerning WRT Energy and the WRT Plan.

WRT ENERGY

         WRT Energy is an independent energy company that owns and operates
mature oil and gas properties primarily in the Louisiana Gulf Coast area. On
February 14, 1996, WRT Energy commenced a voluntary reorganization case under
Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy
Court for the Western District of Louisiana, Lafaytte-Opelousa Division (the
"Bankruptcy Court"), Case No. 96BK-50212. After formal efforts were taken by
WRT Energy and its financial advisor to seek a restructuring partner, on or
about October 1996, WRT Energy's Board of Directors selected the joint
restructuring proposal of DLB and Wexford. In connection therewith, WRT Energy,
DLB and Wexford filed with the Bankruptcy Court (i) the Second Amended Joint
Plan Of Reorganization Under Chapter 11 of The United States Bankruptcy Code,
dated March 11, 1997 (the "WRT Plan") and (ii) the related Second Amended
Disclosure Statement, dated March 11, 1997 (the "Disclosure Statement").

         On March 11, 1997, the Bankruptcy Court, among other things, approved
the Disclosure Statement as containing adequate information to allow creditors
and equity interest holders to make informed judgments about voting for or
against the WRT Plan. Ballots were sent by WRT Energy to certain creditors and
equity interest holders entitled to vote to accept or reject the WRT Plan. To
be counted, such ballots must be returned by April 16, 1997.

         The WRT Plan sets forth the means by which creditors and equity
interest holders of WRT Energy will be treated. The hearing on confirmation of
the WRT Plan has been scheduled before the Bankruptcy Court for April 28, 1997.
The WRT Plan contemplates, among other things, (i) the issuance to WRT Energy's
unsecured creditors, on account of their allowed claims, of an aggregate of 10
million shares of the common stock of WRT Energy, as reorganized under the WRT
Plan ("New WRT Energy") and the right to purchase an additional 3.8 million
shares of the common stock of New WRT Energy at a purchase price of $3.50 per
share (the "Rights Offering") and (ii) the performance of certain transfers by
and between New WRT Energy and the Company pursuant to the PS&C Agreement on
the Effective Date. The WRT Plan also provides for a Board of Directors for the
New WRT Energy consisting of five members for the first three years following
the Effective Date, three of whom have been selected by DLB: Charles E.
Davidson, the Chairman of the Board of Directors of the Company, Mike Liddell,
the Chief Executive Officer of the Company, and Mark Liddell, the President of
the Company, and the two remaining directors to be selected by the Official
Committee of Unsecured Creditors appointed in the WRT Energy bankruptcy
proceeding. Under the WRT Plan, the officers of New WRT Energy will be:
Gary C. Hanna,



                                      11
<PAGE>   14


President (the Chief Operating Officer of the Company); Raymond P. Landry,
Executive Vice President; and Ronald D. Youtsey, Secretary and Treasurer (the
Chief Financial Officer of the Company).

         On the Effective Date, New WRT Energy will enter into an
Administrative Services Agreement pursuant to which the Company will provide,
among other things, certain administrative and related services to New WRT
Energy for a period of one year, subject to renewal. In addition, pursuant to a
commitment agreement by and among WRT Energy, the Company and Wexford, dated as
of January 20, 1997 (the "Commitment Agreement"), (a copy of which is attached
as Exhibit H to the Disclosure Statement), the Company and Wexford,
among other things, have agreed to perform the following (subject to the
conditions precedent set forth therein):

         (a)  The Company and Wexford, jointly and severally, agreed to
              subscribe for and purchase on the Effective Date from New WRT
              Energy, (i) their full pro rata share of the 3.8 million shares
              of common stock of New WRT Energy available in connection with
              the Rights Offering (approximately 1.14 million shares) and
              (ii) all of the remaining New WRT Energy common stock not
              otherwise purchased pursuant to the Rights Offering;

         (b)  The Company agreed to perform, on the Effective Date, those
              transactions contemplated by the provisions of the PS&C Agreement
              (see Exhibit N to the Disclosure Statement); and

         (c)  The Company and Wexford each agreed to (i) vote all claims held
              by them to accept the WRT Plan, and (ii) exercise any and all
              rights that they have under the WRT Plan on account of all claims
              held by them to elect to receive a distribution of common stock
              of New WRT Energy in lieu of a distribution of cash.

         As a consequence of the transactions contemplated by the WRT Plan and
the Commitment Agreement, upon the Effective date, among other things, New WRT
Energy will own 100% of the working interest in the shallow contract area of
the West Cote Blanche Bay field and will continue to conduct business and own
and operate the oil and gas properties of WRT Energy. In addition, it is
contemplated that DLB and Wexford, which collectively own approximately $34.3
million in aggregate principal face amount of 13 7/8% Senior Notes due 2002 of
WRT Energy out of an aggregate of $100 million principal face amount, the Texaco
Claim, and which acquired (through an entity affiliated with Wexford) certain
asserted lien claims against WRT Energy in the aggregate amount of
approximately $4.7 million, together will hold between approximately 56% and
68% of the common stock of New WRT Energy issued on the Effective Date by
virtue of the distributions to be made to DLB under the WRT Plan and in
consideration for the assets contributed by the Company to New WRT Energy
pursuant to the PS&C Agreement. The potential increase in share ownership
primarily reflects shares of common stock of New WRT Energy that DLB and
Wexford may purchase in the Rights Offering over and above their full pro rata
share. It is currently expected that the Company will own between 46% and 55%
of the outstanding common stock of New WRT Energy on the Effective Date, which
is projected to be on or about July 1, 1997.

         The above description is only a summary concerning WRT Energy and the
WRT Plan, and is qualified in its entirety by the more detailed discussions
provided in the Disclosure Statement and WRT Plan, copies of which are filed as
exhibits to this annual report. No assurances can be given that the WRT Plan
will be confirmed by the Bankruptcy Court or that the Effective Date will
occur.



                                      12
<PAGE>   15


OIL AND GAS MARKETING

         General. Revenues from DLB's oil and gas operations are highly
dependent on the prices of, and the demand for, oil and gas. Oil and gas
pricing depends on numerous factors beyond DLB's control, including seasonal
demand, political conditions in the predominant oil producing countries, the
actions of the Organization of Petroleum Exporting Countries, the health of the
domestic economy and Federal and state laws and regulations. Decreases in the
price of oil and gas will adversely affect the carrying value of DLB's proved
properties and its revenues, profitability and cash flow from operations.

         Oil Sales. In 1996, 1995 and 1994, oil sales accounted for 51%, 69%
and 66%, respectively, of the Company's oil and gas sales revenues. DLB sells
its oil production under short-term purchase contracts. Before 1994, these
contracts were based on field posted prices established by the purchasers
within the market area. The sales price was typically the field posted price,
plus an agreed premium, which price was adjusted for quality and gravity of the
oil sold. In February 1994, DLB began selling oil under contracts based on New
York Mercantile Exchange ("Merc") oil futures contract pricing rather than
field posted pricing. Under Merc pricing, the sales price is typically the
calendar month average Merc prompt month settle price, subject to an agreed
discount and adjusted for the quality and gravity of the oil sold. The Merc
prompt month settle price is the closing price during the trading month of
production. DLB has pursued Merc pricing because it believes the Merc market is
more efficient than the field posted market and offers DLB a better net price
for its product.

         During 1995, the Company began to market a portion of its oil through
its wholly-owned subsidiary, GEMCO. In 1996 and 1995, oil sales to Conoco, Inc.
("Conoco") accounted for approximately 35% and 46% of the Company's oil sales
revenues. During the same period, oil sales to Koch Oil Company ("Koch")
accounted for approximately 20% and 21% of the Company's oil sales revenues.
Both the Conoco contract and the Koch contract are based on Merc pricing. No
other single purchaser accounted for more than 10% of the Company's oil sales
revenues during such years. Since the oil purchase markets within the Company's
principal areas of production are highly competitive, the Company believes it
can replace any of its purchase contracts with other contracts on substantially
similar terms and without a significant disruption in oil sales revenues.

         Gas Sales. In 1996, 1995 and 1994, gas sales accounted for 49%, 31%
and 34%, respectively, of DLB's oil and gas sales revenues. The Company's gas
is sold under short-term contracts based on spot market pricing. During 1996
and 1995 Oneok Gas Marketing accounted for approximately 38% and 28%,
respectively, of the Company's gas sales. No other purchaser accounted for more
than 10% of the Company's gas sales revenues during such years. During 1996,
the Company began to market a portion of its gas through GEMCO, with pricing
based upon the appropriate posted index price.

         DLB may hedge its oil and gas sales through futures contracts from
time to time as it deems appropriate. Its futures contracts positions will be
primarily on a short-term basis. DLB does not intend to contract for positions
that it cannot offset against actual production.





                                      13
<PAGE>   16


COMPETITION

         The exploration and production business is highly competitive. In
seeking to obtain desirable new leases and exploration prospects, DLB faces
competition from both major and independent oil and gas companies. Many of
these competitors have financial and other resources substantially in excess of
those available to DLB and may, accordingly, be better positioned to take
advantage of industry opportunities and better able to withstand the effect of
changes in factors such as worldwide oil and gas prices and levels of
production, the availability of alternative energy sources and the application
of government regulations.

         Increases in worldwide energy production capability, decreases in
energy consumption as a result of conservation efforts and the continued
development of alternate energy sources have brought about substantial
surpluses in oil and gas supplies in recent years, resulting in substantial
competition for the marketing of oil and gas. As a result, there have been
reductions in oil and gas prices and delays in producing and marketing gas
after it is discovered. Changes in government regulations relating to the
production, transportation and marketing of gas have also resulted in
significant changes in the historical marketing patterns of the industry.
Generally, these changes have resulted in the abandonment by many pipeline
companies of long-term contracts for the purchase of gas, the development by
gas producers of their own marketing programs to take advantage of new
regulations requiring pipelines to transport gas for regulated fees and an
increasing tendency to rely on short-term sales contracts priced at spot market
prices.

REGULATION

         General. The oil and gas industry, and thus DLB's operations, are
extensively regulated by Federal, state and local authorities. Legislation
affecting the oil and gas industry is under continuous review and statutes are
constantly being adopted, expanded or amended. Numerous departments and
agencies, both Federal and state, have issued rules and regulations binding on
the oil and gas industry, some of which contain substantial penalties for the
failure to comply. The regulatory burden on the oil and gas industry increases
DLB's cost of doing business and consequently affects its profitability.
Because the laws, rules and regulations in this area are continuously changing,
DLB is unable to predict the future cost and impact of complying with them. DLB
does not believe, however, that it will be affected in a manner significantly
different than its competitors.

         Exploration and Production. Regulation of DLB's exploration,
production and related activities includes: requiring permits for the drilling
of wells; maintaining bonding and insurance requirements to drill or operate
wells; and requiring periodic reports about activities and regulating the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled, the plugging and
abandoning of wells and the disposal of fluids used in connection with
operations. DLB's operations are also subject to various conservation laws,
regulations and requirements. These include the regulation of the size and
shape of drilling and spacing units or proration units and the density of wells
which may be drilled and the unitization or pooling of oil and gas properties.
In this regard, some states, such as Oklahoma, allow the forced pooling or
integration of tracts to facilitate exploration, while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws
establish maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas and impose requirements regarding the
ratability of production. State statutes and regulations subject companies to
various judicial and administrative hearings to resolve issues between
producers, landowners, adjacent leaseholders, mineral interest owners and
non-operating working interest owners.

         Environmental Matters. DLB's operations and properties are subject to
extensive and changing Federal, state and local laws and regulations relating
to environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to



                                      14
<PAGE>   17


safety and health. The recent trend in environmental legislation and regulation
generally is toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction or drilling commences and for certain other
activities; restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with
exploration and production activities; limit or prohibit construction, drilling
and other activities on certain lands lying within wilderness or wetlands and
other protected areas; and impose substantial liabilities for pollution
resulting from DLB's operations. The permits required for various of DLB's
operations are subject to revocation, modification and renewal by issuing
authorities. DLB believes that its operations currently are in substantial
compliance with applicable environmental regulations.

         Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines or injunction, or both.
DLB has adopted programs that it believes are appropriate and does not expect
environmental compliance matters to have a material adverse effect on its
financial position. It is also not anticipated that DLB will be required in the
near future to expend amounts that are material to the financial condition or
operations of DLB by reason of environmental laws and regulations, but because
such laws and regulations are frequently changed, and may impose increasingly
stricter requirements, DLB is unable to predict the ultimate cost of complying
with such laws and regulations.

         In addition, it is not uncommon for landowners and other third parties
to make demands and to file lawsuits claiming personal injuries and property
damages allegedly caused by spills or other releases of solid wastes or
hazardous substances into the environment in oil and gas operations.

         The following are examples of environmental, safety and health laws
that potentially relate to DLB's operations:

                  Solid Waste. DLB's operations may generate and result in the
         transportation, treatment and disposal of both hazardous and
         nonhazardous solid wastes that are subject to the requirements of the
         Federal Resource Conservation and Recovery Act ("RCRA") and comparable
         state and local requirements. The Environmental Protection Agency
         ("EPA") is currently considering the adoption of stricter disposal
         standards for nonhazardous waste. Further, legislation has been
         proposed in Congress from time to time that would reclassify certain
         oil and gas wastes, including wastes generated during pipeline,
         drilling and production operations, as "hazardous wastes" under RCRA,
         which reclassification would make such solid wastes subject to much
         more stringent handling, transportation, storage, disposal and
         clean-up requirements. If such legislation were to be enacted, it
         could have a significant impact on DLB's operating costs, as well as
         the oil and gas industry in general. State initiatives to further
         regulate oil and gas wastes could have a similar impact.

                  Hazardous Substances. The Comprehensive Environmental
         Response, Compensation and Liability Act ("CERCLA") and comparable
         state statutes, also known as "Superfund" laws, impose joint and
         several liability, without regard to fault or the legality of the
         original conduct, on certain classes of persons for the release of a
         "hazardous substance" into the environment. These persons include the
         owner or operator of a site, and companies that transport, dispose of
         or arrange for the disposal of, the hazardous substances found at the
         site. CERCLA also authorizes the EPA, and in some cases, third parties
         to take actions in response to threats to the public health or the
         environment and to seek to recover from the classes of responsible
         persons the costs they incur. Although "petroleum" is currently
         excluded from CERCLA's definition of a "hazardous substance," in the
         course of its ordinary operations DLB may generate other materials
         which may fall within the definition of a "hazardous substance." DLB
         may be responsible under CERCLA for



                                      15
<PAGE>   18


         all or part of the costs required to clean up sites at which such
         wastes have been disposed and for natural resource damages. DLB has
         not received any notification that it may be potentially responsible
         for cleanup costs and liabilities under CERCLA or any comparable state
         law but it is possible that it could be named in the future.

                  Air. DLB's operations may be subject to the Clean Air Act
         ("CAA") and comparable state and local requirements. Amendments to the
         CAA were adopted in 1990 and contain provisions that may result in the
         gradual imposition of certain pollution control requirements with
         respect to air emissions from DLB's operations. The EPA has been
         developing regulations to implement these requirements. DLB may be
         required to incur certain capital expenditures in the next several
         years for air pollution control equipment in connection with
         maintaining or obtaining operating permits and approvals addressing
         other air emission-related issues. However, DLB does not believe its
         operations will be materially adversely affected by any such
         requirements.

                  Water. The Federal Water Pollution Control Act ("FWPCA")
         imposes restrictions and strict controls regarding the discharge of
         polluted waters and other oil and gas wastes into navigable waters.
         The FWPCA provides for civil, criminal and administrative penalties
         for any unauthorized discharges of oil and other hazardous substances
         in reportable quantities and, along with the Oil Pollution Act of
         1990, imposes substantial potential liability for the costs of
         removal, remediation and damages. State laws for the control of water
         pollution also provide varying civil, criminal and administrative
         penalties and liabilities in the case of a discharge of petroleum or
         its derivatives into state waters. Although future costs of compliance
         with water pollution requirements under federal or state law may be
         significant, the entire industry will experience similar costs and DLB
         believes that these costs will not have a material adverse impact on
         DLB's financial conditions and operations.

         Gas Sales and Transportation. The Federal Energy Regulatory Commission
("FERC") regulates the transportation and sale for resale of gas in interstate
commerce pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas
Policy Act of 1978 ("NGPA"). In the past, the Federal government has regulated
the prices at which oil and gas could be sold. Deregulation of wellhead sales
in the gas industry began with the enactment of the NGPA in 1978. Commencing in
1985, the FERC promulgated a series of orders (among others are Order Nos. 380,
436, 500, 528, 547 and, ultimately, 636) and regulations adopting changes that
significantly affect the transportation and marketing of gas. These changes
were intended to foster competition in interstate gas sales resulting in
market-driven pricing and open and accessible transportation. Similar efforts
have been made with respect to intrastate gas sales. In 1989, Congress enacted
the Natural Gas Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act
removed all NGA and NGPA price and nonprice controls affecting wellhead sales
of gas effective January 1, 1993. Although sales by producers of gas can
currently be made at uncontrolled market prices, Congress could reenact price
controls in the future.

         Virtually all aspects of Order Nos. 636, 636-A and 636-B, were opposed
by various segments of the oil and gas industry and a number of parties sought
judicial appeals of those orders. Furthermore, after the FERC issued orders
approving the individual pipeline restructuring plans authorized pursuant to
Order No. 636, various parties sought court review of certain of those
individual pipeline restructuring orders. The United States Court of Appeals
for the District of Columbia Circuit issued a decision in United Distribution
Companies v. FERC, 88 F.3d 1105 (D.C. Cir. 1996) which upheld Order No. 636
generally, as well as most of the specific provisions of Order No. 636. A
limited number of issues, however, were remanded to the FERC for further
consideration, although the court permitted the orders to stand as formulated,
pending Commission action on the issues remanded to it. Petitions for
certiorari have been filed with the Supreme Court. 65 U.S.L.W. 3531-32 (U.S.
Jan. 27, 1997) (No. 96-1186, et al.) On




                                      16
<PAGE>   19


February 27, 1997, the FERC issued Order No. 636-C to address the issues
remanded to it by the D.C. Circuit. The FERC reaffirmed certain of its previous
rulings on those issues and reversed others. Order No. 636-C is subject to
further review by the FERC should parties file for rehearing of that order.
Order No. 636-C is also subject to review by the courts, which could reverse
Order No. 636-C, or an order on rehearing, in whole or in part and remand the
matter to the FERC. Additionally, the individual pipeline restructuring plans
authorized by Order No. 636 that were appealed to various courts are still
pending before those courts. Moreover, any or all of the decision of the Court
of Appeals in United Distribution Companies could be reversed if the Supreme
Court grants certiorari to review Order Nos. 636, 636-A and 636-B. It is
impossible for DLB to predict the ultimate outcome regarding FERC review of
Order No. 636-C or the various petitions for judicial review. In addition, DLB
cannot predict whether changed circumstances might cause the FERC to reverse or
revise the current unbundled regulatory regime contemplated by Order No. 636 et
al. All of the above matters have resulted in a degree of uncertainty with
respect to interstate gas sales and transportation. DLB does not believe,
however, that it will ultimately be affected any differently than its
competitors.

         Additional proposals and proceedings that might affect the gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. DLB cannot predict when or if any such
proposals might become effective, or their effect, if any, on DLB's operations.
The gas industry historically has been very heavily regulated; therefore, there
is no assurance that the less stringent regulatory approach recently pursued by
the FERC and Congress will continue indefinitely into the future.

         State Regulation of Gas Production. Certain producing states,
including Oklahoma, have adopted or considered adopting measures that alter the
methods used to prorate gas production from wells located in these states,
including those in their territorial waters. These measures may limit the rate
at which gas may be produced from the wells in which the Company might acquire
an interest. Congress recently considered, but rejected, legislation that would
have limited the states' rights to prorate production. DLB cannot predict
whether such legislation will be reintroduced or what effect the new state
rules may have on gas production in producing states. At the present time there
are no allowables which would limit the production of oil or gas leases in
which DLB presently owns an interest.

         Sales and Transportation of Petroleum. Sales of oil, condensate and
natural gas liquids by DLB are not regulated and are made at market prices. The
price DLB receives from the sale of these products is affected by the cost of
transporting the products to market.

         Gathering. Under the NGA, facilities used for and operations involving
the production and gathering of gas are exempt from FERC jurisdiction, while
facilities used for and operations involving interstate transmission are not.
However, the FERC's determination of what constitutes exempt gathering
facilities as opposed to interstate transmission facilities has evolved over
time. With respect to facilities owned by noninterstate pipeline companies,
such as DLB's gathering facilities, the FERC has historically distinguished
between these types of activities on a very fact-specific basis that makes it
difficult to predict with certainty the status of DLB's gathering facilities.
In 1994, the FERC issued a series of orders that modified the test it uses to
determine whether facilities are classified as gathering or transmission. The
change in that test that could be applicable to DLB's facilities, involves a
redefinition by the FERC of its "behind the plant" factor. Specifically, the
FERC held that gathering facilities downstream of a processing plant would be
considered exempt from FERC jurisdiction only if those facilities are an
incidental extension of the plant operation or an extension of a gathering
system located behind (or "upstream" of) such a plant. This holding was based,
in part, upon the FERC's observation that, in recent years, its "behind the
plant" factor had eroded into a "behind the interstate pipeline" factor and the
FERC wanted to turn to an approach which gave greater emphasis to its
traditional "behind the plant" factor. Although the FERC has not issued, or
been requested to issue, any order or opinion declaring DLB's facilities as





                                      17
<PAGE>   20


gathering rather than transmission facilities, DLB believes that these systems
meet the currently applied tests that the FERC uses to establish a pipeline's
status as a gatherer. State regulation of gathering facilities generally
includes various safety, environmental and, in some circumstances,
nondiscriminatory take requirements. Although some states provide for the rate
regulation of pipelines engaged in the intrastate transportation of gas, such
regulation has not generally been applied against gatherers of gas. Oklahoma
has recently enacted legislation, however, that prohibits the imposition of
unjustly or unlawfully discriminatory gathering rates. Gas gathering may
receive greater regulatory scrutiny as a result of the pipeline restructuring
implemented under Order No. 636. DLB's gathering operations could be adversely
affected should they be subject in the future to the application of state or
Federal regulation of rates and services.

         Safety and Health Regulations. DLB is also subject to laws and
regulations concerning occupational safety and health. It is not anticipated
that DLB will be required in the near future to expend amounts that are
material in the aggregate to DLB's overall operations by reason of occupational
safety and health laws and regulations, but inasmuch as such laws and
regulations are frequently changed, DLB is unable to predict the ultimate cost
of compliance.

OPERATIONAL RISKS AND INSURANCE

         The oil and gas industry involves a variety of operating risks,
including the risk of fire, explosions, blowouts, pipe failure, casing
collapse, abnormally pressured formations and environmental hazards such as oil
spills, gas leaks, ruptures and discharges of toxic fluids and gases. The
occurrence of any of these risks could result in substantial losses to DLB from
loss of life or destruction of property, loss of production or equipment, or
liability for pollution or other environmental damage. To protect against these
risks, DLB insures against some, but not all, potential hazards. Its insurance
coverages include physical damage on certain assets, employer's liability,
comprehensive general liability, automobile, workers compensation, and loss of
production income insurance. Although DLB believes its insurance is adequate
and customary for similarly situated companies, due to deductibles, policy
limits, excluded hazards and other insurance limitations, such insurance does
not fully cover all risks that DLB might incur. As a result, DLB could incur
substantial liabilities to third parties or governmental entities, the payment
of which could reduce or eliminate the funds available for development,
acquisitions or exploration, or result in the loss of properties. Moreover, no
assurance can be given that DLB will be able to maintain adequate insurance in
the future at rates it considers reasonable.

EMPLOYEES

         As of December 31, 1996, DLB employed 62 people on a full-time basis,
including contract personnel. Nine employees are located in GEMCO's Houston,
Texas office and all others are located in DLB's principal offices in Oklahoma
City. The Company considers its relations with its employees to be good. The
acquisition of Bonray in February 1997 added 162 additional employees,
including Bonray's salaried personnel and hourly field employees.

HEADQUARTERS AND OTHER FACILITIES

         DLB leases its Oklahoma City, Oklahoma headquarters under a lease
covering approximately 20,100 square feet that expires in 2003. The monthly
rent is approximately $20,600. In addition, as a result of the February, 1997
acquisition of Bonray Drilling, the Company owns approximately forty acres of
land located in Oklahoma City, Oklahoma, on which an office building and
repair, support and storage facilities for the Company's drilling operations
are located. These facilities include a repair shop (8,000 square feet) and
three warehouses. DLB also leases office space in Houston, Texas.


                                      18
<PAGE>   21


ITEM 2.  PROPERTIES

OIL AND GAS RESERVES

         Estimates of DLB's net proved developed and undeveloped oil and gas
reserves as of January 1, 1997, and the present value (discounted at 10%) of
estimated future net revenues before income tax from those reserves are set
forth in the following table. This information is derived from the engineering
reports of DeGolyer and MacNaughton ("D&M") and H.J. Gruy and Associates, Inc.
("Gruy"). These year-end reserve quantities, as determined by independent
engineering firms, do not include 12.2 MMBOE as of January 1, 1997 with a
present value of future net revenues of $46.1 million attributable to Texaco's
50% interest in the West Cote Blanche Bay field which was acquired by the
Company in March 1997.

<TABLE>
<CAPTION>
                                 AS OF JANUARY 1, 1997
                               NET PROVED RESERVES (1)
                            ------------------------------    PRESENT VALUE
                               OIL        GAS       TOTAL      OF FUTURE
                             (MBBLS)    (MMCF)     (MBOE)     NET REVENUES
                            --------   --------   --------   --------------
                                                             (IN THOUSANDS)
<S>                            <C>       <C>        <C>      <C>
Proved Developed               5,234     54,797     14,367   $      154,978
Proved Undeveloped             1,437     25,560      5,697           49,785
                            --------   --------   --------   --------------
     Total                     6,671     80,357     20,064   $      204,763
                            ========   ========   ========   ==============
</TABLE>

         Estimated future net revenues represent estimated future gross
revenues from the production of proved reserves, net of estimated production
and future development costs, using prices and costs in effect as of January 1,
1997. These prices were held constant throughout the life of the properties
except where different prices were fixed and determinable from applicable
contracts. These price assumptions result in weighted average prices of $25.14
per barrel for oil and $3.70 per Mcf for gas over the life of the properties
that the Company owned at December 31, 1996. The amounts shown do not reflect
non-property related costs, such as general and administrative expenses, debt
service, and future income tax expense or depreciation, depletion and
amortization. The present value of estimated future net revenues is calculated
by discounting estimated future net revenues by 10% annually. Prices used in
calculating the estimated future net revenues attributable to proved reserves
do not necessarily reflect market prices for oil and gas production subsequent
to January 1, 1997. There can be no assurance that all of the proved reserves
will be produced and sold within the periods assumed, that the assumed prices
will actually be realized for such production, or that existing contracts will
be honored. For supplemental information about the oil and gas activities of
DLB, see Note 16 to the Company's Consolidated Financial Statements and Notes.

         There are numerous uncertainties inherent in estimating oil and gas
reserves and their estimated values, including many factors beyond the control
of the producer, and such estimates are affected by oil and gas prices which
have fluctuated widely in recent years. There can be no assurance that these
reserves will be realized as expected. The reserve data set forth in this
annual report represent only estimates. 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 any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different engineers
often vary. In addition, estimates of reserves are subject to revisions based
on actual production, results of future exploration and development activities,
prevailing oil and gas prices, operating costs and other factors. These
revisions may be material. Accordingly, reserve estimates are often



                                      19
<PAGE>   22


different from the quantities of oil and gas that are ultimately recovered. The
meaningfulness of such estimates is highly dependent on the accuracy of the
assumptions on which they are based.

         DLB has not filed reports containing estimates of its total proved net
oil and gas reserves with any Federal agency.

ACREAGE

         DLB's developed and undeveloped oil and gas acreage as of December 31,
1996 is set forth in the following table.

<TABLE>
<CAPTION>
                                         DEVELOPED                   UNDEVELOPED                    TOTAL
                                 --------------------------------------------------------------------------------
                                   GROSS           NET          GROSS            NET         GROSS         NET
                                 --------------------------------------------------------------------------------
<S>                                 <C>            <C>          <C>             <C>          <C>          <C>
Oklahoma......................      167,457        90,130       313,711         275,757      481,168      365,887
Texas.........................        5,220         1,719        24,210           3,175       29,430        4,894
Kansas........................        1,080         1,013         5,466           5,094        6,526        6,107
Louisiana(1)..................        1,650           146           718              36        2,368          182
Barbados(2)...................           --            --        92,160          24,883       92,160       24,883
                                 ----------     ---------     ---------      ----------   ----------    ---------
     Total....................      175,407        93,008       436,245         308,945      611,652      401,953
                                 ==========     =========     =========      ==========   ==========    =========
</TABLE>

---------------------------

          (1)  Does not include 4,682 gross and 2,341 net developed acres
               attributable to Texaco's 50% interest in the West Cote Blanche
               Bay field which was acquired by the Company in March 1997.

          (2)  Owned through DLB's interest in WBL. See Item 1.
               "Business--Areas of Future Exploration and Development
               Activities--Barbados."


         DLB's oil and gas leases are for varying primary terms and may require
the payment of delay rentals to continue the primary term. The leases may be
surrendered by the operator at any time by notice to the lessors, by the
cessation of production or by failure to make timely payments of delay rentals.

         As of December 31, 1996, DLB held royalty, overriding royalty and
other mineral interests in 11,943 net acres in addition to the developed and
undeveloped acreage indicated above.

PRODUCTION, PRICES AND PRODUCTION COSTS

         Information concerning DLB's oil and gas production, average sales
prices and average lease operating expense is set forth below for the periods
indicated. Information relating to gas includes natural gas liquids.

<TABLE>
<CAPTION>
                                    YEAR ENDED DECEMBER 31,
                                 ------------------------------
                                   1996       1995        1994
                                 ------------------------------
<S>                              <C>        <C>        <C>
Production:
   Oil (MBbls) ..............         664         708         663
   Gas (MMcf) ...............       5,603       3,022       3,187
      Total (MBOE) ..........       1,598       1,212       1,194
Average Sales Prices:
   Oil ($/Barrel) ...........   $   20.84   $   17.45   $   17.61
   Gas ($/Mcf) ..............        2.38        1.82        1.93
      Total ($/BOE) .........   $   17.02   $   14.74   $   14.93
Lease operating expense:
   ($/BOE)(1) ...............   $    4.62   $    4.08   $    4.58
</TABLE>

---------------------------

         (1)      The components of lease operating expense may vary
                  substantially among wells depending on the methods of
                  recovery employed and other factors, but generally include
                  production taxes, administrative overhead, maintenance and
                  repairs, labor and utilities.




                                      20
<PAGE>   23




         Since DLB conducts much of its exploratory activities in and about
mature fields, existing markets are often nearby, thereby reducing
transportation costs, which are a component of lease operating expense.

DRILLING ACTIVITY AND PRODUCTIVE WELL SUMMARY

         The following table sets forth DLB's exploration and development
drilling activity expressed on a well basis for the periods indicated.

<TABLE>
<CAPTION>
                                        YEAR ENDED DECEMBER 31,
                           ---------------------------------------------
                                1996            1995            1994
                           ---------------------------------------------
                           GROSS    NET     GROSS   NET    GROSS    NET
                           ---------------------------------------------
<S>                        <C>     <C>     <C>    <C>     <C>     <C>
Exploratory Wells:
   Oil .................       3     2.1       1     0.6       9     4.3
   Gas .................       4     3.2       6     3.0       8     4.4
   Dry .................      14    11.4      12    10.7      14     8.4
                           -----   -----   -----   -----   -----   -----
      Total ............      21    16.7      19    14.3      31    17.1
                           =====   =====   =====   =====   =====   =====
Development Wells:
   Oil .................       8     3.4       4     1.2       4     2.2
   Gas .................      15     5.1       8     3.9       6     1.9
   Dry .................       1     0.3       1    --         6     4.3
                           -----   -----   -----   -----   -----   -----
      Total ............      24     8.8      13     5.1      16     8.4
                           =====   =====   =====   =====   =====   =====
</TABLE>

         "Gross wells" refers to the total wells in which DLB has a working
interest. "Net wells" refers to these gross wells multiplied by DLB's
percentage working interest. As of March 1, 1997, 23 gross (11.2 net)
exploratory and developmental wells were in progress. In 1996, all of DLB's
drilling activities were conducted on a contract basis with independent
drilling contractors. However, with the acquisition of Bonray the Company will
also utilize its own rigs for future drilling activities.

         In 1996, 1995 and 1994, the average well depths for all exploratory
wells drilled were approximately 4,900, 6,900 and 8,600 feet, respectively, and
the average well depths for all development wells drilled in such years were
approximately 9,400, 9,800 and 8,100 feet, respectively.




                                      21
<PAGE>   24


         The following table sets forth the number of productive oil and gas
wells in which DLB owned an interest as of March 1, 1997.

<TABLE>
<CAPTION>
                               COMPANY            TOTAL
                            OPERATED WELLS  PRODUCTIVE WELLS
                           ---------------------------------
                           GROSS     NET     GROSS     NET
                           ---------------------------------
<S>                           <C>    <C>       <C>     <C>
Productive Wells:
   Oil .................      165    107.0     1279    208.4
   Gas .................       91     66.0      379    102.3
                           ------   ------   ------   ------
      Total ............      256    173.0    1,658    310.7
                           ======   ======   ======   ======
</TABLE>

          (1)  This does not include production wells acquired in the Texaco
               Acquisition of March 11, 1997 of 396 gross (198.0 net) operated
               wells.

         DLB seeks to act as operator of the wells in which it owns a
significant interest. As operator of a well, DLB manages drilling and
production operations for itself and the other working interest owners in the
well. As compensation for its services, it receives operating fees from the
other working interest owners. Acting as operator enables DLB to increase its
revenue base, control the progress of drilling and production activity and
enhance its knowledge and expertise.

         The following table sets forth DLB's historical finding and
development costs and proved reserve changes.

<TABLE>
<CAPTION>
                                               YEAR ENDED DECEMBER 31,
                                           -------------------------------
                                             1996       1995        1994
                                           -------------------------------
<S>                                        <C>        <C>         <C>
Finding and Development Costs(1):
   Exploration costs ...................   $  9,161   $  6,283    $  7,694
   Development costs ...................     10,015      5,177       6,510
   Acquisition costs ...................     27,893         39       8,849
                                           -------------------------------
      Total costs ......................   $ 47,069   $ 11,499    $ 23,053
                                           -------------------------------
Proved Reserve Changes (MBOE):
   Extensions and discoveries ..........      5,301      2,097       2,878
   Revisions of previous estimates .....        138     (1,000)       --
   Purchases ...........................      6,830        265       1,093
                                           -------------------------------
      Total reserve additions ..........     12,269      1,362       3,971
                                           ===============================
Finding and Development Costs ($/BOE)(1)   $   3.84   $   8.44    $   5.81
</TABLE>

---------------------------

     (1)  Excludes costs of oil and gas properties not subject to amortization,
          which consist of the cost of undeveloped leaseholds,
          wells-in-progress and secondary recovery projects before the
          assignment of proved reserves.




                                      22
<PAGE>   25


CONTRACT DRILLING OPERATIONS

         The Company is engaged in domestic onshore contract drilling of oil
and gas wells through Bonray. The Company acquired Bonray in February 1997 in a
negotiated transaction involving a cash tender offer and subsequent merger of
Bonray with a wholly-owned subsidiary of the Company. As a result of this
acquisition, the Company acquired 15 land drilling rigs having depth
capabilities ranging from 7,000 to 25,000 feet. The Company believes that the
Bonray Acquisition is of significant strategic importance because it (i)
increases rig availability for use in DLB's exploration and development
program, (ii) gives DLB control of rigs to allow it to hedge against increases
in drilling costs, and (iii) creates new growth opportunities for the Company,
including the ability to enter new core areas through joint ventures with
companies requiring rig availability to protect expiring leasehold positions.
The following table sets forth certain information relating to the Company's
rigs.

<TABLE>
<CAPTION>
                            DEPTH
            RIG          CAPABILITY                                               STATUS AT
          NUMBER         (FEET)(1)         HORSEPOWER           TYPE             MARCH 1, 1997
         ---------------------------------------------------------------------------------------
<S>         <C>            <C>                  <C>                <C>
             1             16,000             1,000          Oilwell 760           Operating
             2             20,000             2,000          Oilwell 860           Rigging Up
             3             10,000               600          Ideco 525             Stacked
             4             12,000               850          Unit U-40             Operating
             5              9,000               500          National 50-A         Stacked
             6              9,000               500          National 50-A         Stacked
             7              7,000               550          Cooper 550            Operating
             8             10,000               750          Cooper LTO 750        Operating
            10             12,000               550          National 55           Operating
            21             12,000               750          Ideco 750             Operating
            30             20,000             1,500          National 1320-M       Rigging Up
            31             25,000             2,000          National 1320-M       Operating
            32             20,000             1,500          National 110-M        Operating
            33             20,000             1,500          Mid Continent U914    Operating
            34             25,000             2,000          Gardner Denver 1500   Operating
</TABLE>

------------------------

         (1)      Depth capabilities are based upon the use of 4.5 inch or 5
                  inch drill pipe and normal casing designs. The capabilities
                  may vary as a result of the use of different drill pipe or
                  unusual casing designs.

         The terms and rates of the Company's drilling contracts vary depending
upon the location, duration and complexity of the drilling, the equipment and
services provided and other factors. As of March 1, 1997, 11 rigs were under
contract for the drilling of 11 wells. As of that date, 10 of the Company's
rigs were operating on a daywork basis, pursuant to which the Company is paid
monthly a specified amount per day based on the depth capability of the rig.
The Company is paid for all days during the term of the contracts except days
for which the rigs are not in operation because of repairs or maintenance.
Daywork contracts generally specify the type of equipment to be used, the size
of the hole and the depth of the well to be drilled, and provide for payment by
the customer of certain costs and expenses of transporting, assembling and
dismantling the rigs. While working under daywork contracts, the Company bears
no part of the costs due to in-hole losses such as time delays for various
reasons, including stuck drill strings and blowouts.




                                      23
<PAGE>   26


         The Company may from time to time enter into footage and turnkey
contracts. Footage and turnkey contracts, as opposed to daywork contracts,
shift the risk of loss in drilling from the customer to the drilling contractor
and, as a consequence, result in greater variation in profitability. As of
March 1, 1997, one rig was operating under a footage contract. Footage
contracts usually provide for payment of an agreed price per foot of hole
drilled to a specified depth regardless of the time required or the problems
encountered. Turnkey contracts, of which none were in process at March 1, 1997,
provide for payment of an agreed price upon the attainment of a specified
objective. Turnkey contracts require more services of the contractor and,
consequently, result in additional risks, costs and higher revenues which are
not inherent in footage or daywork contracts. Turnkey contracts include costs
for casing, cementing, drilling mud, and logging services. The Company
determines the manner of drilling and type of equipment to be used, subject to
customer specifications.

         The Company prefers to work on a daywork basis, as it does not believe
the potentially higher profit margins of footage and turnkey contracts justify
the associated increased risks. However, in periods of lesser demand, the
Company is generally required to work on a footage or turnkey basis,
particularly with respect to shallow drilling.

TITLE TO PROPERTIES

         Following industry practices, DLB makes a cursory review of title to
undeveloped oil and gas leases and farmout acreage upon execution of the
contracts. Before beginning drilling operations, a thorough title examination
is conducted and curative work is performed to correct material title defects.
If material title defects are present, DLB typically is responsible for curing
the defects at its expense. If DLB were unable to cure a material defect, it
could suffer the loss of its investment in the leasehold. DLB has obtained
title opinions on substantially all its producing properties and believes that
it has satisfactory title to such properties in accordance with industry
standards. Before making any significant acquisition of producing properties,
DLB obtains opinions of counsel as to title. DLB's leasehold interests are
subject to customary royalty interests, liens for current taxes and other
burdens not affecting the use or value of the interests. Substantially all of
DLB's oil and gas properties are mortgaged to secure borrowings under the
Company's credit facility. See Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Capital Expenditures, Capital
Resources and Liquidity."


ITEM 3.    LEGAL PROCEEDINGS

         A lawsuit styled Agor et al v. Amerada Hess Corporation and DLB Oil &
Gas, Inc. (CJ-96-32) was filed in the District Court of Dewey County, Oklahoma
on January 22, 1997. The claims arise from the contentions of the mineral
owners under one oil and gas lease ("the Lease") in a 640 acre drilling and
spacing unit ("the Unit") that the Lease has expired in the absence of
commercial production from the wells in the Unit. The plaintiffs seek
cancellation of the Lease and an accounting for production from the alleged
effective date of lease termination. This well was purchased as part of the
Amerada Hess Acquisition and was allocated approximately $0.3 million of the
purchase price. Counsel believes DLB's defense to be meritorious and will
vigorously contest the issue. However, if the plaintiffs prevail, the Company
will seek recovery of such amount pursuant to the provisions of the purchase
agreement.

                                      24
<PAGE>   27

         On July 15, 1996, a lawsuit styled Samson Resources Company et al v.
Amerada Hess Corporation and DLB Oil & Gas, Inc. (CJ-96-38) was filed in the
District Court of Ellis County, Oklahoma. In this action, Samson Resources
Company ("Samson") claims that it has been denied its preferential rights to
purchase certain properties under various operating agreements with Amerada
Hess Corporation. DLB acquired such properties in its Amerada Hess Acquisition.
DLB contends that Samson's preferential right elections were invalid as to the
majority of such interests. On January 21, 1997, a hearing was held before the
District Court of Ellis County on cross motions for summary judgment of DLB and
Samson. The Court ruled in favor of DLB on most of Samson's claims against DLB.
However, the Court appeared to adopt Samson's method of preferential right
election, although judgment was not rendered in Samson's favor. DLB is
considering all its options in light of the Court's ruling. If the Court rules
in Samson's favor, barring appeal, DLB would be required to sell the subject
properties for approximately $1.1 million, representing the values listed in
the purchase agreement for such properties.

         DLB is also involved in the routine judicial and administrative
proceedings that are common to companies of its size in the oil and gas
industry. None of the Company's pending proceedings are believed, either
individually or in aggregate, to be material to DLB's financial condition,
liquidity or results of operations.


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

         No matters were submitted to a vote of security holders of the Company
during the fourth quarter of 1996.


ITEM 4A.   EXECUTIVE OFFICERS OF THE REGISTRANT
         The following table sets forth information regarding the names and
ages (as of March 26, 1997) of and positions held by each of the Company's
executive officers. The Company's executive officers serve at the discretion of
the Board of Directors.

<TABLE>
<CAPTION>
NAME                        AGE         POSITION
----                        ---         --------
<S>                          <C>    <C>
Mike Liddell                 43     Chief Executive Officer and Director

Mark Liddell                 42     President and Director

Gary C. Hanna                39     Executive Vice President and Chief
                                    Operating Officer

Ronald D. Youtsey            41     Senior Vice President and Chief Financial
                                    Officer

William N. Young, III        43     President, GEMCO, L.L.C.

Ted A. Campbell              36     Vice President of Drilling and Production

Rick A. Carlson              37     Vice President of Exploration

Wesley E. Myers              52     Vice President of Engineering

Fred W. Standefer            43     Vice President of Corporate Development
</TABLE>



                                      25
<PAGE>   28

         Mike Liddell has served as Chief Executive Officer of DLB since
October 1994, and as a director of DLB since 1991. From 1991 to 1994, Mr.
Liddell was President of DLB. From 1979 to 1991, he was President and Chief
Executive Officer of DLB Energy. He received a B.S. degree in education from
Oklahoma State University. He is the brother of Mark Liddell.

         Mark Liddell has served as the President of DLB since October 1994,
and since 1991 has been a director of Davidson Oil and Gas Company, Inc. and
DLB. From 1991 to 1994, Mr. Liddell was Vice President of DLB. From 1985 to
1991, he was Vice President of DLB Energy. From 1991 to May 1995, Mr. Liddell
served as a director of TGX Corporation, a publicly-held oil and gas company,
and, from 1989 to 1990, he served as a director of Kaneb Services, Inc., a
publicly-held industrial services and pipeline transportation company. He
received a B.S. degree in education and a J.D. degree from the University of
Oklahoma. He is the brother of Mike Liddell.

         Gary C. Hanna has served as Executive Vice President and Chief
Operating Officer of DLB since October 1994. From 1982 to October 1994, he was
President and Chief Executive Officer of Hanna Oil Properties, Inc., an
Oklahoma City-based petroleum consulting company. Beginning in 1991 and
continuing until Mr. Hanna joined the Company, Hanna Oil Properties, Inc.
performed most of the Company's acquisition and land services. He received a
B.B.A. degree in economics from the University of Oklahoma. Mr. Hanna is on the
Board of Directors of the Oklahoma Independent Producers Association.

         Ronald D. Youtsey has served as Senior Vice President and Chief
Financial Officer of DLB since October 1994. Mr. Youtsey joined DLB as
Controller in 1991. From 1979 to 1991, he was employed by French Petroleum
Corporation, an oil and gas exploration and production company, last serving as
Vice President of Finance. Mr. Youtsey is a Certified Public Accountant and a
member of the American Institute of Certified Public Accountants. He received a
B.S. degree in accounting from the University of Central Oklahoma.

         William N. Young, III has served as President of GEMCO since the sale
of LEDCO in February 1995, and from 1992 to that time, he was President of
LEDCO. From 1986 to 1992, he was employed by Noram Energy Services, Inc., most
recently serving as Vice President -- Gas Acquisitions and, from 1984 to 1986,
he was employed by Midcon Services, Inc., most recently serving as Vice
President of Marketing. From 1982 to 1984, he was Director, Transportation and
Exchange for United Gas Pipe Line Co. Mr. Young received B.S. and M.S. degrees
in civil engineering from North Carolina State University.

         Ted A. Campbell has served as Vice President of Drilling and
Production for DLB since October 1994 and was Operations Manager from 1991
until 1994. From 1987 until the formation of DLB, he was employed by DLB Energy
as a geologist. Mr. Campbell is a member of the American Association of
Petroleum Geologists. He received a B.S. degree in geology from Oklahoma State
University.

         Rick A. Carlson has served as Vice President of Exploration of DLB
since October 1994 and was Senior Geologist from 1991 until 1994. From 1984
until the formation of DLB, he was a geologist for DLB Energy. He is a member
of the American Association of Petroleum Geologists. Mr. Carlson received a
B.S. degree in geology from Oklahoma State University.

         Wesley E. Myers has served as Vice President of Engineering for DLB
since October 1994. From 1993 to 1994, he was a consulting petroleum engineer
and, from 1975 to 1993, he was employed by Grace Petroleum Corporation, an oil
and gas exploration and production company, last serving as Vice President of
Engineering. Mr. Myers is a registered Professional Engineer and a member of
the Society of Petroleum Engineers. He received a B.S. degree in civil
engineering from the University of Missouri at Rolla.

         Fred W. Standefer has served as Vice President of Corporate
Development since August 1995. From 1990 to 1995, he was a financial consultant
with Merrill Lynch & Co. From 1983 to 1995, Mr. Standefer was an owner, officer
and director of NYTEX Corporation, a closely-held independent oil company. He
received a B.B.A. from the University of Texas at Austin.


                                      26
<PAGE>   29
                                    PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

     The common shares of the Company are traded on the Nasdaq National Market
under the symbol "DLBI". The following table sets forth the quarterly high and
low closing sales prices of the Company's common shares, as reported by NASDAQ
for 1996. The prices quoted represent prices between dealers in securities,
without adjustment for mark-ups, mark-downs or commissions, and do not
necessarily reflect actual transactions.

<TABLE>
<CAPTION>
              1996:                                  HIGH         LOW
          --------------                            ------       -----
          <S>                                         <C>        <C>
          First Quarter                               10         6 7/8
          Second Quarter                               8         6 7/8
          Third Quarter                                8 1/2     7 1/8
          Fourth Quarter                              11         8 1/8
</TABLE>

     The closing market price of the common shares on March 10, 1997, was $14
1/4 per share. As of March 10, 1997, there were 45 shareholders of record of
the Company's Common Stock, and the number of shares of Common Stock
outstanding was 12,975,000 shares (excluding treasury shares).

     DLB intends to retain its earnings for use in the operation and expansion
of its business and will not likely pay cash dividends on its Common Stock in
the foreseeable future. In addition, the Company's credit facility limits the
payment of dividends and the making of distributions to shareholders to no more
than 25% of net earnings in any twelve month period.



                                     27
<PAGE>   30
ITEM 6.  SELECTED FINANCIAL DATA

     The following selected consolidated financial and operating data for DLB
as of and for each of the years in the five year period ended December 31,
1996, was derived from the Company's consolidated financial statements. The
information in the table gives effect to the Merger as if such event had
occurred as of January 1, 1991. The selected consolidated financial and
operating data set forth below should be read in conjunction with Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements and notes included
elsewhere in this annual report.

<TABLE>
<CAPTION>
                                                                1996(5)    1995      1994     1993      1992
                                                                -------  --------   -------  -------  -------
STATEMENTS OF OPERATIONS DATA:                               (In thousands, except per share and operating data)
<S>                                                             <C>      <C>        <C>      <C>      <C>
      Revenues:
           Oil and natural gas sales                            $27,194  $ 17,860   $17,826  $10,264  $ 5,824
           Natural gas gathering, processing and
                transportation, net                                 821     3,293     1,652      764       --
           Natural gas contract settlement                           --        --     3,343       --       --
           Interest income and other                                400       899       334      281      383
                                                                -------  --------   -------  -------  -------
                Total revenues                                  $28,415  $ 22,052   $23,155  $11,309  $ 6,207
                                                                -------  --------   -------  -------  -------
      Expenses:
           Lease operating                                        5,539     3,579     4,461    1,704    1,157
           Gross production taxes                                 1,843     1,366     1,009      718      408
           Depreciation, depletion and
                amortization                                      8,938     7,368     6,553    3,270    1,369
           General and administrative                             2,485     1,486       549      446       73
           Interest                                               1,582       529       677       38       11
           Loss on sale of assets                                   208        --        --       --       --
                                                                -------  --------   -------  -------  -------
                Total expenses                                   20,595    14,328    13,249    6,176    3,018
                                                                -------  --------   -------  -------  -------
      Income before income taxes                                  7,820     7,724     9,906    5,133    3,189
      Pro forma income taxes (1)                                     --        --     3,962    2,054    1,276
      Income taxes (1)                                            2,951    12,900        --       --       --
                                                                -------  --------   -------  -------  -------
      Net income (loss)                                         $ 4,869  $ (5,176)  $ 5,944  $ 3,079  $ 1,913
                                                                =======  ========   =======  =======  =======
      Net income (loss) per common share                           0.38     (0.46)     0.59     0.31     0.19
                                                                =======  ========   =======  =======  =======
      Weighted average common share outstanding (2)              12,978    11,250    10,000   10,000   10,000
                                                                =======  ========   =======  =======  =======
CASH FLOW DATA:
      Net cash provided by operating activities                 $19,559  $ 13,395   $17,261  $ 8,076  $ 5,700
      Capital expenditures (3)                                   57,165    19,852    26,291   17,529    9,169
      Distributions to shareholders (pre-Offering)                   --     1,192     3,196      710      252
      EBITDA (4)                                                 18,340    15,621    17,143    8,441    4,569
OPERATING DATA:
      Wellhead production:
           Oil (MBBLS)                                              664       708       663      324      205
           Gas (MMCF)                                             5,603     3,022     3,187    2,374    1,332
                Total (MBOE)                                      1,598     1,212     1,194      720      427
      Average sales price:
           Oil ($/BBL)                                          $ 20.84  $  17.45   $ 17.61  $ 18.29  $ 16.23
           Gas ($/MCF)                                             2.38      1.82      1.93     1.83     1.87
                Total ($/BOE)                                     17.02     14.74     14.93    14.26    13.64
      Lease operating expense ($/BOE)                              3.47      2.95      3.74     2.36     2.71
      Gross production taxes ($/BOE)                               1.15      1.13      0.84     1.00     0.96
      Depreciation, depletion and amortization expense ($/BOE)     5.59      6.08      5.49     4.54     3.21
      General and administrative expense ($/BOE)                   1.56      1.23      0.46     0.62     0.17
</TABLE>



                                      28

<PAGE>   31
<TABLE>
<CAPTION>
                                                   1996      1995    1994     1993      1992
                                                 --------  -------  -------  -------  --------
 BALANCE SHEET DATA                           (In thousands, except per share and operating data)
<S>                                              <C>       <C>      <C>      <C>      <C>
       Cash and cash equivalents                 $  4,060  $14,313  $ 3,059  $ 4,475  $    965
       Working capital                              1,237   13,724      773    2,591    (1,023)
       Property and equipment, net                104,958   58,661   46,375   26,637    12,554
       Total assets                               129,441   78,207   54,041   35,084    15,506
       Long-term debt, including current portion   37,200       --    8,231      483        --
       Shareholders' equity                        64,232   59,544   39,012   30,164    11,690
</TABLE>

--------

(1)  Pro forma income taxes were computed at a blended statutory rate of 40%
     (34% Federal rate and a composite 6% state rate) of income before income
     taxes. The Company was subject to Subchapter S of the internal revenue
     code and, accordingly, was not a tax paying entity. Prior to the July 1995
     equity offering, the Company terminated its S corporation election and
     recognized $11.5 million of deferred income taxes at that time.

(2)  As a result of the Merger, 10,000,000 shares of common stock were issued
     to the prior shareholders of the Company and Davidson Oil and Gas Company,
     Inc. The Merger was accounted for as a reorganization of interests in a
     manner similar to a pooling of interests. Accordingly, 10,000,000 shares
     of common stock were considered outstanding for all periods prior to the
     Merger.

(3)  Capital expenditures include those expenditures for oil and gas
     properties, leaseholds, gas processing plants, saltwater disposal systems
     and other property and equipment.

(4)  EBITDA is earnings before interest, taxes, depreciation, depletion and
     amortization. EBITDA is an analytical measure frequently used by
     securities analysts and is presented to provide additional information
     about the Company's ability to meet its future debt service, capital
     expenditure and working capital requirements. See Item 7. "Management's
     Discussion and Analysis of Financial Condition and Results of Operations -
     Capital Expenditures, Capital Resources and Liquidity." EBITDA should not
     be considered as a better measure of the Company's operating performance
     than net income or as a better measure of liquidity than cash flow from
     operations.

(5)  On May 31, 1996, the Company purchased for approximately $32.1 million
     substantially all of the Oklahoma oil and gas producing properties,
     mineral rights and leasehold acreage of Amerada Hess Corporation.


                                      29

<PAGE>   32
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
         AND RESULTS OF OPERATIONS

     The following discussion is intended to assist in an understanding of the
Company's financial position as of December 31, 1996 and 1995, and its results
of operations for each year in the three year period ended December 31, 1996.
The consolidated financial statements and notes thereto included herein contain
additional information and should be referred to in conjunction with this
discussion.

GENERAL

     Since commencing operations in 1991, the Company's primary focus has been
to explore for oil and gas primarily in the Mid-Continent area utilizing 3-D
and high resolution 2-D seismic technology. The Company believes that this
focus has provided and will continue to provide the Company with numerous
exploratory prospects. In addition, the Company's business strategy has been
enhanced by a shift in industry focus to international exploration and domestic
development and acquisition activities, rather than domestic exploration
activities. By combining its advanced technologies with both proprietary and
public data and successfully applying such technology to its exploration
activities, the Company has made 23 new field discoveries since January 1991,
seven of which were made in 1996. During 1996, the Company initiated efforts in
adding the Louisiana Gulf Coast as a core area. The Company intends to apply
the same concentrated area approach used by the Company in Oklahoma to the area
in Louisiana.

     Previous to 1995, the Company utilized shareholder contributions, cash
flow from operations and, to a lesser extent, borrowings to fund its
exploratory and other capital expenditure programs. As a result of the
Company's expansion of its proprietary and other data bases, additions to the
Company's prospect inventory and acquisition plans and commitments, projected
capital expenditures in 1997 will outpace management's estimate of internally
generated cash flow from operations and existing working capital and will
require additional external capital. See "--Capital Expenditures, Capital
Resources and Liquidity."

     Management believes the Company's involvement in a number of ancillary
activities distinguishes the Company from many of its competitors. Through the
active marketing of the Company's oil and gas production, management believes
the Company obtains prices that, on the whole, are more favorable than those
received by its regional competitors. The Company also attempts to gain
ownership of gathering, processing, transportation and saltwater disposal
facilities when it believes such ownership can enhance net margins per BOE. The
Company also seeks to control costs by focusing the Company's oil and gas
operations in areas subject to less competitive pressure. The cost of acquiring
leasehold and mineral interests are generally lower in these areas. The
February 1997 acquisition of a domestic onshore drilling company further
illustrates the Company's involvement in ancillary activities and is expected
to assist the Company in controlling drilling costs. Each of these activities
can improve the Company's production economics and help to maximize wellhead
margins.

     The markets for oil and gas have been volatile and are likely to remain so
in the future. Prices for oil and gas are subject to wide fluctuations in
response to relatively minor changes in the supply and demand for oil and gas,
market uncertainty and a variety of additional factors that are beyond the
control of the Company. In the future, lower oil and gas prices may reduce (i)
the attractiveness or viability of exploration prospects and the amount of oil
and gas reserves that may be produced economically, (ii) the Company's cash
flow from operations, (iii) the amount of outstanding borrowings under the
Company's credit facility and (iv) the Company's net income and capital
expenditures.


                                      30

<PAGE>   33
     The Company may from time to time enter into certain swap or hedge
transactions in an attempt to mitigate such price volatility on production that
is subject to market sensitive pricing. To the extent the Company is unable to
effect such transactions, continued fluctuations in oil and gas prices could
have an effect on the Company's operating results. The Company had no hedge
positions effecting results of operations for the year ended December 31, 1996.
The Company has entered into futures contracts to fix the sales price of
certain of its oil and gas production during 1997. The Company has entered into
oil futures contracts for the months of January through August, with volumes
ranging from 48,000 to 53,000 Bbls per month, and prices ranging from $25.47
per Bbl in January to $21.37 per Bbl in August. The Company has also
entered into gas futures contracts for the months of January through September,
with volumes ranging from 187,000 to 636,000 Mcf. of gas per month and prices
ranging from $4.47 per Mcf. in January to $1.95 per Mcf. in September. These
futures contracts are expected to mitigate the effect of lower product prices
in the first quarter of 1997 as compared to December 1996.

     The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are
capitalized into a "full cost pool" as incurred, and properties in the pool are
depleted and charged to operations using the units-of-production method based
on the ratio of current production to total proved oil and gas reserves. To the
extent that such capitalized costs, net of depreciation, depletion and
amortization, exceed the present value of estimated future net revenues,
discounted at 10%, from proved oil and gas reserves, after income tax effects,
such excess costs are charged to operations. Once incurred, a write down of oil
and gas properties is not reversible at a later date, even if oil or gas prices
increase.

     The discussion in this Item 7 includes statements that are not purely
historical and are "forward-looking statements" within the meaning of Section
27A of the Securities Act and Section 21E of the Exchange Act, including
statements regarding the Company's expectations, hopes, beliefs, intentions and
strategies regarding the future. The Company's actual results could differ
materially from its expectations discussed herein. Certain important factors
that could cause actual results to differ materially from the Company's
expectations are disclosed elsewhere in this Form 10-K. See "Disclosure
Regarding Forward-Looking Statements."


                                      31

<PAGE>   34
]RESULTS OF OPERATIONS

The following table sets forth certain operating information with respect to
the oil and gas operations of DLB.

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                ----------------------------------------------
                                                                     1996            1995            1994
                                                                --------------  --------------  --------------
                                                        (IN THOUSANDS OF DOLLARS, EXCEPT PER UNIT AND PRODUCTION DATA)
<S>                                                             <C>             <C>             <C>
OPERATING DATA:
     Oil and gas sales revenues                                 $       27,194  $       17,860  $       17,826
     Lease operating expense                                             5,539           3,579           4,461
     Gross production taxes                                              1,843           1,366           1,009
     Depreciation, depletion and amortization (1)                        8,364           6,687           6,185
     General and administrative expense                                  2,485           1,486             549
PRODUCTION DATA:
     Oil (MBBLS)                                                           664             708             663
     Gas (MMCF)                                                          5,603           3,022           3,187
        Total (MBOE)                                                     1,598           1,212           1,194
AVERAGE SALES PRICE DATA:
     Oil ($/BBL)                                                $        20.84  $        17.45  $        17.61
     Gas ($/MCF)                                                          2.38            1.82            1.93
        Total ($/BOE)                                                    17.02           14.74           14.93
EXPENSE DATA ($/BOE):
     Lease operating expense (2)                                          3.47            2.95            3.74
     Gross production taxes                                               1.15            1.13            0.84
     Depreciation, depletion and amortization (1)                         5.23            5.52            5.18
     General and administrative                                           1.56            1.23            0.46
</TABLE>

--------------------

     (1)  Includes only depreciation, depletion and amortization associated
          with oil and gas properties. Amounts pertaining to property and
          equipment other than oil and gas properties were $0.6 million, $0.7
          million and $0.4 million for the years 1996, 1995 and 1994,
          respectively, and including all depreciation, depletion and
          amortization, the results were $5.59, $6.08 and $5.49 on a BOE basis
          for the year 1996, 1995 and 1994, respectively.

     (2)  The components of lease operating expense may vary substantially
          among wells depending on the methods of recovery employed and other
          factors, but generally include administrative overhead, maintenance
          and repairs, and labor and utilities.


YEAR ENDED DECEMBER 31, 1996 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1995

     Revenues. Total revenues for the year ended December 31, 1996 were $28.4
million, an increase of $6.4 million from $22.0 million in 1995. Oil and gas
sales revenues were $27.2 million in 1996 as compared to $17.9 million in 1995.
Production of oil and gas was 664 Mbbl and 5,603



                                      32

<PAGE>   35
Mmcf, respectively, in 1996, as compared to 708 Mbbls and 3,022 Mmcf,
respectively, for 1995. The increase in oil and gas revenues was due to the
June 1996 acquisition of the Amerada Hess properties and an increase in product
prices. The properties acquired from Amerada Hess produced 173 Mbbls of oil and
2,153 Mmcf of gas for the seven months during 1996 that the Company owned the
properties. Increases in gas production offset decreases in oil production on a
BOE basis. Oil production decreased in 1996 primarily from natural production
declines. The average price received for oil increased to $20.84 per barrel in
1996 from $17.45 per barrel in 1995. The average price received for natural gas
was $2.38 per Mcf for 1996 as compared to $1.82 per Mcf for 1995. Gathering,
dehydration and compression fees decreased $2.5 million to $0.8 million in 1996
as compared to $3.3 million in 1995 primarily due to the sale of assets related
to dissolution of the Carmen Field Joint Venture ("CFJV"). On February 7, 1996
the Company settled claims against a joint venture partner pertaining to the
Carmen Field Joint Venture Agreement. The Company received $3.3 million as part
of the settlement and CFJV was dissolved. The Company earned net income before
income taxes from gathering, dehydration and compression fees, and demand
charges of $2.9 million for 1995 from the assets subject to the settlement.
(See Note 13 to the Consolidated Financial Statements.)

     Lease operating expense. Lease operating expense increased to $5.5 million
for 1996 from $3.6 million in 1995 primarily due to the addition of lease
operating expenses associated with the operation of the acquired Amerada Hess
properties. On a BOE basis, lease operating expense was $3.47 per BOE for 1996
as compared to $2.95 per BOE in 1995. The increase in per BOE lease operating
expense was attributable to decreased production from existing wells without a
corresponding decrease in operating expense.

     Gross production taxes. Gross production taxes increased $0.5 million to
$1.8 million for 1996 from $1.3 million for 1995. The increase in gross
production taxes for 1996 was related to the increase in oil and gas sales for
1996. On a BOE basis, gross production taxes were $1.15 in 1996 and $1.13 in
1995.

     Depreciation, depletion and amortization expense. Depreciation, depletion
and amortization ("DD&A") expense for 1996 totaled $8.9 million as compared to
$7.4 million for 1995. The increase in DD&A is primarily attributable to the
increase in the Company's oil and natural gas properties subject to
amortization. The DD&A rate decreased to $5.59 per BOE for 1996, from $6.08 per
BOE for 1995. The decrease in DD&A per BOE resulted primarily from an increased
level of reserves at December 31, 1996.

     General and administrative expense. General and administrative expense
increased to $2.5 million for 1996 from $1.5 million for 1995. This increase
was primarily attributable to staffing increases and additional corporate
expenses to handle higher levels of activity following the July 1995 initial
public offering and the $32.1 million acquisition of properties from Amerada
Hess on May 31, 1996. On a BOE basis, general and administrative expenses
increased 23% from 1995 as compared to a 142% increase from 1994 to 1995.

     Interest expense. Interest expense increased to $1.6 million for 1996 from
$0.5 million for 1995 as a result of an increase in the average amount of debt
outstanding due to the acquisition of the Amerada Hess properties. (See Note 2
to the Consolidated Financial Statements.)

     Income before income taxes. Income before income taxes increased to $7.8
million for 1996 from $7.7 million for 1995, primarily due to the factors
described above, including increased oil and gas revenues due to the
acquisition of the Amerada Hess properties which were partially offset by the
decreased


                                      33

<PAGE>   36
revenues due to the dissolution of the CFJV and the increased interest and
general and administrative expense.

     Income taxes. The effective tax rate for 1996 was approximately 38%. The
deferred income tax expense for 1995 included a $11.5 million charge for a
required change in tax status from an S corporation (which is not taxed
directly) to a C Corporation (which is taxed directly) and, as such, the
effective tax rate for 1995 was not meaningful. (See Note 7 to the Consolidated
Financial Statements.)

     Net income (loss). Net income increased 3% to $4.9 million for 1996 from
$4.7 million for 1995 before the non-recurring deferred tax charge. The Company
incurred a non-recurring charge of $11.5 million for deferred income tax
expense in 1995, of which $9.9 million was attributed to periods prior to 1995.
As a result of this item, net income increased to $4.9 million for 1996 from a
loss of $5.2 million in 1995.


YEAR ENDED DECEMBER 31, 1995 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1994

     Revenues. Total revenues for the year ended December 31, 1995 were $22.1
million, a decrease of $1.1 million from $21.0 million in 1994. During 1994,
the Company recognized $3.3 million from a settlement of a natural gas sales
contract. Excluding the effect of this non-recurring item, total revenues for
1995 would have increased by $2.2 million. Production of oil and gas was 708
MBbl and 3,022 MMcf, respectively, in 1995, as compared to 663 MBbls and 3,187
MMcf, respectively, in 1994. The increase in equivalent barrel production was a
result of the completion of 19 wells in 1995. However, this production increase
was offset by a $0.16 and $0.11 decrease in the average price received per
barrel and Mcf to $17.45 and $1.82, respectively, during 1995. A $1.3 million
increase in revenues from gathering, dehydration and compression fees, and
demand charges under a contract which commenced in July 1994 also contributed
to the increase in total revenues. Also contributing to the increase in total
revenues were increases of $0.3 million of interest income, and $0.4 million of
other revenue that resulted from the termination of the Company's management
agreement with LEDCO in connection with the sale of LEDCO in January 1995.

     Lease operating expense. Lease operating expense decreased $0.9 million to
$3.6 million in 1995. On a BOE basis, lease operating expense decreased 21% in
1995 to $2.95 per BOE from $3.74 per BOE from $4.5 million in 1994. The
decrease in such expense primarily related to decreased saltwater disposal
expenses due to the Company's development of a saltwater disposal facility
located in the Ames Field. Previously, the Company had to transport the
saltwater to other disposal facilities further away.

     Gross Production Taxes. Gross production taxes increased $0.4 million to
$1.4 million in 1995. This increase was primarily due to the expiration of the
incremental tax credit for a waterflood project.

     Depreciation, depletion and amortization expense. DD&A increased $0.8
million to $7.4 million in 1995 from $6.6 million in 1994. The DD&A rate
increased to $6.08 per BOE for 1995, from $5.49 per BOE for 1994. The 11%
increase in DD&A per BOE resulted primarily from an increased level of capital
expenditures for proved reserves in 1995 as compared to 1994.

     General and administrative expense. General and administrative expense
increased $1.0 million to $1.5 million in 1995 from $0.5 million in 1994. This
increase was a result of the Company hiring


                                      34

<PAGE>   37
additional employees and taking larger working interest positions in its wells.
The Company had 50 employees at December 31, 1995 as compared to 35 employees
at December 31, 1994. Third-party operating reimbursements represented 15% of
gross general and administrative expense in 1995 as compared to 36% in 1994.
The Company received operating reimbursements from third-party working interest
participants which reduced overall general and administrative expense.

     Interest expense. Interest expense decreased to $0.5 million in 1995 from
$0.7 million in 1994 primarily as a result of fully paying down the Company's
credit facility with proceeds of the July 1995 equity offering.

     Income before income taxes. Due to the factors described above, primarily
the $3.3 million non-recurring natural gas contract settlement, income before
income taxes decreased 22% to $7.7 million in 1995 from $9.9 million in 1994.

     Income taxes. As a result of the Merger and termination of the Company's
Subchapter S election, the Company recognized a charge against operations in
the amount of $11.5 million for deferred income taxes in 1995. The charge
represented the tax effect of the difference between the financial statement
carrying values and the income tax bases of the Company's assets and
liabilities on the date the election was terminated. This expense is a non-cash
expense. Approximately $9.9 million of the 1995 provision relates to financial
and tax differences generated prior to 1995. The Company's effective tax rate
after removing the impact of the differences generated prior to 1995 was
approximately 39% which is comparable to the 40% estimated tax rate used in
calculating pro forma income taxes in 1994.

     Net income (loss). Primarily as a result of the recognition of income
taxes in 1995, a net loss of $5.2 million was incurred. During 1994, net income
(after pro forma income taxes) was $5.9 million.


CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY

     The following summary table presents comparative cash flows of the Company
for each of the three years ended December 31, 1996.

<TABLE>
<CAPTION>
                                                    YEAR ENDED DECEMBER 31,
                                                ------------------------------
                                                  1996       1995       1994
                                                --------   --------   --------
                                                        (IN THOUSANDS)
<S>                                             <C>        <C>        <C>
Net cash provided by operating activities       $ 19,559   $ 13,395   $ 17,261

Net cash used in investing activities            (66,831)   (19,618)   (25,367)

Net cash provided by financing activities         37,019     17,477      6,690
</TABLE>

     As of December 31, 1996, the Company had cash balances of $4.1 million and
working capital of $1.2 million. The decrease in working capital to $1.2
million as of December 31, 1996, from $13.7 million as of December 31, 1995,
reflects the increased level of capital expenditures during 1996. The increase
in working capital to $13.7 million as of December 31, 1995, from $0.8 million
as of December 1994, reflected the net proceeds of $15.7 million from the July
1995 public offering of common stock after debt repayment. For 1996, net cash
provided by operating activities was $19.6 million, as compared to $13.4
million in 1995. The increase in net cash provided by operating activities in
1996 relates primarily to the


                                      35

<PAGE>   38
timing of receipts and disbursements relating to working capital as the
Company's income before income taxes was substantially similar for 1996 and
1995.

     Net cash used in investing activities was $66.8 million in 1996 as
compared to $19.6 million in 1995. This increase of $47.2 million in 1996 was
primarily related to the acquisition of the Amerada Hess properties for $32.1
million, the acquisition of senior unsecured notes and other credit obligations
of WRT Energy for $7.9 million (see Item 1. "Business - WRT Energy") and the
acquisition of a 20.8% equity interest in WBL for $3.2 million. (See Item 1.
"Business - Areas of Future Exploration and Development Activities -
Barbados.")


     The majority of the $19.6 million spent on capital expenditures in 1995
related to exploration and production activity with $4.0 million for seismic
surveys and other preliminary costs. During 1994, the Company expended the
majority of the $25.4 million of capital expenditures on exploration and
production activity. Additionally, the Company spent $8.5 million for property
acquisitions including $2.1 million for producing properties and $6.0 million
for undeveloped leaseholds through the net acquisition of additional interests
in the Ames Field.

     During 1996, net cash provided by financing activities rose to $37.0
million as compared to $17.5 million in 1995. This increase was due to
borrowings under the 1995 credit facility during 1996. In 1995, the amounts
provided by financing activities primarily consisted of the proceeds of the
July 1995 issuance of common stock after payment of debt.

     Capital expenditures. The Company's capital expenditures to date have
focused primarily on the exploration, acquisition and development of oil and
gas properties. The following table sets forth the Company's expenditures for
exploration, development and property acquisitions for each of the three years
ended December 31, 1996. The table includes costs of oil and gas properties not
subject to amortization, which consist of the cost of undeveloped leaseholds,
wells-in-progress and secondary recovery projects before the assignment of
proved reserves.


                                      36

<PAGE>   39

                                                      YEAR ENDED DECEMBER 31,
                                                    ----------------------------
                                                      1996      1995      1994
                                                    --------  --------  --------
                                                            (IN THOUSANDS)
Exploration costs                                   $  9,605  $ 12,482  $  8,551

Development costs                                     11,503     5,884     7,688

Property acquisition costs                            34,476        39     8,849
                                                    ========  ========  ========
             Total                                  $ 55,584  $ 18,405  $ 25,088
                                                    ========  ========  ========


     During 1996, the Company financed its capital expenditures with cash flow
provided by operations, borrowings under the Company's 1995 credit facility and
the remainder of the net proceeds from the Company's July 1995 equity offering.
Prior to the equity offering, the Company financed its capital expenditures
through shareholder contributions and borrowings under the 1995 Credit
Facility. The Company has budgeted $66.0 million for capital expenditures
in 1997. It is currently anticipated that up to $45.9 million of such amount
will be used as follows: (i) $19.3 million in connection with the Texaco
Acquisition, consisting of $12.3 million for the acquisition of the WCBB
Assets, $6.0 million for the purchase of the Texaco Claims and $1.0 million for
payments to the P&A Trust; (ii) $12.7 million for the Bonray Acquisition; (iii)
$3.8 million for the workover and enhancement of certain rigs acquired in the
Bonray Acquisition; and (iv) from $2.4 million to $9.3 million will be used to
purchase shares of common stock of the new WRT Energy in the Rights Offering,
pursuant to the Company's commitment in the WRT Plan, if approved (v) and
$0.8 million for the purchase of additional claims against WRT Energy. As of
March 26, 1997, approximately $34.0 million had been expended by the Company in
connection with the foregoing activities. Also included in the Company's budget
is up to $27.0 million for oil and gas exploration activities of which $13.0
million is for exploratory wells and $14.0 million is for development wells.
The aggregate level of capital expenditures in 1997 for drilling activities and
the allocation thereof is highly dependent upon the Company's success rate on
exploration drilling and prevailing conditions in the oil and gas industry as
well as the amount of common stock of the New WRT Energy that the Company is
required to purchase in the Rights Offering. Accordingly, the actual level of
capital expenditures and the allocation of such expenditures may vary
materially from the above estimates.

     Capital Resources. Prior to the July 1995 equity offering, the Company's
cash requirements had been met primarily through capital contributions from
shareholders, cash generated from operations and borrowings under credit
facilities.


                                      37

<PAGE>   40


     As of December 31, 1996, $37.2 million was outstanding under the 1995
credit facility. The 1995 credit facility was structured as a revolving loan
agreement providing for aggregate borrowings of up to $60.0 million. Borrowings
under the 1995 credit facility bore interest, at the banks' prime, floating, or
the London Interbank Offered Rate ("LIBOR") plus 176 basis points or a pricing
grid with the rate determined by the percentage of the borrowing base
commitment outstanding. Principal payments on the credit facility were due at
maturity in October 2000, or when any amounts outstanding thereunder were in
excess of the borrowing base. Interest payments were due quarterly. The credit
facility was collateralized by a mortgage on the Company's producing and
non-producing oil and gas properties and contained restrictive covenants
requiring, among other things, that the Company (i) maintained specific levels
of tangible net worth and working capital, (ii) met specific financial ratios
and (iii) limit the payment of dividends or distributions to shareholders.

     On March 5, 1997, the Company established a new revolving credit facility
with a group of financial institutions, which, as amended, provides for
aggregate borrowings of up to $85.0 million (the "1997 Credit Facility").
Borrowings under the 1997 Credit Facility were used to refinance indebtedness
under the 1995 credit facility and to fund the Texaco Acquisition.

     Under the terms of the 1997 Credit Facility, interest is charged at the
higher of the bank's prime rate plus 50 basis points plus the applicable margin
or the rate at which Eurodollar deposits for one, two, three, six or twelve
months are offered to the bank in the Interbank Eurodollar market plus the
applicable margin. Loans made under the 1997 Credit Facility are payable in
full on March 2002, the maturity date. The 1997 Credit Facility is secured by
substantially all of the Company's assets and contains similar restrictive
covenants to those described above relating to the 1995 credit facility. As of
March 19, 1997, outstanding borrowings under the 1997 Credit Facility were $78.5
million.

     Liquidity. The Company intends to meet the remainder of its 1997 capital
requirements and its other obligations primarily from existing cash balances,
cash flow from operations and borrowings under the 1997 Credit Facility. The
Company's cash flow from operations will be dependent upon its future
performance, which will be subject to prevailing economic conditions and to
financial and business conditions and other factors, many of which are beyond
its control. In addition, as a result of borrowings under the 1997 Credit
Facility to fund the Texaco Acquisition, the Company had $1.5 million of
available borrowing capacity under such facility. Management believes that
additional financing will be required to fully implement its proposed 1997
capital budget and has commenced discussions with the lenders under the 1997
credit facility to increase the Company's borrowing capacity thereunder to
address it near-term liquidity requirements. The Company also intends to seek
additional capital through offerings of debt and/or equity securities. There
can be no assurance, however, that the lenders will increase the borrowing
limits under the 1997 credit facility or that such offerings can be
successfully completed. Should sufficient financing not be available from these
or other sources, implementation of the Company's 1997 capital program would be
delayed and, accordingly, the Company's growth strategy could be adversely
affected.


                                      38

<PAGE>   41
     The Company does not intend to pay dividends on its common stock in the
near future. Earnings generated will be redeployed by the Company as it
continues its growth strategies.

     In future periods, the Company expects to recognize deferred income taxes
of approximately 37% to 39% of income before income taxes. The majority of the
Company's income tax expense is expected to be recognized as deferred income
tax expense due to the current tax treatment of oil and gas exploration costs.

     Impact of Recently Issued Accounting Standards Not Yet Adopted. In June,
1996, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standard No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities" ("SFAS No. 125"). SFAS No.
125 is effective for certain transfers and servicing of financial assets and
extinguishment of liabilities occurring after December 31, 1996. It is
effective for other transfers of financial assets occurring after December 31,
1997. It is to be applied prospectively. SFAS No. 125 provides accounting and
reporting standards for transfers and servicing of financial assets and
extinguishment of liabilities based on consistent application of a financial
components approach that focuses on control. It distinguishes transfers of
financial assets that are sales from transfers that are secured borrowings.
Management of DLB does not expect that adoption of SFAS No. 125 will have a
material impact on DLB's financial position or results of operations.

     In October 1996, the American Institute of Certified Public Accountants
issued Statement of Position (SOP) 96-1, "Environmental Remediation
Liabilities." SOP 96-1 was adopted by DLB on January 1, 1997. It requires,
among other things, that environmental remediation liabilities be accrued when
the criteria of SFAS No. 5, "Accounting for Contingencies," have been met. SOP
96-1 also provides guidance with respect to the measurement of the remediation
liabilities. Such accounting is consistent with DLB's current method of
accounting for environmental remediation costs. Therefore, adoption of SOP 96-1
will not have a material impact on DLB's financial position or results of
operations.


                                      39

<PAGE>   42
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The information required by this item appears on pages F-1 through F-27
following the signature pages of this Report.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
         AND FINANCIAL DISCLOSURE

     None.


                                    PART III

     For information concerning Item 10 - Directors and Executive Officers of
the Registrant, Item 11 - Executive Compensation, Item 12 - Security Ownership
of Certain Beneficial Owners and Management and Item 13 - Certain Relationships
and Related Transactions, see the definitive Proxy Statement of DLB Oil & Gas,
Inc. for the Annual Meeting of Shareholders to be held on May 21, 1997, which
will be filed with the Securities and Exchange Commission within 120 days after
the close of the Registrant's year end and is incorporated herein by this
reference (with the exception of portions noted therein that are not
incorporated by reference). See also Part I - Item 4A - Executive Officers of
the Registrant.


                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

     (a)  1. Financial Statements. The following Consolidated Financial
          Statements of the Company and its subsidiaries, the Notes thereto,
          and the reports thereon are filed under Item 8 of this Report.

          Independent Auditors' Report ...............................  F-2

          Consolidated Balance Sheets, December 31, 1996 and 1995 ....  F-3

          Consolidated Statements of Operations, Years Ended
            December 31, 1996, 1995 and 1994 .........................  F-4


          Consolidated Statements of Shareholders' Equity, Years
            Ended December 31, 1996, 1995 and 1994 ...................  F-5

          Consolidated Statements of Cash Flows, Years Ended
            December 31, 1996, 1995 and 1994 .........................  F-6

          Notes to Consolidated Financial Statements .................  F-7


          2. Financial Statement Schedules. All financial statement schedules
          have been omitted, as the required information is inapplicable or is
          not present in amounts sufficient to require submission of the
          schedule or the information is presented in the Consolidated
          Financial Statements or the related notes.


                                      40

<PAGE>   43
          3. Exhibits.

              2.0   Agreement for Purchase and Sale dated April 16, 1996,
                    between Amerada Hess Corporation and DLB Oil & Gas, Inc.
                    (the "Agreement for Purchase and Sale").(4)

              2.1   Letter agreement amending Agreement for Purchase and Sale
                    dated May 7, 1996.(3)

              2.2   Letter agreement amending Agreement for Purchase and Sale
                    dated May 31, 1996.(3)

              3.1   Amended and Restated Certificate of Incorporation(1)

              3.2   Amended and Restated Bylaws(1)

              10.1  Lease of office space, Oklahoma City, Oklahoma(1)

              10.2  Credit Agreement dated December 28, 1995, between
                    Registrant and First Union National Bank of North
                    Carolina(2)

              10.3  Stock Option Agreement by and between Registrant and Mike
                    Liddell(1)

              10.4  Stock Option Agreement by and between Registrant and Mark
                    Liddell(1)

              10.5  Employment Agreement by and between Registrant and Mike
                    Liddell(1)

              10.6  Employment Agreement by and between Registrant and Mark
                    Liddell(1)

              10.7  DLB Oil & Gas Stock Option Plan(1)

              10.8  DLB Oil & Gas Omnibus Equity Compensation Plan(1)

              10.9  Shareholder's Agreement by and among Charles E. Davidson,
                    Mike Liddell and Mark Liddell dated May 25, 1995(1)

              10.10 Agreement for Dissolution of Joint Venture dated February
                    9, 1996, between DLB Oil & Gas, Inc., Magic Circle
                    Acquisition Corporation and Magic Circle Energy
                    Corporation, Carmen Field Limited Partnership, and Carmen
                    Field Joint Venture(2)

              10.11 First Amendment to the Credit Agreement dated June 30,
                    1996, between Registrant and First Union National Bank of
                    North Carolina(4)

              10.12 Credit Agreement Dated as March 5, 1997 between registrant
                    and Chase Manhattan Bank

              10.13 Second Amended Disclosure Statement Under 11 U.S.C.
                    Section 1125 in Support of Debtor and DLBW's Second Amended
                    Joint Plan of Reorganization Under Chapter 22 of the United
                    States Bankruptcy Code

              10.14 Texaco Agreements

              21.0  Subsidiaries of the Company(1)

-----------------

               (1)  Previously filed as an exhibit to Registration No. 33-92786
                    on Form S-1 and incorporated herein by reference.

               (2)  Previously filed as an exhibit to Form 10-K for the year
                    ended December 31, 1995, and incorporated herein by
                    reference.

               (3)  Previously filed as an exhibit to Form 8-K on May 12, 1996,
                    and incorporated herein by reference.

               (4)  Previously filed as an exhibit to Form 10-Q filed on August
                    14, 1996.

               (5)  Pursuant to Item 601(b)(2) of Regulation S-K, the exhibits
                    and schedules to Exhibit 2.0 are omitted. Exhibit 2.0
                    contains a list identifying the contents of its exhibits
                    and schedules, and registrant agrees to furnish
                    supplemental copies of such exhibits and schedules to the
                    Securities and Exchange Commission upon request.

     (b)  Reports on Form 8-K.

          February 7, 1997  Bonray Acquisition


                                      41

<PAGE>   44
                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                                DLB OIL & GAS, INC.



Date:  March 28, 1997          By:  /s/ Mike Liddell
                                   -------------------------------------------
                                   Mike Liddell, Chief Executive Officer


         Pursuant to the requirements of 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.


Date:  March 28, 1997               /s/ Charles E. Davidson
                                    -------------------------------------------
                                    Charles E. Davidson, Chairman of the Board

Date:  March 28, 1997               /s/ Mike Liddell
                                    -------------------------------------------
                                    Mike Liddell, Director

Date:  March 28, 1997               /s/ Mark Liddell
                                    -------------------------------------------
                                    Mark Liddell, Director

Date:  March 28, 1997               /s/ Joel-Andre Ornstein
                                    -------------------------------------------
                                    Joel-Andre Ornstein, Director

Date:  March 28, 1997               /s/ David A. Rogath
                                    -------------------------------------------
                                    David A. Rogath, Director

Date:  March 28, 1997               /s/ Martin L. Solomon
                                    -------------------------------------------
                                    Martin L. Solomon, Director

Date:  March 28, 1997               /s/ Ronald D. Youtsey
                                    -------------------------------------------
                                    Ronald D. Youtsey, Senior Vice President,
                                      Chief Financial Officer and Treasurer
                                    (Principal Accounting and Financial Officer)


                                      42
<PAGE>   45
                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


<TABLE>
<CAPTION>
                                                                   Page
                                                                   ----
<S>                                                                <C>
Independent Auditors' Report ....................................  F-2

Consolidated Balance Sheets, December 31, 1996 and 1995 .........  F-3

Consolidated Statements of Operations, Years Ended
  December 31, 1996, 1995 and 1994 ..............................  F-4

Consolidated Statements of Shareholders' Equity, Years Ended
  December 31, 1996, 1995, and 1994 .............................  F-5

Consolidated Statements of Cash Flows, Years Ended
  December 31, 1996, 1995 and 1994 ..............................  F-6

Notes to Consolidated Financial Statements ......................  F-7
</TABLE>

All financial statement schedules are omitted, as the required information is
inapplicable or the information is presented in the consolidated financial
statements or related notes.


                                      F-1
<PAGE>   46

                          INDEPENDENT AUDITORS' REPORT




The Board of Directors
DLB Oil & Gas, Inc.:


     We have audited the consolidated financial statements of DLB Oil & Gas,
Inc. (as described in Note 1) as listed in the accompanying index. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of DLB Oil &
Gas, Inc. as of December 31, 1996 and 1995, and the results of its operations
and its cash flows for each of the years in the three year period ended
December 31, 1996, in conformity with generally accepted accounting principles.



                                                KPMG Peat Marwick LLP


Oklahoma City, Oklahoma
March 12, 1997


                                      F-2
<PAGE>   47

                              DLB OIL & GAS, INC.
                          CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                            DECEMBER 31,
                                                                    ----------------------------
                                                                        1996           1995
                                                                    -------------   ------------
                                     ASSETS
<S>                                                                 <C>             <C>
Current assets:
     Cash and cash equivalents                                      $   4,060,000   $ 14,313,000
     Accounts receivable                                                8,998,000      4,850,000
     Prepaid expenses                                                     337,000        324,000
                                                                    -------------   ------------
                Total current assets                                   13,395,000     19,487,000
                                                                    -------------   ------------
Property and equipment - at cost, based on the full cost
     method of accounting for oil and natural gas properties:
        Oil and natural gas properties subject to amortization        109,325,000     62,275,000
        Oil and natural gas properties not subject to amortization     18,570,000     10,037,000
        Natural gas processing plants and gathering systems             1,728,000      3,094,000
        Saltwater disposal system                                       1,119,000      1,119,000
        Other property and equipment                                    1,223,000        948,000
                                                                    -------------   ------------
                                                                      131,965,000     77,473,000
        Accumulated depreciation, depletion and amortization          (27,007,000)   (18,812,000)
                                                                    -------------   ------------
                                                                      104,958,000     58,661,000
                                                                    -------------   ------------
Investment in Waggoner (Barbados) Ltd.                                  3,186,000             --
Other assets                                                            7,902,000         59,000
                                                                    -------------   ------------
                        Total assets                                $ 129,441,000   $ 78,207,000
                                                                    =============   ============

                      LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
     Trade accounts payable                                         $   8,119,000   $  3,853,000
     Revenue and royalty distributions payable                          3,125,000      1,527,000
     Drilling advances and other liabilities                               42,000        190,000
     Accrued liabilities                                                  872,000        193,000
                                                                    -------------   ------------
                Total current liabilities                              12,158,000      5,763,000
                                                                    -------------   ------------

Long-term debt                                                         37,200,000             --

Deferred income taxes                                                  15,851,000     12,900,000

Shareholders' equity:
     Preferred stock, 5,000,000 shares authorized; no shares
        issued                                                                 --             --
     Common stock, 130,000,000 shares authorized; 13,000,000
        shares issued; 12,975,000 and 13,000,000 outstanding at
        December 31, 1996 and December 31 1995, respectively               13,000         13,000
     Treasury stock, at cost                                             (181,000)            --
     Additional paid in capital                                        57,910,000     57,910,000
     Retained earnings                                                  6,490,000      1,621,000
                                                                    -------------   ------------
                Total shareholders' equity                             64,232,000     59,544,000
Commitments and contingencies
                                                                    -------------   ------------
                        Total liabilities and shareholders' equity  $ 129,441,000   $ 78,207,000
                                                                    =============   ============
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-3
<PAGE>   48
                              DLB OIL & GAS, INC.
                     CONSOLIDATED STATEMENTS OF OPERATIONS


<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                               ---------------------------------------
                                                  1996          1995          1994
                                               -----------  ------------   -----------
<S>                                            <C>          <C>            <C>
Revenues:
     Oil and natural gas sales                 $27,194,000  $ 17,860,000   $17,826,000
     Natural gas gathering, processing
         and transportation, net                   821,000     3,293,000     1,652,000
     Natural gas contract settlement                    --            --     3,343,000
     Interest income                               355,000       469,000       140,000
     Other                                          45,000       430,000       194,000
                                               -----------  ------------   -----------
                                                28,415,000    22,052,000    23,155,000

Expenses:
     Lease operating                             5,539,000     3,579,000     4,461,000
     Gross production taxes                      1,843,000     1,366,000     1,009,000
     Depreciation, depletion and amortization    8,938,000     7,368,000     6,553,000
     General and administrative                  2,485,000     1,486,000       549,000
     Interest                                    1,582,000       529,000       677,000
     Loss on sale of assets                        208,000            --            --
                                               -----------  ------------   -----------
                                                20,595,000    14,328,000    13,249,000
                                               -----------  ------------   -----------

Income before income taxes                       7,820,000     7,724,000     9,906,000

Pro forma income taxes                                  --            --     3,962,000
Income taxes                                     2,951,000    12,900,000            --
                                               ===========  ============   ===========
Net income (loss)                              $ 4,869,000  $ (5,176,000)  $ 5,944,000
                                               ===========  ============   ===========
Net income (loss) per common share             $      0.38  $      (0.46)  $      0.59
                                               ===========  ============   ===========

Weighted average common
     shares outstanding                         12,978,000    11,250,000    10,000,000
                                               ===========  ============   ===========
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-4
<PAGE>   49
                               DLB OIL & GAS, INC
                CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                                                        ADDITIONAL
                                               NO. OF        COMMON      TREASURY        PAID-IN
                                               SHARES        STOCK         STOCK         CAPITAL
                                            ------------  ------------  ------------   ------------
<S>                                         <C>           <C>           <C>            <C>
Balance, December 31, 1993                            --  $         --  $         --   $         --
   Income before income taxes                         --            --            --             --
   Contributed capital                                --            --            --             --
   Distributions to shareholders                      --            --            --             --

Balance, December 31, 1994                            --            --            --             --
   Contributed capital                                --            --            --             --
   Distributions to shareholders                      --            --            --             --
   Pre-public offering net loss                       --            --            --             --
   Issuance of stock in connection with
      merger of Davidson Oil and Gas, Inc.    10,000,000        10,000            --     31,017,000
   Sale of stock in connection with
      public offering, net of costs            3,000,000         3,000            --     26,893,000
   Post-public offering net income                    --            --            --             --
                                            ------------  ------------  ------------   ------------
Balance, December 31, 1995                    13,000,000        13,000            --     57,910,000
   Purchase of treasury stock                         --            --      (181,000)            --
   Net income                                         --            --            --             --
                                            ------------  ------------  ------------   ------------
Balance, December 31, 1996                    13,000,000  $     13,000  $   (181,000)  $ 57,910,000
                                            ============  ============  ============   ============

<CAPTION>
                                                                           COMBINED
                                              RETAINED                   SHAREHOLDERS'
                                              EARNINGS       TOTAL          EQUITY
                                            ------------  ------------   ------------
<S>                                         <C>           <C>            <C>
Balance, December 31, 1993                  $         --  $         --   $ 30,164,000
   Income before income taxes                         --            --      9,906,000
   Contributed capital                                --            --      2,138,000
   Distributions to shareholders                      --            --     (3,196,000)
                                            ------------  ------------   ------------
Balance, December 31, 1994                            --            --     39,012,000
   Contributed capital                                --            --          4,000
   Distributions to shareholders                      --            --     (1,192,000)
   Pre-public offering net loss                       --            --     (6,797,000)
   Issuance of stock in connection with
      merger of Davidson Oil and Gas, Inc.            --    31,027,000    (31,027,000)
   Sale of stock in connection with
      public offering, net of costs                   --    26,896,000             --
   Post-public offering net income             1,621,000     1,621,000             --
                                            ------------  ------------   ------------
Balance, December 31, 1995                     1,621,000    59,544,000             --
   Purchase of treasury stock                         --      (181,000)            --
   Net income                                  4,869,000     4,869,000             --
                                            ------------  ------------   ------------
Balance, December 31, 1996                  $  6,490,000  $ 64,232,000   $         --
                                            ============  ============   ============
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-5
<PAGE>   50
                               DLB OIL & GAS, INC
                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                          YEAR ENDED DECEMBER 31,
                                                               ------------------------------------------
                                                                   1996           1995           1994
                                                               ------------   ------------   ------------
<S>                                                            <C>            <C>            <C>
Cash flows from operating activities:
    Net income (loss)                                          $  4,869,000   $ (5,176,000)  $  5,944,000
    Adjustments to reconcile net income (loss)
         to net cash provided by operating activities:
            Depreciation, depletion, and amortization             8,938,000      7,368,000      6,553,000
            Pro forma income taxes                                       --             --      3,962,000
            Deferred income taxes                                 2,951,000     12,900,000             --
            Loss on sale of assets                                  208,000             --             --
            Increase in accounts receivable                      (3,789,000)      (676,000)    (1,524,000)
            (Increase) decrease in prepaid expenses                 (13,000)        14,000        (35,000)
            Increase (decrease) in accounts payable,
                distributions payable and accrued liabilities     6,543,000       (865,000)     2,459,000
            Decrease in drilling advances                          (148,000)      (170,000)       (98,000)
                                                               ------------   ------------   ------------
                Net cash provided by operating activities        19,559,000     13,395,000     17,261,000
                                                               ------------   ------------   ------------

Cash flows from investing activities:
    Expenditures for property and equipment                     (57,165,000)   (19,852,000)   (26,291,000)
    Proceeds from sale of property and equipment                  1,399,000        234,000             --
    Purchase of investments and other assets                    (11,065,000)            --        (42,000)
    Collection of note receivable                                        --             --        966,000
                                                               ------------   ------------   ------------
                Net cash used in investing activities           (66,831,000)   (19,618,000)   (25,367,000)
                                                               ------------   ------------   ------------

Cash flows from financing activities:
    Proceeds of long-term debt                                   37,200,000      3,000,000     15,751,000
    Payments of long-term debt                                           --    (11,231,000)    (8,003,000)
    Contributed capital                                                  --          4,000      2,138,000
    Distributions to shareholders                                        --     (1,192,000)    (3,196,000)
    Proceeds from issuance of stock                                      --     26,896,000             --
    Purchase of treasury stock                                     (181,000)            --             --
                                                               ------------   ------------   ------------
                Net cash provided by financing activities        37,019,000     17,477,000      6,690,000
                                                               ------------   ------------   ------------

Net increase (decrease) in cash and cash equivalents:           (10,253,000)    11,254,000     (1,416,000)
Cash and cash equivalents beginning of year                      14,313,000      3,059,000      4,475,000
                                                               ------------   ------------   ------------
Cash and cash equivalents end of year                          $  4,060,000   $ 14,313,000   $  3,059,000
                                                               ============   ============   ============

Supplemental cash flow information:
    Cash payments for interest                                 $  1,403,000   $    541,000   $    551,000
                                                               ============   ============   ============

Supplemental schedule of noncash investing activities:
    Property and equipment received from
         settlement of contingency                             $    231,000   $         --   $         --
                                                               ============   ============   ============
</TABLE>


See accompanying notes to consolidated financial statements.


                                      F-6
<PAGE>   51
                              DLB OIL & GAS, INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        DECEMBER 31, 1996, 1995 AND 1994


(1)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     ORGANIZATION, DESCRIPTION OF BUSINESS AND PRINCIPALS OF CONSOLIDATION

     DLB Oil & Gas, Inc. (DLB or the Company) engages primarily in the
     exploration for and development of crude oil and natural gas properties.
     The Company focuses its efforts and is an active explorer in Oklahoma and
     Kansas. The Company also engages to a lesser extent, in the gathering,
     processing, transportation and marketing of hydrocarbons.

     The accompanying consolidated financial statements covering periods prior
     to July 20, 1995, the date of the merger of Davidson Oil and Gas, Inc.
     (Davidson) into DLB, include each of their accounts and their
     proportionate share of a venture involved in the production of oil and
     natural gas and in the gathering, processing and transportation of natural
     gas. Due to the nature of a joint venture agreement between the Company
     and Davidson, the Company and Davidson were considered to be under common
     control prior to the merger. Accordingly, the merger of Davidson into DLB
     was accounted for as a reorganization of interests under common control in
     a manner similar to a pooling of interests.

     The accompanying consolidated financial statements covering periods on or
     after July 20, 1995, include the consolidated accounts of the Company and
     its wholly owned subsidiaries, and its proportionate share of a venture
     involved in the production of oil and natural gas and in the gathering,
     processing and transportation of natural gas. The Company accounts for its
     investment in Waggoner (Barbados) Ltd. using the equity method of
     accounting. All significant intercompany transactions and balances have
     been eliminated in consolidation.

     CASH AND CASH EQUIVALENTS

     For purposes of the consolidated statements of cash flows, the Company
     considers all short-term debt securities purchased with a maturity of
     three months or less to be cash equivalents.

     PROPERTY AND EQUIPMENT

     The Company accounts for its oil and natural gas exploration and
     development activities using the full cost method of accounting.
     Accordingly, all costs including nonproductive costs and certain general
     and administrative costs associated with acquisition, exploration and
     development of oil and natural gas properties are capitalized. Net
     capitalized costs are limited to the estimated future net revenues, after
     income taxes, discounted at 10% per year, from proved oil and natural gas
     reserves and


                                      F-7
<PAGE>   52
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     the cost of properties not subject to amortization. Such capitalized costs
     including the estimated future development costs and site remediation
     costs, if any, are depleted by an equivalent units-of-production method,
     converting natural gas to barrels at the ratio of six Mcf of natural gas
     to one barrel of oil. No gain or loss is recognized upon disposal of oil
     and natural gas properties, unless such dispositions significantly alter
     the relationship between capitalized costs and proved oil and natural gas
     reserves. The cost of natural gas processing plants and gas gathering
     systems is also being depreciated on the units-of-production method. The
     cost of other property and equipment, including the saltwater disposal
     system, is depreciated over estimated useful lives of five to seven years.

     Oil and natural gas properties not subject to amortization consist of the
     cost of undeveloped leaseholds, exploratory and developmental wells in
     progress, and secondary recovery projects before the assignment of proved
     reserves. These costs are reviewed periodically by management for
     impairment, with the impairment provision included in the cost of oil and
     natural gas properties subject to amortization. Factors considered by
     management in its impairment assessment include drilling results by the
     Company and other operators, the terms of oil and gas leases not held by
     production, production response to secondary recovery activities and
     available funds for exploration and development.

     The Company adopted the provisions of Statement of Financial Accounting
     Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and
     for Long-Lived Assets to be Disposed of," on January 1, 1996. SFAS No. 121
     requires that long-lived assets and certain identifiable intangibles be
     reviewed for impairment whenever events or changes in circumstances
     indicate that the carrying amount of an asset may not be recoverable. Due
     to the Company's use of the full cost method of accounting for its oil and
     gas properties, SFAS No. 121 does not apply to the Company's oil and gas
     property assets which comprise approximately 97% of the Company's net
     property and equipment. Accordingly, the adoption of SFAS No. 121 did not
     have an impact on the Company's financial position or results of
     operations in 1996.

     INVESTMENTS AND OTHER ASSETS

     The Company's investment in Waggoner (Barbados) Ltd. is accounted for by
     the equity method. Other assets, including securities of WRT Energy
     Corporation, are accounted for at cost.

     REVENUE AND ROYALTY DISTRIBUTIONS PAYABLE

     For certain oil and gas properties, the Company receives production
     proceeds from the purchaser and further distributes such amounts to other
     revenue and royalty owners. Production proceeds applicable to other
     revenue and royalty owners are reflected as revenue and royalty
     distributions payable in the accompanying consolidated balance sheets. The
     Company accrues revenue for only its net revenue interest in its oil and
     natural gas properties.


                                      F-8
<PAGE>   53
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     NATURAL GAS IMBALANCES

     Natural gas production imbalances arise during the course of production
     from properties when owners produce more natural gas than their
     proportionate share of reserves. The Company utilizes the sales method of
     accounting for natural gas imbalances and, accordingly, has recognized
     revenue on all production delivered to its purchasers. As long as the
     remaining reserves of the properties are sufficient for the underproduced
     owners to recoup their share of production, no cash repayment by the
     Company will be required. If the recoverable reserves are insufficient for
     the underproduced owners to recoup their share of production, the Company
     records a liability for the repayment of its share of overproduction. No
     receivables are recorded for those wells where the Company has taken less
     than its ownership share of natural gas production.

     COMMITMENTS AND CONTINGENCIES

     Liabilities for loss contingencies arising from claims, assessments,
     litigation or other sources are recorded when it is probable that a
     liability has been incurred and the amount can be reasonably estimated.

     In October 1996, the American Institute of Certified Public Accountants
     issued Statement of Position (SOP) 96-1, "Environmental Remediation
     Liabilities." SOP 96-1 was adopted by the Company on January 1, 1997. It
     requires, among other things, that environmental remediation liabilities
     be accrued when the criteria of SFAS No. 5, "Accounting for
     Contingencies," have been met. SOP 96-1 also provides guidance with
     respect to the measurement of the remediation liabilities. Such accounting
     is consistent with the Company's method of accounting for environmental
     remediation costs. Therefore, adoption of SOP 96-1 will not have a
     material impact on the Company's financial position or results of
     operations.

     OTHER REVENUES

     Included in other revenues in the 1995 consolidated statement of
     operations is $370,000 for amounts received for the management of an
     intrastate pipeline company engaged in the gathering, transmission and
     marketing of natural gas. Earlier years did not include significant
     revenues associated with management fees. This management agreement
     terminated in February 1995 upon sale of the intrastate pipeline company
     by its owners.

     GENERAL AND ADMINISTRATIVE EXPENSES

     General and administrative expenses are reported net of amounts charged to
     other working interest owners of the oil and natural gas properties
     operated by the Company, and net of general and administrative expenses
     capitalized by the Company as relating to its property exploration and
     development activities.


                                      F-9
<PAGE>   54
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     INCOME TAXES

     Income taxes are accounted for under the asset and liability method.
     Deferred tax assets and liabilities are recognized for the future tax
     consequences attributable to differences between the financial statement
     carrying amounts of existing assets and liabilities and their respective
     tax bases and operating loss and tax credit carryforwards. Deferred tax
     assets and liabilities are measured using enacted tax rates expected to
     apply to taxable income in the years in which those temporary differences
     are expected to be recovered or settled. The effect on deferred tax assets
     and liabilities of a change in tax rates is recognized in income in the
     period that includes the enactment date.

     NET INCOME (LOSS) PER COMMON SHARE

     Net income (loss) per common share is based upon the number of common
     shares considered outstanding during each period after giving effect to
     the merger of Davidson and the Company, as of the beginning of the
     earliest period presented. Subsequent to the initial public offering of
     the Company's common stock, net income (loss) per common share is based
     upon the weighted average number of shares of common stock outstanding for
     the year.

     For the year end December 31, 1996, shares represented by granted stock
     options were not included in the net income per common share calculations
     as the option price was in excess of the trading price of the Company's
     securities. For the year ended December 31, 1995, shares represented by
     granted stock options were antidilutive to the net income (loss) per
     common share calculation.

     STOCK OPTIONS

     With regard to the Company's stock options granted, no accounting is made
     until such time as the options are exercised, in that the option price
     equaled the market value of the option at the date of the grant. Upon
     exercise, the proceeds are added to stockholders' equity, and no expense
     is recognized. Statement of Financial Accounting Standards No. 123
     "Accounting for Stock Issued to Employees" provides companies with the
     option of expensing the "fair value" of stock options granted. The Company
     has elected not to change its current accounting method regarding stock
     options, and therefore SFAS No. 123 did not impact the Company's 1996
     operating results. The Company has adopted the expanded disclosure
     requirements for stock options in 1996.

     FAIR VALUE OF FINANCIAL INSTRUMENTS

     The Company's financial instruments consist of cash and cash equivalents,
     trade receivables, payables and long-term debt. As of December 31, 1996
     and 1995, the consolidated financial statement carrying values of the
     Company's financial instruments, approximate their respective estimated
     fair value, because of the short maturity or the frequent interest rate
     repricing of these instruments.


                                     F-10
<PAGE>   55
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     DERIVATIVE FINANCIAL INSTRUMENTS

     The Company has utilized derivative financial instruments, in the form of
     futures contracts, on a limited basis to manage or hedge price risk
     associated with oil and gas production. The Company does not utilize
     derivative financial instruments for trading purposes. Gains and losses
     attributable to the Company's hedging activities are recorded as increases
     and decreases in oil and gas sales when the futures contracts are closed.
     When a futures contract ceases to qualify as a hedge, the change in fair
     value is reflected in operations at that time.

     USE OF ESTIMATES

     Management of the Company has made a number of estimates and assumptions
     relating to the reporting of assets and liabilities, the disclosure of
     contingent assets and liabilities, and the reported amounts of revenues
     and expenses during the reporting periods, to prepare these consolidated
     financial statements in conformity with generally accepted accounting
     principles. Actual results could differ from those estimates.

     RECLASSIFICATIONS

     Certain reclassifications have been made to the 1995 and 1994 financial
     statements to conform to the 1996 presentation.

(2)  PROPERTY ACQUISITION

     On May 31, 1996, the Company acquired certain Oklahoma oil and natural gas
     properties from Amerada Hess Corporation ("Amerada Hess") for
     approximately $32,100,000, with $25,500,000 allocated to producing
     properties and $6,600,000 allocated to undeveloped leasehold and to
     nonproducing minerals. The Company funded the purchase through use of cash
     funds and borrowings of $30,000,000 from its credit facilities.

     Total estimated proved reserves as of May 31, 1996, net to the Company,
     were 6.8 Mmboe. Proved reserves attributable to the acquired properties
     were divided approximately 43% oil and 57% natural gas. (The quantities of
     proved reserves in this paragraph were prepared by the Company's internal
     engineers and based on an independent reserve study prepared as of January
     1, 1996 by Degolyer and MacNaughton and are unaudited.)

     The 1996 acquisition of the Amerada Hess properties described above was
     accounted for by the purchase method of accounting for business
     combinations. Accordingly, the accompanying 1996 Consolidated Statement of
     Operations does not include any revenues or expenses associated with the
     Amerada Hess properties prior to the acquisition date of May 31, 1996.
     Following are the Company's pro forma results assuming the acquisition
     occurred at the beginning of 1995:


                                     F-11
<PAGE>   56
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<TABLE>
<CAPTION>
                                                   1996        1995
                                                  -------    --------
          <S>                                     <C>         <C>
          Total revenues                          $33,242    $ 31,780
          Net income (loss)                       $ 5,655    $ (5,485)
          Net income (loss) per share             $  0.44    $  (0.49)
</TABLE>

(3)  ACCOUNTS RECEIVABLE

     Accounts receivable consisted of the following:

<TABLE>
<CAPTION>
                                                  December 31,  December 31,
                                                      1996          1995
                                                  ------------  ------------
<S>                                                <C>           <C>
     Joint interest billings                       $1,162,000    $  945,000
     Accrued oil and natural gas revenue            7,340,000     3,905,000
     Other                                            496,000            --
                                                   ----------    ----------
            Total                                  $8,998,000    $4,850,000
                                                   ==========    ==========
</TABLE>

     The Company requires other joint interest owners to pay drilling costs in
     advance. The advances are recorded as liabilities by the Company. The
     Company does not require parties to collateralize amounts owing to the
     Company for joint interest billings after the completion of the well. To
     mitigate this credit risk, the Company has the ability to offset amounts
     owed to the Company through application of revenues owing to the other
     parties and has the ability to file liens on the related properties.


                                     F-12
<PAGE>   57
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(4)  PROPERTY AND EQUIPMENT

     Property and equipment consisted of the following:

<TABLE>
<CAPTION>
                                                                               DECEMBER 31,   DECEMBER 31,
                                                                                  1996            1995
                                                                              -------------   ------------
<S>                                                                           <C>             <C>
     Oil and natural gas properties:
           Subject to amortization                                            $ 109,325,000   $ 62,275,000
           Not subject to amortization:
                 Cost incurred in 1996                                           14,674,000             --
                 Cost incurred in 1995                                            1,278,000      7,419,000
                 Cost incurred in 1994                                            1,518,000      1,518,000
                 Cost incurred in 1993                                              715,000        715,000
                 Cost incurred in 1992                                              385,000        385,000
                                                                              -------------   ------------
                                                                                 18,570,000     10,037,000
                                                                              -------------   ------------
     Accumulated depreciation, depletion and amortization                       (25,868,000)   (17,505,000)
                                                                              -------------   ------------
     Net oil and natural gas properties                                         102,027,000     54,807,000
                                                                              -------------   ------------

     Natural gas processing plants and gathering systems                          1,728,000      3,094,000
     Saltwater disposal system                                                    1,119,000      1,119,000
     Other property and equipment                                                 1,223,000        948,000
                                                                              -------------   ------------
                                                                                  4,070,000      5,161,000
     Accumulated depreciation                                                    (1,139,000)    (1,307,000)
                                                                              -------------   ------------
     Net processing plants, gathering and disposal systems,
           and other property and equipment                                       2,931,000      3,854,000
                                                                              -------------   ------------
     Property and equipment, net of accumulated
           depreciation, depletion and amortization                           $ 104,958,000   $ 58,661,000
                                                                              =============   ============

     Depreciation, depletion and amortization expense
     consisted of the following:
           Depreciation, depletion and amortization
                 of oil and natural gas properties                            $   8,364,000   $  6,687,000
           Depreciation and amortization of processing plants, gathering
                 and disposal systems, and other property and equipment             538,000        645,000
           Amortization of other assets                                              36,000         36,000
                                                                              =============   ============
                              Total depreciation, depletion and amortization  $   8,938,000   $  7,368,000
                                                                              =============   ============
</TABLE>

(5)  INVESTMENT IN WAGGONER (BARBADOS) LTD. AND OTHER ASSETS

     On November 27, 1996, the Company purchased 21% of the equity of Waggoner
     (Barbados) Ltd. which has a joint venture agreement with the Barbados
     National Oil Company, Ltd. to more fully develop the onshore oil and gas
     reserves of Barbados by applying state-of-the-art exploration, completion,
     and production methods. As of December 31, 1996, Waggoner (Barbados) Ltd.
     had not begun significant operations. The cost of the Company's investment
     equals its share of the stockholders' equity of Waggoner


                                     F-13
<PAGE>   58
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     (Barbados) Ltd. The assets of Waggoner (Barbados) Ltd. are comprised
     principally of cash as of December 31, 1996.

     Operations under the joint venture created by the agreements are expected
     to commence in the first quarter of 1997. The initial work plan
     contemplates both exploitation of existing fields and new exploration. The
     joint venture will share in sixty percent of the production enhancements
     over and above current volumes adjusted for normal production declines.

     During 1996, the Company acquired senior unsecured notes and other credit
     obligations of WRT Energy Corporation ("WRT Energy"), an oil and gas
     company operating under the provisions of Chapter 11 of the United States
     Bankruptcy Code since February of 1996. These notes and other credit
     obligations are being accounted for using the cost method. At December 31,
     1996 the Company's cost of these notes and other credit obligations was
     approximately $7.9 million.

     On November 29, 1996 as amended on January 20, 1997, and March 11, 1997,
     the Company and Wexford Management L.L.C. ("Wexford"), an entity
     affiliated with the Chairman of the board of directors of the Company,
     filed a joint plan of reorganization with WRT Energy. No competing
     reorganization plans have been filed. The Company is anticipating
     confirmation of the plan during the second quarter of 1997, although
     delays caused by motions requested by other creditors could delay the
     proceedings. The plan is expected to go into effect sixty days after
     confirmation of the plan. The Company has been in contact with other
     creditors of WRT Energy and anticipates that the plan, substantially as
     filed, will be approved by at least the minimum number of creditors
     required by provisions of the United States Bankruptcy Code in order for
     the plan to be confirmed. Under the plan, a new WRT Energy will be created
     with approximately 21.3 million shares of common stock outstanding and the
     Company will exchange its WRT Energy notes, the Company's interest in the
     West Cote Blanche Bay Field acquired in March of 1997 (described in Note
     14) and other assets for an equity interest in the new WRT Energy. In
     addition, the Company and Wexford have committed to funding a rights
     offering associated with the reorganization plan of WRT Energy. The rights
     to purchase new common stock of WRT Energy are being offered to all
     unsecured creditors of WRT Energy. Pursuant to provisions of the plan, the
     Company and Wexford have committed to purchase the rights not exercised by
     other creditors. Based upon the notes and other credit obligations, the
     Company's pro rata portion of the rights offering, as contemplated by the
     plan, ranges from a minimum of $2.4 million to a maximum of $9.3 million.
     The Company would own approximately 9.9 million to 11.8 million shares or
     between 46.2 % and 55.4 % of WRT Energy's equity.


                                     F-14
<PAGE>   59
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(6)  LONG-TERM DEBT

     1995 Facility

     Under the terms of the revolving loan agreement dated December 24, 1995,
     the Company may borrow up to the borrowing base at either the banks' prime
     or floating rate, the London Interbank Offered Rate ("LIBOR") plus 176
     basis points or a pricing grid rate with the rate determined by the
     percentage of borrowing base commitment outstanding. As of December 31,
     1996, borrowings of $37,200,000 were outstanding at a weighted average
     interest rate of 7.3%. No amounts were borrowed as of December 31, 1995.
     As of December 31, 1996 and 1995, the Company's borrowing base was
     $50,000,000 and $20,000,000, respectively. Principal payments on the
     revolving loan are due at maturity or when the amounts outstanding under
     the revolving loan agreements are in excess of the borrowing base.
     Interest payments are due quarterly. The advances under the revolving
     loans are collateralized by a mortgage on the Company's producing and
     nonproducing oil and natural gas properties and are due in October 2000.

     The revolving loan agreement requires the Company to pay commitment fees
     for unused amounts. For 1996, 1995 and 1994, the Company's commitment fee
     expense was $174,000, $44,000 and $70,000, respectively.

     The revolving loan agreement contains restrictive covenants requiring,
     among other things, maintenance at specific levels of tangible net worth,
     working capital, and specific financial ratios, as well as limiting the
     payment of dividends.

     1997 Facility

     On March 5, 1997, the Company established a new $85,000,000 revolving
     credit facility with a group of financial institutions. This facility was
     used to refinance indebtedness under the 1995 facility with the remainder
     to be used for funding of acquisitions and general corporate purposes. The
     maturity of the 1997 facility is March 2002.

     Under the terms of the 1997 facility, interest will be charged at the
     higher of the bank's prime rate plus 1/2 of 1% plus the applicable margin
     or the rate at which Eurodollar deposits for one, two, three, six or
     twelve months are offered to the bank in the Interbank Eurodollar market
     plus the applicable margin. Loans made under the 1997 facility are payable
     in full on the maturity date.

     The new revolving credit facility contains similar restrictive covenants
     to the 1995 facility.

(7)  INCOME TAXES

     Prior to the July 1995 merger and initial public offering, the Company and
     Davidson filed separate income tax returns as Subchapter S corporations
     under the provisions of the Internal Revenue Code. The Company's
     S election terminated in 1995 upon completion of the initial public
     offering. As a result of the Company's termination of the S election, the
     Company recognized a charge against operations in 1995 in the amount of
     $11,500,000


                                     F-15
<PAGE>   60
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     for deferred income taxes which represented the tax effect of
     the difference between the financial statement carrying values and the
     income tax basis of the Company's assets and liabilities on the date the
     S election was terminated.

     In addition to the $11,500,000 deferred income tax expense described
     above, the Company recorded $1,400,000 in deferred income tax expense in
     1995 related to the period following the initial public offering.

     Tax strategies implemented by the shareholders of the Company and Davidson
     prior to the merger are not reflective of the results that the Company
     would have achieved if the Company had been directly subject to income
     taxes. Therefore, results of the operations for 1994, reflect a pro forma
     provision for income tax expense at a rate of 40% (based upon blended
     Federal and state rates) of income before taxes.

     At December 31, 1996, the Company had the following carryforwards
     available to reduce future federal and state income taxes:

<TABLE>
<CAPTION>
                                                   YEAR OF      CARRYFORWARD
     TYPES OF CARRYFORWARD                        EXPIRATION       AMOUNTS
                                                 ---------------------------
<S>                                              <C>              <C>
     Net operating loss - federal                2010 and 2011    $2,201,000
     Net operating loss - various states         2010 and 2011    $2,600,000
     Statutory depletion                              None        $  290,000
</TABLE>

     Total income tax expense for 1996 and 1995 differed from the amounts
     computed by applying the federal income tax rate of 34% to income before
     income taxes as a result of the following:

<TABLE>
<CAPTION>
                                                         1996         1995
                                                     -----------  -----------
<S>                                                  <C>          <C>
     Computed "expected" federal income tax expense  $ 2,659,000  $ 2,626,000
     Effect of state income taxes                        292,000      289,000
     Effect of change in tax status                           --    9,925,000
     Other, net                                               --       60,000
                                                     -----------  -----------
                                                     $ 2,951,000  $12,900,000
                                                     ===========  ===========
</TABLE>

     The tax effects of temporary differences that gave rise to significant
     portions of the deferred tax assets and liabilities at December 31, 1996
     and 1995 are presented below:


                                     F-16
<PAGE>   61
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<TABLE>
<CAPTION>
                                                                 1996           1995
                                                             ------------   ------------
<S>                                                          <C>            <C>
     Deferred tax assets:
            Net operating loss carryforwards                 $    831,000   $    241,000
            Statutory depletion carryforwards                     110,000         55,000
                                                             ------------   ------------
                  Total deferred tax assets                  $    941,000   $    296,000

     Deferred tax liability:
            Property and equipment, principally due to
            difference in depreciation, and expensing
            of intangible drilling cost, nonproductive well
            costs and general and administrative expenses
            for tax purposes                                  (16,792,000)   (13,196,000)
                                                             ============   ============
                  Net deferred tax liability                 $(15,851,000)  $(12,900,000)
                                                             ============   ============
</TABLE>


     Because the temporary differences between financial carrying value and tax
     basis are expected to reverse before the expiration of the net operating
     loss carryforwards, management believes that it is more likely than not
     that the benefits of these carryforwards will be realized. As such, there
     is no valuation allowance for deferred tax assets at December 31, 1996.


(8)  SHAREHOLDERS' EQUITY

     Effective with the merger of DLB and Davidson, the capital structure of
     the Company consisted of 130,000,000 authorized common shares ($.001 par
     value) with 10,000,000 shares outstanding along with 5,000,000 authorized
     preferred shares with no preferred shares outstanding. For financial
     reporting purposes, combined shareholder's equity at the date of the
     merger was converted into the Company's common stock and additional
     paid-in-capital.

     On February 7, 1996, the Company adopted a common stock repurchase plan.
     Under the terms of the plan, up to $5,000,000 of common stock could have
     been repurchased from time to time. Pursuant to the plan, 25,000 shares
     were repurchased for $181,000. Repurchased stock is held as treasury stock
     by the Company. The repurchase plan expired on August 5, 1996.

     On July 25, 1995, the Company issued 3,000,000 shares of common stock
     through a public offering at $10 per share. Net proceeds to the Company
     from the offering, after selling and offering costs, were $26,896,000. The
     Company used $11,231,000 of these proceeds to retire then existing
     indebtedness under its revolving line of credit facilities.

     In 1995, the Company adopted a stock option plan ("the Plan") pursuant to
     which the Company's Board of Directors may grant stock options to officers
     and key employees. The Plan authorizes grants of options to purchase up to
     1,625,000 shares of authorized but unissued common stock. Stock options
     are granted with an exercise price equal to the


                                     F-17
<PAGE>   62
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     stock's fair market value at the date of grant. All stock options have ten
     year terms and vest ratably over a five year term.

     No grants were made during 1996. The per share weighted-average fair value
     of stock options granted during 1995 was $4.69 on the date of grant using
     the Black Scholes option-pricing model with the following weighted-average
     assumptions: expected dividend yield 0%, risk-free interest rate of 5.50%,
     expected volatility of 45% and an expected life of five years.

     The Company has elected to continue to apply APB Opinion No. 25 in
     accounting for its granted stock options and, accordingly no compensation
     cost has been recognized for the fair value of stock options in the
     financial statements. Had the Company determined compensation cost based
     on the fair value at the grant date for its stock options under SFAS No.
     123, the Company's net income would have been reduced to the pro forma
     amounts indicated below:

<TABLE>
<CAPTION>
                                                 1996               1995
                                              -----------       ------------
<S>                                           <C>               <C>
     Net income (loss):
                          As reported         $ 4,869,000       $ (5,176,000)
                          Pro forma             3,900,000         (5,362,000)

     Net income (loss) per share:
                          As reported         $      0.38       $      (0.46)
                          Pro forma                  0.30              (0.48)
</TABLE>

     Pro forma net income reflects only options granted in 1995, as no options
     were granted in 1996. The full impact of compensation cost for stock
     options under SFAS No. 123 is not reflected in the pro forma net income
     amounts presented above because compensation cost is reflected over the
     options vesting period of five years.

     Stock option activity during the years indicated is as follows:


                                     F-18
<PAGE>   63
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<TABLE>
<CAPTION>
                                                   NUMBER OF  WEIGHTED-AVERAGE
                                                     SHARES    EXERCISE PRICE
                                                   ---------- ----------------
     <S>                                           <C>          <C>
     Balance as of December 31, 1994                       --   $       --
                   Granted                          1,625,000           10
                   Exercised                               --           --
                   Forfeited                               --           --
                   Expired                                 --           --
                                                   ----------   ----------
     Balance as of December 31, 1995                1,625,000           10
                   Granted                                 --           --
                   Exercised                               --           --
                   Forfeited                               --           --
                   Expired                                 --           --
                                                   ----------   ----------
     Balance as of December 31, 1996                1,625,000   $       10
                                                   ==========   ==========
</TABLE>

     At December 31, 1996, the exercise prices and weighted-average remaining
     contractual life of outstanding options was $10 and 8.7 years,
     respectively.

     At December 31, 1996 and 1995, the number of options exercisable was
     390,000 and 65,000, respectively, and the weighted-average exercise price
     of those options was $10.

(9)  NATURAL GAS CONTRACT SETTLEMENT

     During 1994, the Company entered into a settlement of a natural gas
     contractual dispute. As a result of the settlement, the Company recognized
     a gain in 1994 of $3,343,000 in a one time, lump sum payment which is not
     subject to any repayment conditions.

(10) MAJOR CUSTOMERS

     The Company markets its oil and natural gas production to numerous
     purchasers under a combination of short-term and long-term contracts.
     During 1996, 1995 and 1994, the Company's largest purchasers accounted for
     47%, 58% and 72%, respectively, of oil and natural gas revenues of the
     Company. The Company had no other purchasers that accounted for greater
     than 10% of its oil and natural gas revenues. The Company does not believe
     that the loss of any single customer would have a material effect on the
     results of the Company's operations.

(11) EMPLOYEE BENEFIT PLANS

     In 1994, the Company adopted a qualified 401 (k) Profit Sharing Plan which
     permits eligible employees to defer up to 10% of their compensation. All
     employees over 18 years of age and with six months of service can
     participate in the Plan. Employees vest in the Company's matching
     contributions at a rate of 25% per year. The Company is not


                                     F-19
<PAGE>   64
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     obligated to match the employees' contributions. During 1996, 1995 and
     1994, the Company elected to make $35,000, $25,000 and $14,000 in matching
     contributions, respectively.

     Also in 1994, the Company adopted a money purchase pension plan, which
     commits the Company to contribute 8.33% of employees compensation to the
     plan up to maximum amounts allowed by regulation. All employees over 18
     years of age and employed on the first of January of the plan year are
     eligible to participate in the plan. The plan does not permit employee
     contributions. Participants vest immediately in the contributions made by
     the Company. During 1996, 1995 and 1994, the Company contributed to the
     plan $169,000, $144,000 and $90,000, respectively.

     Prior to the merger, the Company granted selected key employees various
     carried interests in certain undeveloped and purchased producing oil and
     gas properties. The carried interests, which range in the aggregate from
     0.5% to 2.5% of the properties, applied to wells drilled in certain areas
     of development and purchased producing properties. Compensation expense
     equal to the fair value of the grant of proved reserves was not recognized
     as the amount was not significant. The granting of carried interest ceased
     at the merger effective date. The employees' interests in the proved
     properties are not included in the Company's estimated quantities of
     proved oil and gas reserves.

(12) RELATED PARTY TRANSACTIONS

     A company, the owner of which is related to certain officers of the
     Company, sold oil field equipment and provided oil field services which
     aggregated $3,829,000, $1,481,000 and $1,784,000 to the Company for 1996,
     1995, and 1994, respectively. The transactions were settled on normal
     industry terms. As of December 31, 1996 and 1995, the Company owed the
     supplier $484,000 and $105,000, respectively. All amounts owed to the
     supplier related to sales of oil field equipment and oil field services
     provided to the Company.

(13) COMMITMENTS AND CONTINGENCIES

     Minimum future rental payments under noncancelable operating leases having
     remaining terms in excess of one year as of December 31, 1996, for each of
     the next three years and in the aggregate are as follows:

<TABLE>
                       <S>              <C>
                       1997                242,861
                       1998                309,938
                       1999                321,804
                                        ----------
                                        $  874,603
                                        ==========
</TABLE>

     Rental expense for the years ended December 31, 1996, 1995 and 1994 was
     $178,000, $140,000 and $104,000, respectively.


                                     F-20
<PAGE>   65
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The Company is a defendant in two legal proceedings related to properties
     purchased from Amerada Hess. One suit relates to the validity of a
     leasehold interest. The claimants seek cancellation of the lease. The
     Company does not agree with the claimants position. However, if the
     claimant prevails, the Company would seek recovery from Amerada Hess
     pursuant to provisions of the purchase agreement. The lease involved in
     this suit had an agreed upon value of approximately $311,000 as documented
     in the purchase agreement.

     The second suit relates to the Company's denial of an unrelated party's
     preferential rights to purchase certain properties under various operating
     agreements with Amerada Hess. DLB acquired such properties in the Amerada
     Hess acquisition. DLB contends that the third party's preferential right
     elections were invalid as to the majority of such interests. On January
     21, 1997, a hearing was held before the District Court of Ellis County,
     Oklahoma on cross motions for summary judgment of the Company and the
     third party. The Court ruled in favor of the Company on most of the third
     party's claims against the Company. However, the Court did not rule on the
     validity of the preferential rights. If the Court rules in the third
     party's favor, barring appeal, the Company would be required to sell the
     certain properties for the values listed in the purchase agreement, of
     approximately $1,123,000.

     DLB is also involved in the routine judicial and administrative
     proceedings that are common to companies of its size in the oil and gas
     industry. None of these proceedings are believed, either individually or
     in aggregate, to be material to DLB's financial condition, liquidity or
     results of operations.

     As of December 31, 1996, the Company had outstanding letters of credit of
     approximately $1,463,000. The letters of credit expire during the first
     quarter of 1997.

     In 1996, the Company settled claims submitted to arbitration against a
     joint venture partner alleging breach of contract and tortuous conduct.
     The claims arose under the terms of the Carmen Field Joint Venture
     Agreement dated May 26, 1993, between the Company and Magic Circle
     Acquisition Corporation ("Magic Circle"). In the proceeding, the Company
     sought actual damages in excess of $1,000,000, an accounting and other
     relief, including dissolution of the Carmen Field Joint Venture ("CFJV").
     The Company settled its claims by agreement dated February 7, 1996. The
     settlement agreement provided for mutual releases of all claims arising
     out of the CFJV, dissolution of the CFJV, distribution to the Company of
     its interest in the CFJV oil and gas properties, the payment of $3,349,000
     to the Company and transfer to the Company of its share of a gathering
     system in Stephens County, Oklahoma, and transfer to Magic Circle
     gathering, processing and compression facilities in Alfalfa and Woodward
     Counties, Oklahoma. As a result of the settlement, the Company recognized
     a $208,000 loss, including $212,000 of related legal fees. The Company
     earned net revenues before income taxes of $2,933,000 and $1,151,000
     during 1995 and 1994, respectively, from its ownership of the assets
     transferred to Magic Circle as part of the settlement.


                                     F-21
<PAGE>   66
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(14) EVENTS OCCURRING SUBSEQUENT TO DECEMBER 31, 1996

     BONRAY DRILLING CORPORATION

     On February 10, 1997, the Company purchased the outstanding common stock
     of Bonray Drilling Corporation through a tender offer. DLB paid $30.00 per
     share, or approximately $12.7 million. As a result of the completed tender
     offer, Bonray Drilling Corporation became a wholly-owned subsidiary of
     DLB.

     Bonray owns a total of 15 rigs, including six rigs capable of drilling
     wells over 20,000 feet and nine rigs capable of drilling wells from 7,500
     to 15,000 feet. Two of the six deep drilling rigs are presently being
     remobilized. These rigs are expected to be in operation by the second
     quarter of 1997. Ten rigs were in service or available for service at the
     time of acquisition with three in stacked status.

     WEST COTE BLANCHE BAY FIELD

     On March 11, 1997, the Company purchased Texaco Exploration and
     Production, Inc.'s 50% interest in the shallow rights in the West Cote
     Blanche Bay Field ("WCBB") located in Saint Mary's Parish, Louisiana.

     The purchase includes the right to operate existing and future wells
     completed above the Robb "C" (a geologic marker located at approximately
     10,500 feet) and the right to operate the related production facilities
     which include oil and gas pipelines, salt water disposal wells,
     compression facilities and related equipment. The purchase price was $12.3
     million. Proved reserves attributable to the acquisition were
     independently estimated at approximately 12.2 Mmboe (million barrels of
     oil equivalent) as of January 1, 1997, and are essentially 100% oil. (The
     quantities of proved reserves in this paragraph were prepared by the
     Company's internal engineers and based on an independent reserve study
     prepared as of January 1, 1996 by Netherland, Sewell and Associates, Inc.
     and are unaudited.)

     The remaining 50% working interest in the shallow rights to the WCBB
     property is owned by WRT Energy. As part of the WRT Energy reorganization
     plan, DLB expects to contribute the acquired interest in WCBB (described
     above) to WRT Energy in exchange for 5.0 million shares in the reorganized
     WRT Energy. See Note 5.

     Additionally, the Company purchased approximately $6.0 million of
     obligations of WRT Energy that relate to the West Cote Blanche Bay Field
     properties. Such obligations are expected to be converted into equity of
     the new WRT Energy and are included in the equity percentages disclosed in
     Note 5.

(15) OIL AND NATURAL GAS OPERATIONS

     Below is a summary of results of operations for oil and natural gas
     producing activities. The results do not include any allocation of the
     Company's interest costs or general

                                     F-22
<PAGE>   67
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     corporate overhead and therefore, are not necessarily indicative of the
     contribution to net income of the Company's oil and natural gas
     operations. Income taxes have not been considered in the summary.

<TABLE>
<CAPTION>
                                                  YEAR ENDED DECEMBER 31,
                                           -------------------------------------
                                              1996         1995         1994
                                           -----------  -----------  -----------
<S>                                        <C>          <C>          <C>
     Income:
       Oil and natural gas sales           $27,194,000  $17,860,000  $17,826,000

     Expenses:
       Lease operating expenses              5,539,000    3,579,000    4,461,000
       Gross production taxes                1,843,000    1,366,000    1,009,000
       Depreciation, depletion, and
         amortization                        8,364,000    6,687,000    6,185,000
                                           -----------  -----------  -----------
                                            15,746,000   11,632,000   11,655,000
                                           -----------  -----------  -----------

     Results of operations from oil and
         natural gas producing activities  $11,448,000  $ 6,228,000  $ 6,171,000
                                           ===========  ===========  ===========

     Depreciation, depletion, and
         amortization per equivalent
         barrel of production              $      5.23  $      5.52  $      5.18
                                           ===========  ===========  ===========
</TABLE>

     The following is a summary of costs incurred, all of which were
     capitalized, for oil and natural gas property exploration, development,
     and acquisition activities:

<TABLE>
<CAPTION>
                                            YEAR ENDED DECEMBER 31,
                                   ----------------------------------------
                                       1996           1995          1994
                                   -----------    -----------    ----------
<S>                                <C>            <C>            <C>
     Exploration costs             $ 9,605,000    $12,482,000    $8,551,000

     Development costs              11,503,000      5,884,000     7,688,000

     Acquisition costs              34,476,000         39,000     8,849,000
</TABLE>

(16) SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

     The following supplemental unaudited information regarding the oil and gas
     activities of the Company is presented pursuant to the disclosure
     requirements promulgated by the Securities and Exchange Commission and
     Statement of Financial Accounting Standards No. 69 "Disclosures About Oil
     and Gas Producing Activities".

     OIL AND NATURAL GAS QUANTITIES

     Substantially all reserve information for the year ended December 31,
     1996, presented below was prepared by the independent engineering firms of
     Degolyer and MacNaughton and H.J. Gruy & Associates, Inc. For the year
     ended December 31, 1995, substantially all reserve information presented
     was prepared by Netherland, Sewell and Associates, Inc.


                                     F-23
<PAGE>   68
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     and H.J. Gruy & Associates, Inc. There are many uncertainties inherent in
     estimating reserve quantities, and in projecting future production rates
     and the timing of future development expenditures. In addition, reserve
     estimates of new discoveries are more imprecise than those of properties
     with a production history. Accordingly, these estimates are subject to
     change as additional information becomes available.

     Proved oil and natural gas reserves are the estimated quantities of crude
     oil, condensate, natural gas and natural gas liquids that 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 oil and natural gas reserves are
     those reserves expected to be recovered through existing wells with
     existing equipment and operating methods.

     Estimates of net quantities of proved reserves and proved developed
     reserves of crude oil, including condensate and natural gas liquids, and
     natural gas, as well as the changes in proved reserves during the periods
     indicated, are set forth in the tables below. All reserves are located in
     the United States.

     The Company prepared the estimated reserves as of December 31, 1993 based
     on geological and engineering evaluations performed as of December 31,
     1994. The reserve estimates as of December 31, 1993 were derived by
     analyzing actual historical production amounts and by adjusting the
     reserves attributable to wells acquired or disposed of during 1993. In
     addition, in deriving the estimates as of December 31, 1993, the Company
     used production costs and the estimated sales prices as of December 31,
     1994. The Company has estimated its reserves as of December 31, 1993 in
     this manner because the actual information necessary to calculate
     estimated proved reserves and related information in accordance with
     guidelines of the Securities and Exchange Commission (SEC) as of December
     31, 1993 was not available. Because the reserve estimates as of December
     31, 1994 are based on additional information gained from the result of
     drilling, testing and production subsequent to the dates of the estimated
     reserves, the reserve estimates as of December 31, 1993 are not
     necessarily reflective of quantities that might have been estimated based
     on information available as of such date had estimates in accordance with
     SEC guidelines been made at such date. Management believes that, because
     of the methodology used, the reserve information presented is more
     reflective of actual quantities than estimates that might have been
     generated as of December 31, 1993.


                                     F-24
<PAGE>   69
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<TABLE>
<CAPTION>
     CHANGES IN PROVED RESERVES                       OIL      NATURAL GAS
                                                     (BBLS)        (MCF)
                                                   ---------   -----------
<S>                                                <C>          <C>
     Proved reserves, at December 31, 1993         3,620,000    17,069,000
              Extension and discoveries            1,375,000     9,019,000
              Purchase of reserves                   514,000     3,476,000
              Production                            (663,000)   (3,187,000)
                                                   ---------    ----------
     Proved reserves, at December 31, 1994         4,846,000    26,377,000
              Extension and discoveries              521,000     9,454,000
              Purchase of reserves                   130,000       803,000
              Revisions of previous estimates       (171,000)   (4,969,000)
              Production                            (708,000)   (3,022,000)
                                                   ---------    ----------
     Proved reserves, at December 31, 1995         4,618,000    28,643,000
              Extension and discoveries              270,000    30,186,000
              Purchase of reserves                 2,983,000    23,082,000
              Revisions of previous estimates       (537,000)    4,049,000
              Production                            (664,000)   (5,603,000)
                                                   ---------    ----------
     Proved reserves, at December 31, 1996         6,670,000    80,357,000
                                                   =========    ==========
</TABLE>


<TABLE>
<CAPTION>
                                               OIL         NATURAL GAS
     PROVED DEVELOPED RESERVES AS OF:         (BBLS)          (MCF)
                                             ---------     -----------
<S>                                          <C>            <C>
          December 31, 1993                  2,816,000      13,098,000
          December 31, 1994                  3,791,000      16,529,000
          December 31, 1995                  4,046,000      19,955,000
          December 31, 1996                  5,234,000      54,797,000
</TABLE>

     STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

     The following table sets forth the standardized measure of the discounted
     future cash flows attributable to the Company's proved oil and natural gas
     reserves. Future cash inflows were computed by applying year-end prices of
     oil and natural gas to the estimated future production of proved oil and
     natural gas reserves, except as described above for 1993. All prices were
     held constant except where a definite price escalation is provided in the
     sales contract. Contractually provided natural gas prices in excess of
     estimated market prices were used in computing the future cash inflows
     only if the Company expects to continue to receive higher prices under
     legally enforceable contract terms. Future prices received may differ from
     the estimates in the standardized measure.

     Future production and development costs represent the estimated future
     expenditures (based on current costs) to be incurred in developing and
     producing the proved reserves,


                                     F-25
<PAGE>   70
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     assuming continuation of existing economic conditions. Future income taxes
     were computed by applying the appropriate statutory tax rates to the
     future pretax net cash flows relating to proved reserves, net of tax basis
     of the properties involved and certain tax carryforwards. The future
     income taxes give effect to permanent differences but do not include the
     impact of future operations. The resulting periodic future net cash flows
     were discounted using a 10% annual rate.

     The additions to proved reserves from new discoveries and extensions could
     vary significantly from year to year; additionally, the impact of changes
     to reflect current prices and costs of reserves proved in prior years
     could be significant. Accordingly, the information presented below should
     not be viewed as an estimate of the fair value of the Company's oil and
     natural gas properties, nor should it be considered indicative of any
     trends.

<TABLE>
<CAPTION>
                                                1996             1995            1994
                                            -------------   -------------   -------------
<S>                                         <C>             <C>             <C>
     Future cash inflows                    $ 464,712,000   $ 144,069,000   $ 125,546,000
     Future production costs                 (106,027,000)    (42,494,000)    (32,021,000)
     Future development costs                 (17,180,000)     (7,236,000)     (7,053,000)
     Future income taxes                     (106,757,000)    (27,265,000)    (25,000,000)
                                            -------------   -------------   -------------
     Future net cash flows                    234,748,000      67,074,000      61,472,000
     10% discount to reflect
              timing of cash flows            (93,996,000)    (23,409,000)    (16,055,000)
                                            -------------   -------------   -------------
     Standardized measure of
              discounted future cash flows  $ 140,752,000      43,665,000   $  45,417,000
                                            =============      ==========   =============
     Discounted future net cash flows
              before income taxes           $ 204,763,000   $  61,501,000   $  63,888,000
                                            =============   =============   =============
</TABLE>

     The net weighted average prices at December 31, 1996 used in the
     computations in the table above were $25.14 per barrel of oil and $3.70
     per Mcf of natural gas.


                                     F-26
<PAGE>   71
                              DLB OIL & GAS, INC.
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     CHANGES RELATING TO STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
     FLOWS

     Principal changes in the standardized measure of discounted future net
     cash flows attributable to the Company's proved reserves are as follows:

<TABLE>
<CAPTION>
                                                              1996           1995           1994
                                                         -------------   ------------   ------------
<S>                                                      <C>             <C>            <C>
     Beginning balance                                   $  43,665,000   $ 45,417,000   $ 27,957,000

     Sales of oil and natural gas, net of
              production costs                             (19,812,000)   (12,915,000)   (12,356,000)

     Net changes in prices and production costs             81,807,000      4,787,000             --

     Extensions, discoveries and improved
              recovery, net of future development costs     51,292,000      9,654,390     22,281,000

     Purchase of reserves, net of future
              development costs                             35,286,000      1,616,610      8,658,000

     Development costs incurred during the period            1,178,000      1,993,000             --

     Revisions of quantity estimates                           916,000     (8,339,000)            --

     Change in income taxes                                (47,662,000)    (1,477,000)    (5,635,000)

     Accretion of discount                                   6,150,000      6,388,000      4,512,000

     Other, primarily changes in timing                    (12,068,000)    (3,460,000)            --
                                                         -------------   ------------   ------------
     Ending balance                                      $ 140,752,000   $ 43,665,000   $ 45,417,000
                                                         =============   ============   ============
</TABLE>


                                     F-27
<PAGE>   72
                                 EXHIBIT INDEX

<TABLE>
<S>      <C>
         2.0   Agreement for Purchase and Sale dated April 16, 1996, between
               Amerada Hess Corporation and DLB Oil & Gas, Inc. (the "Agreement
               for Purchase and Sale").(4)

         2.1   Letter agreement amending Agreement for Purchase and Sale dated
               May 7, 1996.(3)

         2.2   Letter agreement amending Agreement for Purchase and Sale dated
               May 31, 1996.(3)

         3.1   Amended and Restated Certificate of Incorporation(1)

         3.2   Amended and Restated Bylaws(1)

         10.1  Lease of office space, Oklahoma City, Oklahoma(1)

         10.2  Credit Agreement dated December 28, 1995, between Registrant and
               First Union National Bank of North Carolina(2)

         10.3  Stock Option Agreement by and between Registrant and Mike
               Liddell(1)

         10.4  Stock Option Agreement by and between Registrant and Mark
               Liddell(1)

         10.5  Employment Agreement by and between Registrant and Mike
               Liddell(1)

         10.6  Employment Agreement by and between Registrant and Mark
               Liddell(1)

         10.7  DLB Oil & Gas Stock Option Plan(1)

         10.8  DLB Oil & Gas Omnibus Equity Compensation Plan(1)

         10.9  Shareholder's Agreement by and among Charles E. Davidson, Mike
               Liddell and Mark Liddell dated May 25, 1995(1)

         10.10 Agreement for Dissolution of Joint Venture dated February 9,
               1996, between DLB Oil & Gas, Inc., Magic Circle Acquisition
               Corporation and Magic Circle Energy Corporation, Carmen Field
               Limited Partnership, and Carmen Field Joint Venture(2)

         10.11 First Amendment to the Credit Agreement dated June 30, 1996,
               between Registrant and First Union National Bank of North
               Carolina(4)

         10.12 Credit Agreement Dated as March 5, 1997 between registrant
               and Chase Manhattan Bank

         10.13 Second Amended Disclosure Statement Under 11 U.S.C. Section
               1125 in Support of Debtor and DLBW's Second Amended Joint Plan
               of Reorganization Under Chapter 22 of the United States
               Bankruptcy Code

         10.14 Texaco Agreements

         21.0  Subsidiaries of the Company(1)
</TABLE>

-----------------

          (1)  Previously filed as an exhibit to Registration No. 33-92786 on
               Form S-1 and incorporated herein by reference.

          (2)  Previously filed as an exhibit to Form 10-K for the year ended
               December 31, 1995, and incorporated herein by reference.

          (3)  Previously filed as an exhibit to Form 8-K on May 12, 1996, and
               incorporated herein by reference.

          (4)  Previously filed as an exhibit to Form 10-Q filed on August 14,
               1996.

          (5)  Pursuant to Item 601(b)(2) of Regulation S-K, the exhibits and
               schedules to Exhibit 2.0 are omitted. Exhibit 2.0 contains a
               list identifying the contents of its exhibits and schedules, and
               registrant agrees to furnish supplemental copies of such
               exhibits and schedules to the Securities and Exchange Commission
               upon request.