<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-14029
12,610,000 Shares
Titan Exploration, Inc.
Common Stock
($.01 par value)
------------------
Of the shares offered hereby, 12,500,000 shares are being sold by Titan
Exploration, Inc. (the "Company") and 110,000 shares are being sold
by the Selling Stockholder named herein under "Principal and
Selling Stockholders." The Company will not receive any of
the proceeds of Shares sold by the Selling Stockholder.
Prior to this offering, there has been no public
market for the Common Stock. The Common Stock
has been approved for listing on The Nasdaq
Stock Market's National Market under the
symbol "TEXP," subject to
notice of issuance.
------------------
FOR A DISCUSSION OF CERTAIN RISKS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 8
HEREIN.
------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL
OFFENSE.
<TABLE>
<CAPTION>
Underwriting
Discounts Proceeds to Proceeds to
Price to and the the Selling
Public Commissions(1) Company(2) Stockholder
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
Per Share.................................... $11.00 $0.69 $10.31 $10.31
Total(3)..................................... $138,710,000 $8,700,900 $128,875,000 $1,134,100
</TABLE>
(1) The Company and the Selling Stockholder have agreed to indemnify the several
Underwriters against certain liabilities, including liabilities under the
Securities Act of 1933. See "Underwriting."
(2) Before deduction of expenses payable by the Company estimated at $825,000.
(3) The Company has granted the Underwriters an option, exercisable for 30 days
from the date of this Prospectus, to purchase a maximum of 1,891,500
additional shares to cover over-allotments of shares. If the option is
exercised in full, the total Price to Public will be $159,516,500,
Underwriting Discounts and Commissions will be $10,006,035, and Proceeds to
the Company will be $148,376,365.
------------------
The Shares are offered by the several Underwriters when, as and if
delivered to and accepted by the Underwriters and subject to their right to
reject orders in whole or in part. It is expected that the Shares will be ready
for delivery on or about December 20, 1996, against payment in immediately
available funds.
Credit Suisse First Boston
Donaldson, Lufkin & Jenrette
Securities Corporation
Howard, Weil, Labouisse, Friedrichs
Incorporated
J.P. Morgan & Co.
Petrie Parkman & Co.
The date of this Prospectus is December 16, 1996.
<PAGE> 2
TITAN EXPLORATION, INC.
PERMIAN BASIN PRODUCING PROPERTIES
[MAP OF THE COMPANY'S PRODUCING PROPERTIES]
---------------------
The Company intends to furnish its stockholders annual reports containing
consolidated financial statements certified by its independent auditors and
quarterly reports for each of the first three quarters of each fiscal year
containing unaudited financial information.
---------------------
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OF
THE COMPANY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NASDAQ NATIONAL MARKET OR
OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
DURING THIS OFFERING, CERTAIN PERSONS AFFILIATED WITH PERSONS PARTICIPATING
IN THE DISTRIBUTION MAY ENGAGE IN TRANSACTIONS FOR THEIR OWN ACCOUNTS OR FOR THE
ACCOUNTS OF OTHERS IN THE COMMON STOCK OF THE COMPANY PURSUANT TO EXEMPTIONS
FROM RULES 10B-6, 10B-7, AND 10B-8 UNDER THE SECURITIES EXCHANGE ACT OF 1934.
2
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the detailed
information and financial statements and the notes thereto appearing elsewhere
in this Prospectus. The pro forma information gives effect to the reorganization
of the Company, the 1995 Acquisition and the 1996 Acquisition. See "The
Company." Unless otherwise indicated, the information in this Prospectus assumes
no exercise of the Underwriters' over-allotment option. Certain terms relating
to the oil and gas industry are defined in "Glossary of Oil and Gas Terms." As
noted in the glossary, PV-10 is calculated without giving effect to income
taxes.
THE COMPANY
Titan is an independent energy company engaged in the exploration,
development and acquisition of oil and gas properties. Since its inception in
March 1995, the Company has experienced significant growth in reserves,
production and cash flow by acquiring and exploiting producing properties
primarily in the Permian Basin of west Texas and southeastern New Mexico.
In December 1995, the Company acquired a concentrated group of Permian
Basin producing oil and gas properties from a large independent company for
approximately $40.6 million (the "1995 Acquisition"). On October 31, 1996, the
Company acquired additional Permian Basin producing properties from a major
integrated company for approximately $135.5 million (the "1996 Acquisition"). As
of September 30, 1996, the Company had pro forma estimated net proved reserves
of approximately 17.8 MMBbls of oil and 280.8 Bcf of natural gas, or an
aggregate of 64.6 MMBOE with a PV-10 of $292.1 million. If, in calculating the
PV-10, the Company's oil and gas prices at October 31, 1996 were substituted for
the prices at September 30, 1996, the PV-10 would be $351.9 million. The prices
of the Company's oil decreased 4% and gas increased 33% from September 30, 1996
to October 31, 1996. Approximately 62% of these reserves were classified as
proved developed. The Company acquired, explored for and developed its reserves
for an average reserve replacement cost of approximately $2.73 per BOE through
September 30, 1996, assuming the 1996 Acquisition was consummated on September
30, 1996. Pro forma production for the nine months ended September 30, 1996 was
12,227 BOE per day, resulting in an annualized pro forma proved reserves to
production ratio of 14.5 to one.
The Company prefers to acquire properties over which it can exercise
operating control. The Company operated 456 gross wells (389 net wells) on a pro
forma basis at September 30, 1996, and these operated properties represented
approximately 71% of its pro forma proved developed producing PV-10 and 83% of
the Company's pro forma PV-10 attributable to proved reserves at September 30,
1996. The Company's emphasis on controlling the operation of its properties
enables the Company to manage expenses, capital allocation and other aspects of
development and exploration.
The Company's oil and gas properties are located in approximately 60 fields
in the Permian Basin. Approximately 70% of the Company's PV-10 of total proved
reserves is concentrated in 12 principal fields located in this region. The
region is characterized by complex geology with numerous known producing
horizons and provides significant opportunities to increase reserves, production
and ultimate recoveries through development, exploratory and horizontal
drilling, recompletions, secondary and tertiary recovery methods, and use of 3-D
seismic and other advanced technologies.
The Company believes that its personnel provide it with competitive
advantages for exploiting these opportunities in the Permian Basin and other
complex producing basins in North America. Members of the Company's management
team have an average of 25 years experience in the oil and gas industry and have
operating experience in all aspects of the industry, in particular deep well and
horizontal drilling. They have formulated and supervised acquisitions,
exploration projects, development drilling programs and production enhancement
plans, including workovers and enhanced recovery projects. In addition,
management has a significant equity investment in the Company. Giving effect to
this offering and assuming the exercise by management of all of their options to
acquire Common Stock, management will beneficially own an aggregate of 20% of
the Company's outstanding Common Stock.
3
<PAGE> 4
BUSINESS STRATEGY
The Company's strategy is to grow reserves, production and net income per
share through (i) the acquisition of producing properties that provide
significant development and exploratory drilling potential, (ii) the
exploitation and development of its reserve base, (iii) the exploration for oil
and gas reserves and (iv) the implementation of a low operating and overhead
cost structure.
o Acquisitions. The Company seeks to acquire oil and gas properties that
provide opportunities for the addition of reserves, production and value
through low risk exploitation and development, high-potential exploration
and control of operations. The Company believes that these criteria can be
met in the Permian Basin and in other North American basins that have had
high historical cumulative production levels that represent a relatively
small percentage of the recoverable in-place reserves. At September 30,
1996, the Company had acquired and developed 64.6 MMBOE of proved oil and
gas reserves at an average reserve replacement cost of $2.73 per BOE,
assuming the 1996 Acquisition was consummated on September 30, 1996, which
compares to an average reserve replacement cost of $4.85 per BOE (for 1993
through 1995) for the 184 independent oil and gas companies included in
the Arthur Andersen 1996 Oil and Gas Reserve Disclosures.
o Exploitation of Reserve Base. The Company engages in horizontal and
infill drilling activities, major workovers, recompletions, secondary and
tertiary recovery operations, and other production enhancement techniques
in order to increase reserves and production. Through 1998, subject to
market conditions and drilling and operating results, the Company expects
to spend approximately $22 million to drill 14 proved locations on
Company-operated properties and $21 million to drill 129 unproven
locations, 39 of which are on Company-operated properties and 90 of which
are on Company-owned, but nonoperated, properties.
o Exploration Activities. The Company seeks to apply management's extensive
geological and drilling expertise and 3-D seismic technology to identify
and develop exploration projects. As part of its exploration strategy, the
Company attempts to reduce the costs and risks of its exploration
activities by, in selected circumstances, applying 3-D seismic technology,
drilling wells with multiple pay objectives in known producing areas and
selling interests in its exploration prospects to industry partners. A
large portion of the Company's efforts have focused on deep well
opportunities in historically prolific fields. Through 1998, subject to
market conditions and drilling and operating results, the Company expects
to spend approximately $30 million to drill approximately 40 exploratory
locations on Company-owned properties.
o Low Cost Structure. The Company has implemented and plans to maintain a
low overhead and operating cost structure to enhance the profitability and
the exploitation potential of its properties. The Company provides
incentive stock awards to its senior management team in lieu of
comparatively higher salary levels in order to align management's
interests with stockholders, maintain relatively low general and
administrative expense and increase the amount of cash flow available for
reinvestment by the Company. The Company also seeks to be an efficient
operator and achieve reductions in labor and other field-level costs from
those incurred by previous operators of its properties. By operating a
significant portion of its daily production, the Company believes it is
well positioned to control the expenses and timing of development and
exploitation of such properties and to better manage such cost reduction
efforts.
4
<PAGE> 5
THE OFFERING
<TABLE>
<S> <C>
Common Stock Offered:
By the Company......................................... 12,500,000 Shares
By the Selling Stockholder............................. 110,000 Shares
Common Stock to be outstanding after this offering....... 32,050,013 Shares(1)
Use of Proceeds by the Company........................... For repayment of indebtedness
incurred in connection with the
1996 Acquisition. See "Use of
Proceeds."
Nasdaq National Market Symbol............................ "TEXP"
</TABLE>
- ---------------
(1) Does not include (i) 3,631,350 shares of Common Stock issuable upon exercise
of outstanding employee stock options, with an exercise price of $2.08 per
share, and (ii) 85,000 shares of Common Stock issuable upon exercise of
outstanding employee stock options, with an exercise price equal to the
Price to Public on the cover page of this Prospectus. See "Capitalization,"
"Management" and Note 9 of Notes to Consolidated Financial Statements.
5
<PAGE> 6
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
PERIOD ENDED NINE MONTHS ENDED
DECEMBER 31, 1995 SEPTEMBER 30, 1996
-------------------------- --------------------------
PRO FORMA AS PRO FORMA AS
HISTORICAL ADJUSTED(1) HISTORICAL ADJUSTED(1)
---------- ------------ ---------- ------------
<S> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Revenues..................................... $ 985 $ 49,591 $ 10,377 $ 42,554
-------- ------- ------ -------
Expenses:
Oil and gas production.................... 304 17,435 4,339 13,820
General and administrative................ 1,546 4,625 1,452 3,469
Amortization of stock option awards....... 576 576 576 576
Exploration and abandonment............... 490 490 110 110
Depletion, depreciation and
amortization............................ 299 16,832 2,269 12,001
Interest.................................. 97 2,145 1,179 1,595
Other..................................... (796) (796) (336) (336)
-------- ------- ------ -------
Total expenses............................... 2,516 41,307 9,589 31,235
-------- ------- ------ -------
Net income (loss)............................ (1,531) 5,385 (2,210) 7,358
Net income (loss) per share.................. (.11) .18 (.12) .21
Weighted average shares outstanding.......... 14,066 29,609 18,835 34,437
CONSOLIDATED STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in):
Operating activities...................... $ (1,764) $ 5,653
Investing activities...................... (47,563) (12,763)
Financing activities...................... 55,540 11,700
OTHER CONSOLIDATED FINANCIAL DATA:
Capital expenditures......................... $ 43,811 $ 17,763
EBITDAX(2)................................... (69) $ 28,327 4,922 $ 25,601
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
-------------------------
PRO FORMA AS
HISTORICAL ADJUSTED(1)
---------- ------------
<S> <C> <C>
CONSOLIDATED BALANCE SHEET DATA:
Cash and cash equivalents............................................ $ 10,803 $ 10,803
Working capital...................................................... 8,760 8,453
Oil and gas properties, net.......................................... 60,168 187,202
Total assets......................................................... 74,824 202,308
Total debt........................................................... 28,000 25,827
Total stockholders' equity........................................... 37,951 166,001
</TABLE>
- ---------------
(1) Assumes the 1995 Acquisition, the 1996 Acquisition, the Conversion (see "The
Company"), this offering and the application of the proceeds therefrom had
taken place on January 1, 1995 for purposes of the Consolidated Statement of
Operations Data, Consolidated Statement of Cash Flows Data and Other
Consolidated Financial Data and assumes the 1996 Acquisition, the
Conversion, this offering and the application of the proceeds therefrom had
taken place on September 30, 1996 for purposes of the Consolidated Balance
Sheet Data.
(2) EBITDAX is presented because of its wide acceptance as a financial indicator
of a company's ability to service or incur debt. EBITDAX (as used herein) is
calculated by adding interest, income taxes, depletion, depreciation and
amortization, amortization of stock option awards, and exploration and
abandonment costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. EBITDAX should not be
considered as an alternative to earnings (loss) or operating earnings
(loss), as defined by generally accepted accounting principles, as an
indicator of the Company's financial performance, as an alternative to cash
flow, as a measure of liquidity or as being comparable to other similarly
titled measures of other companies.
6
<PAGE> 7
SUMMARY RESERVE INFORMATION
<TABLE>
<CAPTION>
DECEMBER 31, 1995 SEPTEMBER 30, 1996
-------------------------- --------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1)
---------- ------------ ---------- ------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Estimated Proved Reserves(2):
Oil (MBbls).................................. 6,146 16,460 6,563 17,843
Gas (MMcf)................................... 134,995 242,039 179,565 280,824
MBOE (6 Mcf per Bbl)......................... 28,645 56,800 36,491 64,647
Proved developed reserves as a percentage of
proved reserves.............................. 47% 68% 42% 62%
PV-10(3)....................................... $ 89,753 $198,341 $ 144,532 $292,080
Standardized Measure of Discounted Future Net
Cash Flows(4)................................ $ 66,352 $176,421 $ 104,678 $229,199
</TABLE>
- ---------------
(1) Gives effect to the 1996 Acquisition as if it had occurred on the day
indicated.
(2) The reserve and present value data at December 31, 1995 have been prepared
by the Company. The reserve and present value data at September 30, 1996
have been prepared by Williamson Petroleum Consultants, Inc. ("Williamson"),
independent petroleum engineering consultants. For additional information
relating to the Company's oil and gas reserves, see "Business and
Properties -- Oil and Natural Gas Reserves" and Note 14 of the Notes to the
Consolidated Financial Statements of the Company. Summaries of the October
1, 1996 reserve reports and the letter of Williamson with respect thereto
are included as Appendix A to this Prospectus.
(3) The present value of future net revenue attributable to the Company's
reserves was prepared using prices in effect at the end of the respective
periods presented, discounted at 10% per annum on a pre-tax basis. These
amounts reflect the effects of the Company's hedging activities. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
(4) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the present value of future net revenues after income
taxes discounted at 10%. These amounts reflect the effects of the Company's
hedging activities. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Matters."
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
PERIOD ENDED NINE MONTHS
DECEMBER 31, 1995 ENDED SEPTEMBER 30, 1996
--------------------------- ---------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1)
---------- ------------ ---------- ------------
<S> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)............................... 30 2,004 388 1,311
Gas (MMcf)................................ 245 17,952 2,725 12,235
Total (MBOE).............................. 71 4,996 842 3,350
AVERAGE SALES PRICE PER UNIT(2):
Oil (per Bbl)............................. $16.80 $14.23 $17.25 17.30
Gas (per Mcf)............................. .97 1.16 1.30 1.61
BOE....................................... 10.46 9.88 12.16 12.66
EXPENSES PER BOE:
Production costs, including production
taxes.................................. $ 4.28 $ 3.49 $ 5.15(3) $ 4.13(3)
General and administrative................ 21.77 .93 1.72 1.04
Depletion, depreciation and
amortization........................... 4.21 3.37 2.69 3.58
</TABLE>
- ---------------
(1) Gives effect to the 1995 Acquisition and the 1996 Acquisition as if those
transactions had occurred on January 1, 1995.
(2) Reflects results of hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters."
(3) Includes approximately $.77 per BOE of production costs attributable to
necessary rework operations on the 1995 Acquisition properties.
7
<PAGE> 8
RISK FACTORS
This Prospectus contains forward-looking statements. The words
"anticipate," "believe," "expect," "plan," "intend," "estimate," "project,"
"will," "could," "may" and similar expressions are intended to identify
forward-looking statements. These statements include information regarding oil
and gas reserves, future drilling and operations, future production of oil and
gas and future net cash flows. Such statements reflect the Company's current
views with respect to future events and financial performance and involve risks
and uncertainties, including without limitation the risks described in "Risk
Factors." Should one or more of these risks or uncertainties occur, or should
underlying assumptions prove incorrect, actual results may vary materially and
adversely from those anticipated, believed, estimated or otherwise indicated.
Investors should carefully consider the following risk factors, in addition to
other information contained in this Prospectus, before purchasing the shares of
Common Stock offered hereby.
VOLATILITY OF OIL AND GAS PRICES
The Company's revenues, operating results and future rate of growth are
highly dependent upon the prices received for the Company's oil and gas.
Historically, the markets for oil and gas have been volatile and may continue to
be volatile in the future. Revenues generated from the oil and gas operations of
the Company will be highly dependent on the future prices of oil and gas.
Various factors beyond the control of the Company will affect prices of oil and
gas, including the worldwide and domestic supplies of oil and gas, the ability
of the members of the Organization of Petroleum Exporting Countries ("OPEC") to
agree to and maintain oil price and production controls, political instability
or armed conflict in oil-producing regions, the price and level of foreign
imports, the level of consumer demand, the price and availability of alternative
fuels, the availability of pipeline capacity, weather conditions, domestic and
foreign governmental regulations and taxes and the overall economic environment.
Recent political instability in the Middle East has had a significant
effect on world oil markets. In the third quarter of 1996, prices of oil
experienced substantial price fluctuations, including large price escalations,
resulting in part from Iraq's attack against the Kurdish rebels in Northern Iraq
and the subsequent United States response. On June 30, 1996, the posted price
for West Texas Intermediate Crude was $19.50 per Bbl, as posted by the Company's
major purchaser. On September 30, 1996, the posted price for West Texas
Intermediate Crude was $22.75 per Bbl, as posted by the Company's major
purchaser. The Company is unable to predict the long-term effects of these and
other conditions on the prices of oil. Moreover, it is possible that prices for
any oil the Company produces will be lower than current prices received by the
Company.
Historically, the market for natural gas has been volatile and is likely to
continue to be volatile in the future. Prices for natural gas are subject to
wide fluctuation in response to market uncertainty, changes in supply and demand
and a variety of additional factors (including those referred to in the first
paragraph of this Risk Factor), all of which are beyond the Company's control.
Any significant decline in the price of oil or gas would adversely affect
the Company's revenues and operating income and may require a reduction in the
carrying value of the Company's oil and gas properties. See "Risk
Factors -- Uncertainty of Reserve Information and Future Net Revenue Estimates,"
"Business and Properties -- Competition" and "Business and
Properties -- Governmental Regulation."
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES
There are numerous uncertainties inherent in estimating quantities of
proved reserves and their values, including many factors beyond the Company's
control. The reserve information set forth in this Prospectus represents
estimates only. Although the Company believes such estimates to be reasonable,
reserve estimates are imprecise and should be expected to change as additional
information becomes available.
Estimates of oil and gas reserves, by necessity, are projections based on
engineering data, and there are uncertainties inherent in the interpretation of
such data as well as the projection of future rates of production and the timing
of development expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that are difficult to
measure. The accuracy of any reserve estimate is
8
<PAGE> 9
a function of the quality of available data, engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and gas
reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions concerning future oil and
gas prices, future operating costs, severance and excise taxes, development
costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery and estimates of the future net cash flows expected therefrom may
vary substantially. Moreover, there can be no assurance that the Company's
reserves will ultimately be produced or that the Company's proved undeveloped
reserves will be developed within the periods anticipated. Any significant
variance in the assumptions could materially affect the estimated quantity and
value of the Company's reserves. Actual production, revenues and expenditures
with respect to the Company's reserves will likely vary from estimates, and such
variances may be material. See "Business and Properties -- Oil and Natural Gas
Reserves."
RISK OF HEDGING ACTIVITIES
The Company's use of energy swap arrangements to reduce its sensitivity to
oil and gas price volatility is subject to a number of risks. If the Company's
reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, the Company would be required to satisfy its obligations
under fixed price sales and hedging contracts on potentially unfavorable terms
without the ability to hedge that risk through sales of comparable quantities of
its own production. Further, the terms under which the Company enters into fixed
price sales and hedging contracts are based on assumptions and estimates of
numerous factors such as cost of production and pipeline and other
transportation costs to delivery points. Substantial variations between the
assumptions and estimates used by the Company and actual results experienced
could materially adversely affect the Company's anticipated profit margins and
its ability to manage the risk associated with fluctuations in oil and gas
prices. Additionally, the fixed price sales and hedging contracts limit the
benefits the Company will realize if actual prices rise above the contract
prices.
In addition, fixed price sales and hedging contracts are subject to the
risk that the other party may prove unable or unwilling to perform its
obligations under such contracts. Any significant nonperformance could have a
material adverse financial effect on the Company.
As of September 30, 1996, excluding the effects of the 1996 Acquisition,
the Company had approximately 58% of its oil production and approximately 73% of
its natural gas production (based on the first three quarters' production)
committed to hedging contracts through December 1996. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
LIMITED OPERATING HISTORY; RAPID GROWTH
The Company, which began operations in March 1995, has a brief operating
history upon which investors may base their evaluation of the Company's
performance. As a result of its brief operating history and rapid growth, the
operating results from the Company's historical periods are not readily
comparable and may not be indicative of future results. There can be no
assurance that the Company will continue to experience growth in, or maintain
its current level of, revenues, oil and gas reserves or production. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
The Company's rapid growth has placed significant demands on its
administrative, operational and financial resources. Any future growth of the
Company's oil and gas reserves, production and operations would place
significant further demands on the Company's financial, operational and
administrative resources. The Company has hired eight new employees and plans to
hire 15 to 20 additional employees as a result of the 1996 Acquisition. The
Company's future performance and profitability will depend in part on its
ability to successfully integrate the administrative and financial functions of
acquired properties into the Company's operations, to hire additional personnel
and to implement necessary enhancements to its management systems
9
<PAGE> 10
to respond to changes in its business. There can be no assurance that the
Company will be successful in these efforts. The inability of the Company to
integrate acquired properties, to hire additional personnel or to enhance its
management systems could have a material adverse effect on the Company's results
of operations.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial capital
expenditures for the exploration, development, acquisition and production of its
oil and gas reserves. The Company intends to finance such capital expenditures
primarily with funds provided by operations and borrowings under its $250
million Credit Agreement, which currently has a borrowing base of $165 million.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources." The cost of the 1995 Acquisition
was approximately $40.6 million, and the cost of the 1996 Acquisition was
approximately $135.5 million. The Company's direct capital expenditures for oil
and gas producing activities, excluding property acquisitions, were $2.0 million
for the nine months ended December 31, 1995 and $7.5 million for the nine months
ended September 30, 1996.
If revenues decrease as a result of lower oil or gas prices or otherwise,
the Company may have limited ability to expend the capital necessary to replace
its reserves or to maintain production at current levels, resulting in a
decrease in production over time. If the Company's cash flow from operations and
availability under the Credit Agreement are not sufficient to satisfy its
capital expenditure requirements, there can be no assurance that additional debt
or equity financing will be available to meet these requirements. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
RESERVE REPLACEMENT RISK
The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable. The
proved reserves of the Company will generally decline as reserves are depleted,
except to the extent that the Company conducts successful exploration or
development activities or acquires properties containing proved reserves, or
both. In order to increase reserves and production, the Company must continue
its development and exploration drilling and recompletion programs or undertake
other replacement activities. The Company's current strategy includes increasing
its reserve base through acquisitions of producing properties, continued
exploitation of its existing properties and exploration of new and existing
properties. There can be no assurance, however, that the Company's planned
development and exploration projects and acquisition activities will result in
significant additional reserves or that the Company will have continuing success
drilling productive wells at low finding and development costs. Furthermore,
while the Company's revenues may increase if prevailing oil and gas prices
increase significantly, the Company's finding costs for additional reserves
could also increase. For a discussion of the Company's reserves, see "Business
and Properties -- Oil and Natural Gas Reserves."
DRILLING AND OPERATING RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
gas may involve unprofitable efforts, not only from dry wells, but from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including economic
conditions, mechanical problems, title problems, weather conditions, compliance
with governmental requirements and shortages or delays in the delivery of
equipment and services. The Company's future drilling activities may not be
successful and, if unsuccessful, such failure may have a material adverse effect
on the Company's future results of operations and financial condition.
10
<PAGE> 11
In addition, the Company's use of 3-D seismic requires greater pre-drilling
expenditures than traditional drilling strategies. There can be no assurance
that the Company's drilling program will be successful or that unsuccessful
drilling efforts will not have a material adverse effect on the Company.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and gas, such as fires, natural
disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others.
The Company expects to drill a number of deep vertical and horizontal wells
in the future. The Company's deep and/or horizontal drilling activities involve
greater risk of mechanical problems than other drilling operations. Future
drilling activity may be significantly more expensive than such activity to
date.
As protection against operating hazards, the Company maintains insurance
coverage against some, but not all, potential losses. The Company may elect to
self-insure in circumstances in which management believes that the cost of
insurance, although available, is excessive relative to the risks presented. The
occurrence of an event that is not covered, or not fully covered, by insurance
could have a material adverse effect on the Company's financial condition and
results of operations.
ACQUISITION RISKS
The Company's rapid growth since its inception in March 1995 has been
largely the result of acquisitions of producing properties. The Company expects
to continue to evaluate and pursue acquisition opportunities available on terms
management considers favorable to the Company. The successful acquisition of
producing properties requires an assessment of recoverable reserves, future oil
and gas prices, operating costs, potential environmental and other liabilities
and other factors beyond the Company's control. This assessment is necessarily
inexact and its accuracy is inherently uncertain. In connection with such an
assessment, the Company performs a review of the subject properties it believes
to be generally consistent with industry practices. This review, however, will
not reveal all existing or potential problems, nor will it permit a buyer to
become sufficiently familiar with the properties to assess fully their
deficiencies and capabilities. Inspections may not be performed on every well,
and structural and environmental problems are not necessarily observable even
when an inspection is undertaken. The Company generally assumes preclosing
liabilities, including environmental liabilities, and generally acquires
interests in the properties on an "as is" basis. With respect to its
acquisitions to date, the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. There can be no
assurance that the Company's acquisitions will be successful. Any unsuccessful
acquisition could have a material adverse effect on the Company.
COMPLIANCE WITH GOVERNMENT REGULATIONS
The Company's business is subject to federal, state and local laws and
regulations relating to the exploration for, and the development, production and
transportation of, oil and gas, as well as safety matters. Although the Company
believes it is in substantial compliance with all applicable laws and
regulations, the requirements imposed by such laws and regulations are
frequently changed and subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their effect
on its operations. Significant expenditures may be required to comply with
governmental laws and regulations and may have a material adverse effect on the
Company's financial condition and results of operations. See "Business and
Properties -- Governmental Regulation."
COMPLIANCE WITH ENVIRONMENTAL REGULATIONS
The Company's operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. The implementation of new, or the modification of
existing, laws or regulations could have a material adverse effect on the
Company. The discharge of oil, gas or other pollutants into the air, soil or
water may give rise to significant liabilities on the part of the Company to the
government and third parties and may require the Company to incur substantial
costs of remediation. Moreover, the Company has agreed to indemnify sellers of
producing properties
11
<PAGE> 12
purchased by the Company in the 1995 Acquisition and the 1996 Acquisition
against environmental claims associated with such properties. No assurance can
be given that existing environmental laws or regulations, as currently
interpreted or reinterpreted in the future, or future laws or regulations will
not materially adversely affect the Company's results of operations and
financial condition or that material indemnity claims will not arise against the
Company with respect to properties acquired by the Company. See "Business and
Properties -- Environmental Matters."
MARKETABILITY OF PRODUCTION
The marketability of the Company's production depends in part upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities. Most of the Company's natural gas is delivered
through gas gathering systems and gas pipelines that are not owned by the
Company. Federal and state regulation of oil and gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its oil and gas. Any dramatic change in market factors could
have a material adverse effect on the Company.
The PV-10 referred to in this Prospectus should not be construed as the
current market value of the estimated oil and gas reserves attributable to the
Company's properties. In accordance with applicable requirements, the estimated
discounted future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. Actual future net cash flows also
will be affected by factors such as the amount and timing of actual production,
supply and demand for oil and gas, curtailments or increases in consumption by
gas purchasers and changes in governmental regulations or taxation. The timing
of actual future net cash flows from proved reserves, and thus their actual
present value, will be affected by the timing of both the production and the
incurrence of expenses in connection with development and production of oil and
gas properties. In addition, the 10% discount factor, which is required to be
used to calculate discounted future net cash flows for reporting purposes, is
not necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with the Company or the oil and
gas industry in general.
DEPENDANCE ON KEY PERSONNEL
The Company's success has been and will continue to be highly dependent on
Jack Hightower, its Chairman of the Board and Chief Executive Officer, and a
limited number of other senior management personnel. Loss of the services of Mr.
Hightower or any of those other individuals could have a material adverse effect
on the Company's operations. The Company maintains a $3.0 million key man life
insurance policy on the life of Mr. Hightower, but no other senior management
personnel. In addition, as a result of the 1996 Acquisition, the Company plans
to employ 15 to 20 new employees and will face competition for such personnel
from other companies. There can be no assurance that the Company will be
successful in hiring or retaining key personnel. The Company's failure to hire
additional personnel or retain its key personnel could have a material adverse
effect on the Company.
CONTROL BY EXISTING STOCKHOLDERS
Upon completion of this offering, directors, executive officers and
principal stockholders of the Company, and certain of their affiliates, will
beneficially own approximately 59% of the Company's outstanding Common Stock
(approximately 56% if the Underwriters exercise their over-allotment option in
full). Accordingly, these stockholders, as a group, will be able to control the
outcome of stockholder votes, including votes concerning the election of
directors, the adoption or amendment of provisions in the Company's Certificate
of Incorporation or Bylaws and the approval of mergers and other significant
corporate transactions. See "Description of Capital Stock -- Common Stock." The
existence of these levels of ownership concentrated in a few persons makes it
unlikely that any other holder of Common Stock will be able to affect the
management or direction of the Company. These factors may also have the effect
of delaying or preventing a change in the management or voting control of the
Company, including transactions that otherwise could involve payment of a
premium over prevailing market prices to holders of Common Stock. See "Principal
and Selling Stockholders."
12
<PAGE> 13
COMPETITION
The Company operates in the highly competitive areas of oil and gas
exploration, development, acquisition and production with other companies, many
of which have substantially larger financial resources, staffs and facilities.
In seeking to acquire desirable producing properties or new leases for future
exploration and in marketing its oil and gas production, the Company faces
intense 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 the Company. See "Business and Properties -- Competition."
This highly competitive environment could have a material adverse effect on the
Company.
CUMULATIVE VOTING; BLANK CHECK PREFERRED STOCK
The Company's Certificate of Incorporation (i) provides for cumulative
voting for the election of directors and (ii) authorizes the Board of Directors
of the Company to issue up to 10,000,000 shares of preferred stock without
stockholder approval and to set the rights, preferences and other designations,
including voting rights, of those shares as the Board of Directors may
determine. These provisions, alone or in combination with each other and with
the matters described in "Risk Factors -- Control by Existing Stockholders," may
discourage transactions involving actual or potential changes of control of the
Company, including transactions that otherwise could involve payment of a
premium over prevailing market prices to holders of Common Stock. The Company
also is subject to provisions of the Delaware General Corporation Law that may
make some business combinations more difficult. See "Description of Capital
Stock -- Delaware Law Provisions."
ABSENCE OF DIVIDENDS ON COMMON STOCK
The Company does not currently intend to pay regular cash dividends on the
Common Stock. In addition, the Credit Agreement prohibits the payment of cash
dividends. See "Dividend Policy."
SHARES ELIGIBLE FOR FUTURE SALE; REGISTRATION RIGHTS
Sales of a substantial number of shares of Common Stock in the public
market following this offering could adversely affect the market price for the
Common Stock. The Company believes all of the shares of Common Stock currently
outstanding will be eligible for sale under Rule 144 on October 1, 1998, based
on current Securities and Exchange Commission (the "Commission") rules and
subject to compliance with the manner-of-sale, volume and other limitations of
Rule 144. The Commission has proposed an amendment to Rule 144 that, if adopted,
could permit those shares to be sold earlier. Some investors have the right to
require the Company to register the public resale of their shares before that
time. See "Shares Eligible for Future Sale" and "Description of Capital
Stock -- Registration Rights."
IMMEDIATE AND SUBSTANTIAL DILUTION
Purchasers of the Common Stock in the offering will experience an immediate
and substantial dilution in pro forma net tangible book value per share. These
investors will also experience additional dilution upon the exercise of
outstanding options. See "Dilution."
NO PRIOR PUBLIC MARKET; POSSIBLE STOCK PRICE VOLATILITY
Before this offering, there has been no public market for the Common Stock,
and an active public market for the Common Stock may not develop or be
sustained. The initial public offering price will be determined through
negotiations between the Company and the Representatives of the Underwriters
based on several factors that may not be indicative of future market prices. See
"Underwriting" for a discussion of the factors to be considered in determining
the initial public offering price. The trading price of the Common Stock and the
price at which the Company may sell securities in the future could be subject to
large fluctuations in response to changes in government regulations, quarterly
variations in operating results, litigation, general market conditions, the
prices of oil and gas, the liquidity of the Company and the Company's ability to
raise additional funds and other events.
13
<PAGE> 14
THE COMPANY
Titan Exploration, Inc. is an independent energy company engaged in the
exploration, development and acquisition of oil and gas properties. The Company
was formed in 1996 for the purpose of becoming the holding company for Titan
Resources, L.P. (the "Partnership") pursuant to the terms of an Exchange
Agreement and Plan of Reorganization dated September 30, 1996 (the "Exchange
Agreement"). The Partnership was formed in March 1995 and has grown primarily
through acquisitions of oil and gas properties and the exploitation of these
properties. See "Business and Properties -- Principal Oil and Gas Properties."
Under the Exchange Agreement, effective September 30, 1996, (i) the limited
partners of the Partnership transferred all of their limited partnership
interests to the Company in exchange for an aggregate of 19,318,199 shares of
Common Stock, and (ii) the shareholders of Titan Resources I, Inc., a Texas
corporation that is the general partner of the Partnership, transferred all of
the issued and outstanding stock of that corporation to the Company in exchange
for an aggregate of 231,814 shares of Common Stock. These transactions are
referred to in this Prospectus as the "Conversion." As a result of the
Conversion, Titan Exploration, Inc. owns, directly or indirectly, all the
partnership interests in the Partnership and conducts its active business
operations through the Partnership. References to the "Company" or to "Titan"
are to Titan Exploration, Inc. and its predecessors and subsidiaries, including
the Partnership.
Titan's principal executive offices are located at 500 West Texas, Suite
500, Midland, Texas 79701 and its telephone number is (915) 682-6612.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the 12,500,000 shares of
Common Stock offered by the Company are estimated to be approximately $128.1
million ($147.6 million if the Underwriters exercise their over-allotment option
in full), based on the initial public offering price of $11.00 per share and
after deducting the underwriting discounts and commissions and estimated
offering expenses.
The Company intends to use the net proceeds to repay indebtedness under the
Company's Amended and Restated Credit Agreement, dated October 31, 1996 (the
"Credit Agreement"), incurred in connection with the 1996 Acquisition. The
Company intends to reborrow under the Credit Agreement from time to time as
necessary to fund exploration, development and acquisition activities and other
general corporate purposes. At October 31, 1996, the outstanding principal
balance of indebtedness under the Credit Agreement was $154.5 million, a
substantial amount of which was incurred in connection with the 1996
Acquisition. For the nine months ended September 30, 1996, the Credit Agreement
had an average interest rate of 6.75% per annum, and the indebtedness has a
final maturity of January 1, 2001. As a result of an interest rate swap
agreement, the Company effectively has a fixed interest rate of 6.72% on $10
million of the revolving portion of the Credit Agreement. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" for a description of the Credit
Agreement. Affiliates of J.P. Morgan Securities Inc. (one of the Underwriters)
and First Union Corporation (an owner of in excess of 5% of the Common Stock)
are participants in that indebtedness and will each be entitled to receive 20%
of any repayments of that indebtedness. See "Certain Transactions" and
"Underwriting."
DIVIDEND POLICY
The Company has never declared or paid cash dividends on its Common Stock
and anticipates that all future earnings will be retained for development of its
business. In addition, the Credit Agreement prohibits the payment of cash
dividends on Common Stock. The Board of Directors of the Company may review the
Company's dividend policy from time to time in light of, among other things, the
Company's earning and financial position and limitations imposed by the
Company's debt instruments. See "Management's Discussion and Analysis of
Financial Condition and Results of Operation -- Liquidity and Capital
Resources."
14
<PAGE> 15
DILUTION
The Company's pro forma net tangible book value at September 30, 1996 was
$36,954,000, or approximately $1.89 per share of Common Stock. Net tangible book
value per share represents the amount of total tangible assets of the Company
reduced by the amount of the Company's total liabilities, divided by the number
of shares of Common Stock outstanding. After giving effect to the Company's
receipt of the estimated net proceeds from the sale of 12,500,000 shares of
Common Stock in this offering at the initial public offering price of $11.00 per
share, the Company's pro forma as adjusted net tangible book value as of
September 30, 1996 would have been $165,004,000, or $5.15 per share. This
represents an immediate increase in pro forma net tangible book value of $3.26
per share to the Company's stockholders and an immediate dilution in pro forma
net tangible book value of $5.85 per share to new investors purchasing shares in
this offering. The following table illustrates the per share dilution in pro
forma net tangible book value to new investors:
<TABLE>
<S> <C> <C>
Initial public offering price per share............................... $11.00
Pro forma net tangible book value per share of Common Stock at
September 30, 1996............................................... $1.89
Increase per share of Common Stock attributable to new investors.... 3.26
-----
Pro forma as adjusted net tangible book value per share of Common
Stock after this offering........................................... 5.15
------
Pro forma as adjusted dilution per share to new investors............. $ 5.85
======
</TABLE>
The following table sets forth the number of shares of Common Stock
purchased from the Company, the total consideration paid, and the average price
per share paid by existing stockholders and to be paid (at the initial public
offering price of $11.00 per share) by purchasers of shares offered hereby
(before deducting underwriting discounts and commissions and estimated offering
expenses):
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION
--------------------- ----------------------- AVERAGE PRICE
NUMBER PERCENTAGE AMOUNT PERCENTAGE PER SHARE
------ ---------- -------- ---------- -------------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Existing stockholders....... 19,550 61.0% $ 40,540 22.8% $ 2.07
New investors............... 12,500 39.0 137,500 77.2 11.00
------ ---------- -------- ---------- -------------
Total............. 32,050 100.0% $178,040 100.0% $ 5.56
====== ======== ======== ======== ==========
</TABLE>
The preceding tables assume no exercise of any stock options to purchase
Common Stock outstanding at September 30, 1996. The preceding table excludes (i)
3,631,350 shares of Common Stock issuable upon exercise of options outstanding
at September 30, 1996, with an exercise price of $2.08 per share, and (ii)
85,000 shares issuable upon exercise of options that have been granted under the
Company's 1996 Incentive Plan with an exercise price equal to the Price to
Public set forth on the cover page of this Prospectus. A total of 850,000 shares
are reserved for future issuance under the Company's 1996 Incentive Plan. See
"Management -- Employee Benefit Plans -- 1996 Incentive Plan" and Note 9 of
Notes to Consolidated Financial Statements.
15
<PAGE> 16
CAPITALIZATION
The following table sets forth the capitalization of the Company (i) as of
September 30, 1996, (ii) pro forma to give effect to the 1996 Acquisition, and
(iii) pro forma as adjusted to reflect the estimated net proceeds from the
Company's sale of 12,500,000 shares of Common Stock pursuant to this offering.
This table should be read in conjunction with the Consolidated Financial
Statements and related notes in the Prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
---------------------------------------------
PRO FORMA
AS
HISTORICAL PRO FORMA ADJUSTED(2)
---------- -------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt(1).............................. $ 28,000 $153,877 $ 25,827
Stockholders' equity:
Preferred Stock, $.01 par value, 10,000,000
shares authorized; no shares outstanding
actual, pro forma and pro forma as
adjusted.................................. -- -- --
Common Stock, $.01 par value, 60,000,000
shares authorized; 19,550,013 shares
issued and outstanding actual; 19,550,013
shares issued and outstanding pro forma;
and 32,050,013 shares issued and
outstanding pro forma as
adjusted(2)............................... 195 195 320
Additional paid-in capital................... 54,180 54,180 182,105
Deferred compensation........................ (16,424) (16,424) (16,424)
--------- -------- ---------
Total stockholders' equity..................... 37,951 37,951 166,001
--------- -------- ---------
Total capitalization................. $ 65,951 $191,828 $ 191,828
========= ======== =========
</TABLE>
- ---------------
(1) See Note 4 of Notes to Consolidated Financial Statements.
(2) Common Stock pro forma as adjusted excludes (i) 3,631,350 shares of Common
Stock issuable upon exercise of options outstanding at September 30, 1996,
with an exercise price of $2.08 per share, and (ii) 85,000 shares issuable
upon exercise of options that have been granted under the Company's 1996
Incentive Plan with an exercise price equal to the Price to Public set forth
on the cover page of this Prospectus. A total of 850,000 shares are reserved
for future issuance under the Company's 1996 Incentive Plan. See
"Management -- Employee Benefit Plans -- 1996 Incentive Plan" and Note 9 of
Notes to Consolidated Financial Statements.
16
<PAGE> 17
SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's consolidated financial statements
and related notes included elsewhere in this Prospectus. The consolidated
statement of operations data, consolidated statement of cash flows data and
other consolidated financial data for the period from inception (March 31, 1995)
through December 31, 1995, and the consolidated balance sheet data and
consolidated operating data at December 31, 1995, are derived from, and are
qualified by reference to, the consolidated financial statements included
elsewhere in this Prospectus that have been audited by KPMG Peat Marwick LLP,
independent accountants. The unaudited consolidated financial data as of
September 30, 1995 and September 30, 1996, and for the six months ended
September 30, 1995 and for the nine months ended September 30, 1996 have been
prepared on a basis consistent with the audited consolidated financial
statements and, in the opinion of management, include all adjustments
(consisting only of normal recurring adjustments) necessary to present fairly
the financial condition and results of operations for the periods presented. The
pro forma consolidated financial data is derived from, and is qualified by
reference to, the Company's pro forma condensed financial statements and related
notes included elsewhere in this Prospectus. The results for the nine months
ended September 30, 1996, are not necessarily indicative of the results that may
be expected for the year ending December 31, 1996.
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
PERIOD ENDED SEPTEMBER 30, NINE MONTHS ENDED
DECEMBER 31, 1995 1995 SEPTEMBER 30, 1996
----------------------------------- ------------- -----------------------------------
PRO FORMA PRO FORMA
PRO AS ADJUSTED PRO AS ADJUSTED
HISTORICAL FORMA(1) (1)(2) HISTORICAL HISTORICAL FORMA(1) (1)(2)
---------- -------- ----------- ------------- ---------- -------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF
OPERATIONS DATA:
Revenues:
Operating revenues........... $ 743 $49,349 $49,349 $ 12 $ 10,237 $42,414 $ 42,414
Other revenues............... 242 242 242 161 140 140 140
-------- ------- ------- ------- -------- ------- ---------
Total revenues........... 985 49,591 49,591 173 10,377 42,554 42,554
-------- ------- ------- ------- -------- ------- ---------
Expenses:
Oil and gas production....... 304 17,435 17,435 37 4,339 13,820 13,820
General and administrative... 1,546 4,625 4,625 668 1,452 3,469 3,469
Amortization of stock option
awards..................... 576 576 576 -- 576 576 576
Exploration and
abandonment................ 490 490 490 -- 110 110 110
Depletion, depreciation and
amortization............... 299 16,832 16,832 57 2,269 12,001 12,001
Interest..................... 97 10,888 2,145 -- 1,179 7,902 1,595
Other........................ (796) (796) (796) (669) (336) (336) (336)
-------- ------- ------- ------- -------- ------- ---------
Total expenses........... 2,516 50,050 41,307 93 9,589 37,542 31,235
-------- ------- ------- ------- -------- ------- ---------
Net income (loss).............. (1,531) (459) 5,385 80 (2,210) 260 7,358
Net income (loss) per share.... (.11) (.03) .18 .01 (.12) .01 .21
Weighted average shares
outstanding.................. 14,066 13,974 29,609 14,860 18,835 21,032 34,437
CONSOLIDATED STATEMENT OF CASH
FLOWS DATA:
Net cash provided by (used in):
Operating activities......... $ (1,764) $ -- $ -- $ (513) $ 5,653 $ -- $ --
Investing activities......... (47,563) -- -- (6,439) (12,763) -- --
Financing activities......... 55,540 -- -- 20,540 11,700 -- --
OTHER CONSOLIDATED FINANCIAL
DATA:
Capital expenditures........... $ 43,811 $ -- $ -- $ 2,387 $ 17,763 $ -- $ --
EBITDAX(3)..................... (69) 28,327 28,327 137 4,922 25,601 25,601
</TABLE>
17
<PAGE> 18
<TABLE>
<CAPTION>
PERIOD ENDED DECEMBER 31, NINE MONTHS ENDED
1995 SEPTEMBER 30, 1996
--------------------------- ---------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1)
---------- ------------ ---------- ------------
(IN THOUSANDS, EXCEPT OPERATING DATA)
<S> <C> <C> <C> <C>
CONSOLIDATED OPERATING DATA:
Production:
Oil (MBbls).............................................. 30 2,004 388 1,311
Gas (MMcf)............................................... 245 17,952 2,725 12,235
Total (MBOE)............................................. 71 4,996 842 3,350
Average Sales Prices Per Unit(4):
Oil (per Bbl)............................................ $ 16.80 $ 14.23 $ 17.25 $ 17.30
Gas (per Mcf)............................................ .97 1.16 1.30 1.61
BOE...................................................... 10.46 9.88 12.16 12.66
Expenses per BOE:
Production costs, including production taxes............. $ 4.28 $ 3.49 $ 5.15(5) $ 4.13(5)
General and administrative............................... 21.77 .93 1.72 1.04
Depletion, depreciation and amortization................. 4.21 3.37 2.69 3.58
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
-------------------------------------------------
PRO FORMA
DECEMBER 31, 1995 HISTORICAL PRO FORMA(1) AS ADJUSTED(1)(2)
----------------- ---------- ------------ -----------------
<S> <C> <C> <C> <C>
CONSOLIDATED BALANCE SHEET DATA:
Cash and cash equivalents.................... $ 6,213 $ 10,803 $ 10,803 $ 10,803
Working capital.............................. 11,905 8,760 8,453 8,453
Oil and gas assets, net...................... 42,869 60,168 187,202 187,202
Total assets................................. 57,487 74,824 202,308 202,308
Total debt................................... 20,000 28,000 153,877 25,827
Stockholders' equity......................... 34,585 37,951 37,951 166,001
</TABLE>
- ---------------
(1) Assumes the 1995 Acquisition, the 1996 Acquisition and the Conversion had
taken place on January 1, 1995 for purposes of the Consolidated Statement of
Operations Data, Consolidated Statement of Cash Flows Data, Other
Consolidated Financial Data and Consolidated Operating Data and assumes the
1996 Acquisition had taken place on September 30, 1996 for purposes of the
Consolidated Balance Sheet Data.
(2) Assumes this offering and the application of the proceeds therefrom had
taken place on January 1, 1995 for purposes of the Consolidated Statement of
Operations Data, Consolidated Statement of Cash Flows Data, Other
Consolidated Financial Data and Consolidated Operating Data and on September
30, 1996 for purposes of the Consolidated Balance Sheet Data.
(3) EBITDAX is presented because of its wide acceptance as a financial indicator
of a company's ability to service or incur debt. EBITDAX (as used herein) is
calculated by adding interest, income taxes, depletion, depreciation and
amortization, amortization of stock option awards, and exploration and
abandonment costs to net income (loss). Interest includes interest expense
accrued and amortization of deferred financing costs. EBITDAX should not be
considered as an alternative to earnings (loss) or operating earnings
(loss), as defined by generally accepted accounting principles, as an
indicator of the Company's financial performance, as an alternative to cash
flow as a measure of liquidity or as being comparable to other similarly
titled measures of other companies.
(4) Reflects results of hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters."
(5) Includes approximately $.77 per BOE of production costs attributable to
necessary rework operations on the 1995 Acquisition properties.
18
<PAGE> 19
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Titan is an independent energy company engaged in the exploration,
development and acquisition of oil and gas properties. The Company's strategy is
to grow reserves, production and net income per share through (i) the
acquisition of producing properties that provide significant development and
exploratory drilling potential, (ii) the exploitation and development of its
reserve base, (iii) the exploration for oil and gas reserves and (iv) the
implementation of a low operating and overhead structure. The Company has grown
rapidly through the acquisition and exploitation of oil and gas properties,
consummating the 1995 Acquisition for a purchase price of approximately $40.6
million and the 1996 Acquisition for approximately $135.5 million.
The Company's growth resulting from acquisitions has impacted its reported
financial results in a number of ways. Acquired properties frequently have not
received focused attention prior to sale. After acquisition, certain of these
properties require maintenance, workovers, recompletions and other remedial
activity not constituting capital expenditures, which initially increase lease
operating expenses. The Company anticipates spending at least $1.0 million in
nonrecurring remedial expenses with respect to the properties obtained in the
1996 Acquisition. The Company may dispose of certain of the properties if it
determines they are outside the Company's strategic focus. The increased
production and revenue resulting from the rapid growth of the Company has
required it to recruit and develop operating, accounting and administrative
personnel compatible with its increased size. As a result of the 1996
Acquisition, the Company has hired eight new employees and intends to hire 15 to
20 additional employees. At December 15, 1996, the Company had 28 employees. As
a result, the Company anticipates a corresponding increase in its general and
administrative expense. The Company believes that with its current inventory of
drilling locations and the anticipated additional staff it will be well
positioned to follow a more balanced program of exploration and exploitation
activities to complement its acquisition efforts.
Titan uses the successful efforts method of accounting for its oil and gas
producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that result in proved reserves,
and to drill and equip development wells are capitalized. Costs to drill
exploratory wells that do not result in proved reserves, geological and
geophysical costs, and costs of carrying and retaining properties that do not
contain proved reserves are expensed. Costs of significant nonproducing
properties, wells in the process of being drilled and significant development
projects are excluded from depletion until such time as the related project is
developed and proved reserves are established or impairment is determined.
The Company's predecessor was classified as a partnership for federal
income tax purposes. Therefore, no income taxes were paid by the Company prior
to the Conversion. Future tax amounts, if any, will be dependent upon several
factors, including, but not limited to, the Company's results of operations.
RESULTS OF OPERATIONS
The financial statements of the Company, which began operations on March
31, 1995, include the results of the nine months ended December 31, 1995 and the
nine months ended September 30, 1996. As a result of the Company's limited
operating history and rapid growth, its financial statements are not readily
comparable and may not be indicative of future results. Furthermore, because the
period from inception of the Company to September 30, 1995 was only six months
in length, a comparison of results from that period to the nine months ended
September 30, 1996 would not be meaningful.
Nine Months Ended September 30, 1996
For the nine months ended September 30, 1996, the Company's revenues from
the sale of oil and gas (excluding the effects of hedging activities) were $7.6
million and $4.1 million, respectively. During the period, the Company produced
388 MBbls of oil and 2,725 MMcf of gas, with total oil and gas production of 842
MBOE. The revenues and production are primarily attributable to the 1995
Acquisition.
19
<PAGE> 20
As a result of hedging activities in the nine months ended September 30,
1996, oil revenues were reduced $899,000 ($2.32 per Bbl) to $17.25 per Bbl and
gas revenues were reduced $553,000 ($.20 per Mcf) to $1.30 per Mcf for a total
reduction of $1,452,000.
Oil and gas production costs, including production taxes, were $4.3 million
($5.15 per BOE) for the nine months ended September 30, 1996. These costs
included $645,000 ($.77 per BOE) that were attributable to rework expenses
incurred with respect to the 1995 Acquisition properties.
Exploration and abandonment costs were $110,000 for the nine months ended
September 30, 1996.
General and administrative expenses were $1,452,000 ($1.72 per BOE) for the
nine months ended September 30, 1996.
For the nine months ended September 30, 1996, depletion, depreciation and
amortization expense was $2.3 million ($2.69 per BOE), which primarily
represents the depletion, depreciation and amortization relating to the
production from the 1995 Acquisition.
Interest expense was $1,179,000 for the nine months ended September 30,
1996. The interest expense was attributable to bank financing incurred to fund
the 1995 Acquisition.
Nine Months Ended December 31, 1995
For the nine months ended December 31, 1995, the Company's revenues from
the sale of oil and gas were $504,000 and $239,000, respectively. During the
period, the Company produced 30 MBbls of oil and 245 MMcf of gas, for a total
production of 71 MBOE. The revenues and production are primarily attributable to
the 1995 Acquisition, which was consummated December 11, 1995.
Oil and gas production costs, including production taxes, were $304,000
($4.28 per BOE) for the nine months ended December 31, 1995.
Exploration and abandonment costs were $490,000 for the nine months ended
December 31, 1995.
General and administrative expenses were $1.5 million ($21.77 per BOE) for
the nine months ended December 31, 1995.
For the nine months ended December 31, 1995, depletion, depreciation and
amortization expense was $299,000 ($4.21 per BOE).
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources
Funding for the Company's business activities has been provided by its
initial capitalization, bank financing, cash flow from operations and private
equity sales. The 1995 Acquisition was funded with cash from the Company's
initial capitalization, additional private equity sales and bank financing. The
1996 Acquisition was funded with bank financing to be partially repaid with the
proceeds of this offering and the issuance of equity capital in a private
placement in September 1996.
While the Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties, the Company has no present agreement,
commitment or understanding with respect to any such acquisition, other than the
acquisition of oil and gas properties and interests in its normal course of
business. Any future acquisitions may require additional financing and will be
dependent upon financing arrangements available at the time.
The Company believes that in the short-term -- that is, through
1997 -- availability under the Credit Agreement and cash flow from operations
will be sufficient for anticipated operating and capital expenditure
requirements in 1997. Immediately following the completion of this offering, the
Company will have approximately $139.2 million available under the Credit
Agreement. However, in the long term -- beyond 1997 -- if the Company's cash
flow from operations and availability under the Credit Agreement are not
20
<PAGE> 21
sufficient to satisfy cash requirements, there can be no assurance that
additional debt or equity financing will be available to meet its requirements.
Although certain of the Company's costs and expenses may be affected by
inflation, inflationary costs have not had a significant effect on the Company's
results of operations.
Net Cash Provided by (Used in) Operating Activities. For the nine months
ended December 31, 1995, net cash used in operations was $1.8 million primarily
due to initiation of the Company's operations. For the nine months ended
September 30, 1996, net cash provided by operating activities increased to $5.7
million due primarily to the 1995 Acquisition and the cash flow therefrom.
Net Cash Used in Investing Activities. For the nine months ended December
31, 1995, net cash used in investing activities was $47.6 million of which $39.9
million was primarily attributable to the 1995 Acquisition. An additional $3.8
million was expended in other acquisition, exploration and development
activities, along with the purchase of a $5.0 million short-term investment. Net
cash used in investing activities for the nine months ended September 30, 1996
was $12.8 million, which was the result of the redemption of $5.0 million in
short-term investments, additions to oil and gas properties of $17.6 million and
additions of $200,000 to other property and equipment.
Net Cash Provided by Financing Activities. Net cash provided by financing
activities was $55.5 million for the nine months ended December 31, 1995. This
included $20.0 million of proceeds from the issuance of long-term debt and $35.5
million of capital contributions. For the nine months ended September 30, 1996,
net cash provided by financing activities was $11.7 million, which included $8.0
million from the issuance of long-term debt and $3.7 million from capital
contributions.
Credit Agreement. The Credit Agreement establishes a four year revolving
credit facility, up to the maximum amount of $250 million, subject to a
borrowing base to be determined annually by the lenders based on certain proved
oil and gas reserves and other assets of the Company. Initially, the borrowing
base is established at $165 million. To the extent that the borrowing base is
less than the aggregate principal amount of all outstanding loans and letters of
credit under the Credit Agreement, such deficiency must be cured by the Company
ratably within 180 days, by either prepaying a portion of the outstanding
amounts under the Credit Agreement or pledging additional collateral to the
lenders. A portion of the credit facility is available for the issuance of up to
$15.0 million of letters of credit, of which $300,000 was outstanding at
September 30, 1996. The Company borrowed $154.5 million of the $165 million
available under the Credit Agreement at the closing of the 1996 Acquisition. The
Company intends to use the net proceeds to repay indebtedness under the Credit
Agreement. See "Use of Proceeds."
All outstanding amounts under the Credit Agreement are due and payable in
full on January 1, 2001.
At the Company's option, borrowings under the Credit Agreement bear
interest at either (i) the "Base Rate" (i.e., the higher of the applicable prime
commercial lending rate, or the federal funds rate plus .5% per annum) or (ii)
the Eurodollar rate plus a margin ranging from 1% to 1.50% per annum that
depends on the level of the Company's aggregate outstanding borrowings under the
Credit Agreement. In addition, the Company is committed to pay quarterly in
arrears a fee ranging from .30% to .375% of the unused portion of the borrowing
base.
The loan documents governing the Credit Agreement contain certain covenants
and restrictions relating to the Company's operations that are customary in the
oil and gas industry. In addition, the line of credit is secured by a first lien
on properties that represented at least 80% of the value of the Company's proved
oil and gas properties (based on PV-10 as of September 30, 1996). See Note 12 of
Notes to Consolidated Financial Statements.
Capital Expenditures
The Company requires capital primarily for the exploration, development and
acquisition of oil and gas properties, the repayment of indebtedness and general
working capital needs.
21
<PAGE> 22
The following table sets forth costs incurred by the Company in its
exploration, development and acquisition activities during the periods
indicated.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
NINE MONTHS ENDED SEPTEMBER 30,
DECEMBER 31, 1995 1996
----------------- ----------------
(IN THOUSANDS)
<S> <C> <C>
Development costs.................................. $ 1,580 $ 7,358
Exploration costs.................................. 448 107
Acquisition costs:
Unproved properties.............................. 1,040 300
Proved properties................................ 40,873 11,837
------- --------
Total.................................... $43,941 $ 19,602
======= ========
</TABLE>
Through 1998, subject to market conditions and drilling and operating
results, the Company expects to spend (i) approximately $22 million to drill 14
proved locations on Company-operated properties, (ii) approximately $21 million
to drill 129 unproven locations, 39 of which are on Company-operated properties
and 90 of which are on Company-owned, but nonoperated, properties, and (iii)
approximately $30 million to drill approximately 40 exploratory locations on
Company-owned properties. See "Risk Factors -- Volatility of Oil and Gas Prices"
and "Risk Factors -- Drilling and Operating Risks."
OTHER MATTERS
Stock Options and Compensation Expense
In connection with the Conversion, the Company issued options to purchase
3,631,350 shares of Common Stock to certain of its officers and employees in
substitution for options issued by the Partnership. Of the options issued by the
Partnership, approximately 93% were issued on March 31, 1995, the date of
inception, and approximately 7% were issued as of September 1, 1996. The options
issued by the Company have an exercise price of $2.08 per share. Options to
purchase 803,576 shares of Common Stock are currently vested and an additional
1,190,841, 1,209,966 and 426,967 shares will vest on March 31 of each of 1997,
1998 and 1999, respectively. Based in part on selling prices of interests in the
Partnership in December 1995 and September 1996, the Company expects to record a
noncash compensation expense of approximately $421,000 per month for a period of
39 months beginning in the fourth quarter of 1996 to reflect the estimated value
of the revised option plan on September 30, 1996.
Hedging Activities
The Company uses swap agreements in an attempt to reduce the risk of
fluctuating oil and gas prices and interest rates. In November and December
1995, the Company entered into four master agreements for energy price and other
swap transactions with each of Enron Capital & Trade Resources Corp. ("ECTRC")
(an affiliate of Joint Energy Development Investments Limited Partnership
("JEDI"), an owner of in excess of 5% of the outstanding Common Stock), First
Union National Bank of North Carolina (a lender to the Company under the Credit
Agreement and an affiliate of First Union Corporation, an owner of in excess of
5% of the outstanding Common Stock), Chemical Bank and Texas Commerce Bank
National Association (a lender to the Company and an affiliate of Chemical
Bank). The Company has entered into energy price swap arrangements from time to
time under these master agreements. Settlement of gains or losses on these
energy swap transactions is generally based on the difference between the
contract price and a formula using New York Mercantile Exchange ("NYMEX")
related prices and is reported as a component of oil and gas revenues as the
associated production occurs. The Company has entered into hedging transactions
with respect to a substantial portion of its estimated production through
December 1996, excluding the production attributable to the 1996 Acquisition.
The Company's reserve report at September 30, 1996 reflects hedging activities
contracted through December 31, 1996, resulting in a reduction of PV-10 of
$420,000. The Company continues to evaluate whether to enter into additional
hedging transactions for 1997 and future
22
<PAGE> 23
years. The following is a summary of the Company's hedging transactions in
effect as of September 30, 1996. See "Risk Factors -- Risk of Hedging
Activities."
Natural Gas. As of September 30, 1996, the Company had hedging transactions
related to 220,000 MMBtu of natural gas per month through December 1996 that
provide for settlements based on prices of natural gas determined by reference
to closing prices of natural gas futures contracts traded on NYMEX. These hedges
include a price swap using a "participating floor" with a price of $1.70 per
MMBtu. In the event that the NYMEX reference price for any settlement period is
less than the floor price, the Company will be paid 100% of the difference. In
the event that the NYMEX reference price for any settlement period is greater
than the floor price, the Company must pay 47% of the difference.
Since most of the Company's natural gas is sold under spot contracts with
reference to El Paso Permian Basin sales hub prices, the Company entered into
"basis differential swaps" related to 220,000 MMBtu of natural gas per month for
the period May 1996 through December 1996. In the event that the NYMEX reference
price for a reference period exceeds the average price per MMBtu for natural gas
delivered to El Paso Permian Basin hub by more than $.325 per MMBtu the Company
receives a payment based on the excess above the $.325 basis. In the event that
the NYMEX reference price for a reference period exceeds the El Paso Permian hub
price by less than $.325 per MMBtu (or in the event that the El Paso Permian
Basin hub price exceeds the NYMEX reference price), the Company must pay the
deficiency below the $.325 basis.
As a result of its hedging activities, the Company's natural gas revenues
were reduced by $553,000 for the nine months ended September 30, 1996.
Crude Oil. As of September 30, 1996, the Company had one hedging
transaction related to 25,000 Bbls of West Texas Intermediate Light Sweet crude
oil a month through December 1996 that provides for settlements based on prices
of oil determined by reference to NYMEX future oil contracts. The swap price for
this transaction is $17.18 per Bbl. In the event that the NYMEX reference price
for any settlement period is less than the swap price, the Company receives the
difference. In the event that the NYMEX reference price for any settlement
period is greater than the swap price, the Company must pay the difference.
As a result of its hedging activities, the Company's crude oil revenues
were reduced by $899,000 during the nine months ended September 30, 1996.
Interest Rates. The Company also uses derivative financial instruments to
manage interest rate risks. Under an interest rate swap agreement, the Company
has an effective rate of 6.72% on $10 million of its revolving line of credit
through December 23, 1996.
Natural Gas Balancing
It is customary in the natural gas industry for various working interest
partners to produce more or less than their entitlement share of natural gas
from time to time. The Company's net overproduced position at September 30, 1996
was 549,844 Mcf, and 205,182 Mcf on a pro forma basis. Under terms of typical
natural gas balancing agreements, the underproduced party can take a certain
percentage, typically 25% to 50% of the overproduced party's entitled share of
gas sales in future months, to eliminate such imbalances. During the make-up
period, the overproduced party's cash flow will be adversely affected. The
Company recognizes revenue and imbalance obligations under the entitlements
method of accounting.
Environmental and Other Laws and Regulations
The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for and the development, production
and transportation of oil and gas, as well as environmental and safety matters.
Many of these laws and regulations have become more stringent in recent years,
often imposing greater liability on a larger number of potentially responsible
parties. Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation, and the
Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. The Company has no material
commitments for capital expenditures to comply with existing environmental
requirements.
23
<PAGE> 24
Nevertheless, changes in existing environmental laws or in interpretations
thereof could have a significant impact on the operating costs of the Company,
as well as the oil and gas industry in general. See "Risk Factors -- Compliance
with Environmental Regulations," "Business and Properties -- Environmental
Matters" and "Business and Properties -- Abandonment Costs."
Accounting Pronouncements
On October 23, 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation," which establishes a fair value method for accounting for
stock-based compensation plans either through recognition or disclosure. The
Company adopted this standard in 1996 and will disclose the pro forma net income
(loss) and earnings (loss) per share amounts assuming the fair value method was
adopted on March 31, 1995 (date of inception) in its financial statements as of
and for the year ended December 31, 1996. The adoption of this standard will not
impact the Company's consolidated results of operations or financial position.
24
<PAGE> 25
BUSINESS AND PROPERTIES
GENERAL
Titan is an independent energy company engaged in the exploration,
development and acquisition of oil and gas properties. Since its inception in
March 1995, the Company has experienced significant growth in reserves,
production and cash flow by acquiring and exploiting producing properties
primarily in the Permian Basin of west Texas and southeastern New Mexico.
In December 1995, the Company acquired a concentrated group of Permian
Basin producing oil and gas properties from a large independent company for
approximately $40.6 million (the "1995 Acquisition"). On October 31, 1996, the
Company acquired additional Permian Basin producing properties from a major
integrated company for approximately $135.5 million (the "1996 Acquisition"). As
of September 30, 1996, the Company had pro forma estimated net proved reserves
of approximately 17.8 MMBbls of oil and 280.8 Bcf of natural gas, or an
aggregate of 64.6 MMBOE with a PV-10 of $292.1 million. If, in calculating the
PV-10, the Company's oil and gas prices at October 31, 1996 were substituted for
the prices at September 30, 1996, the PV-10 would be $351.9 million. The prices
of the Company's oil decreased 4% and gas increased 33% from September 30, 1996
to October 31, 1996. Approximately 62% of these reserves were classified as
proved developed. The Company acquired, explored for and developed its reserves
for an average reserve replacement cost of approximately $2.73 per BOE through
September 30, 1996, assuming the 1996 Acquisition was consummated on September
30, 1996. Pro forma production for the nine months ended September 30, 1996 was
12,227 BOE per day, resulting in an annualized pro forma proved reserves to
production ratio of 14.5 to one.
The Company prefers to acquire properties over which it can exercise
operating control. The Company operated 456 gross wells (389 net wells) on a pro
forma basis at September 30, 1996, and these operated properties represented
approximately 71% of its pro forma proved developed producing PV-10 and 83% of
the Company's pro forma PV-10 attributable to proved reserves at September 30,
1996. The Company's emphasis on controlling the operation of its properties
enables the Company to manage expenses, capital allocation and other aspects of
development and exploration.
The Company's oil and gas properties are located in approximately 60 fields
in the Permian Basin. Approximately 70% of the Company's PV-10 of total proved
reserves is concentrated in 12 principal fields located in this region. The
region is characterized by complex geology with numerous known producing
horizons and provides significant opportunities to increase reserves, production
and ultimate recoveries through development, exploratory and horizontal
drilling, recompletions, secondary and tertiary recovery methods, and use of 3-D
seismic and other advanced technologies.
The Company believes that its personnel provide it with competitive
advantages for exploiting these opportunities in the Permian Basin and other
complex producing basins in North America. Members of the Company's management
team have an average of 25 years experience in the oil and gas industry and have
operating experience in all aspects of the industry, in particular deep well and
horizontal drilling. They have formulated and supervised acquisitions,
exploration projects, development drilling programs and production enhancement
plans, including workovers and enhanced recovery projects. In addition,
management has a significant equity investment in the Company. Giving effect to
this offering and assuming the exercise by management of all of their options to
acquire Common Stock, management will beneficially own an aggregate of 20% of
the Company's outstanding Common Stock.
25
<PAGE> 26
BUSINESS STRATEGY
The Company's strategy is to grow reserves, production and net income per
share through (i) the acquisition of producing properties that provide
significant development and exploratory drilling potential, (ii) the
exploitation and development of its reserve base, (iii) the exploration for oil
and gas reserves and (iv) the implementation of a low operating and overhead
cost structure.
o Acquisitions. The Company seeks to acquire oil and gas properties that
provide opportunities for the addition of reserves, production and value
through low risk exploitation and development, high-potential exploration
and control of operations. The Company believes that these criteria can be
met in the Permian Basin and in other North American basins that have had
high historical cumulative production levels that represent a relatively
small percentage of the recoverable in-place reserves. At September 30,
1996, the Company had acquired and developed 64.6 MMBOE of proved oil and
gas reserves at an average reserve replacement cost of $2.73 per BOE,
assuming the 1996 Acquisition was consummated on September 30, 1996, which
compares to an average reserve replacement cost of $4.85 per BOE (for 1993
through 1995) for the 184 independent oil and gas companies included in
the Arthur Andersen 1996 Oil and Gas Reserve Disclosures.
o Exploitation of Reserve Base. The Company engages in horizontal and
infill drilling activities, major workovers, recompletions, secondary and
tertiary recovery operations, and other production enhancement techniques
in order to increase reserves and production. Through 1998, subject to
market conditions and drilling and operating results, the Company expects
to spend approximately $22 million to drill 14 proved locations on
Company-operated properties and $21 million to drill 129 unproven
locations, 39 of which are on Company-operated properties and 90 of which
are on Company-owned, but nonoperated, properties.
o Exploration Activities. The Company seeks to apply management's extensive
geological and drilling expertise and 3-D seismic technology to identify
and develop exploration projects. As part of its exploration strategy, the
Company attempts to reduce the costs and risks of its exploration
activities by, in selected circumstances, applying 3-D seismic technology,
drilling wells with multiple pay objectives in known producing areas and
selling interests in its exploration prospects to industry partners. A
large portion of the Company's efforts have focused on deep well
opportunities in historically prolific fields. Through 1998, subject to
market conditions and drilling and operating results, the Company expects
to spend approximately $30 million to drill approximately 40 exploratory
locations on Company-owned properties.
o Low Cost Structure. The Company has implemented and plans to maintain a
low overhead and operating cost structure to enhance the profitability and
the exploitation potential of its properties. The Company provides
incentive stock awards to its senior management team in lieu of
comparatively higher salary levels in order to align management's
interests with stockholders, maintain relatively low general and
administrative expense and increase the amount of cash flow available for
reinvestment by the Company. The Company also seeks to be an efficient
operator and achieve reductions in labor and other field-level costs from
those incurred by previous operators of its properties. By operating a
significant portion of its daily production, the Company believes it is
well positioned to control the expenses and timing of development and
exploitation of such properties and to better manage such cost reduction
efforts.
COMPANY HISTORY
The history of the Company's operations can be divided into three segments:
Initial Operations. The Company was formed in March 1995 by Jack Hightower,
members of his management team and Natural Gas Partners, L.P. and Natural Gas
Partners II, L.P. (collectively, "NGP"), with an initial equity capitalization
of approximately $20.5 million. From its inception, the Company engaged in the
exploration, development and acquisition of oil and gas properties, initially
focusing on those in Ward, Pecos, Winkler and Hardeman counties in Texas. From
inception until December 31, 1995, excluding the 1995 Acquisition, the Company
spent approximately $2.7 million to acquire and develop properties in these
counties. From January 1, 1996 until September 30, 1996, the Company spent an
additional $5.9 million to
26
<PAGE> 27
further develop these properties. This activity has resulted in a PV-10
attributable to these initial properties of approximately $53.6 million at
September 30, 1996.
1995 Acquisition. On December 11, 1995, the Company acquired a concentrated
group of producing oil and gas properties in the Permian Basin from a large,
independent exploration and production company for a purchase price of
approximately $40.6 million. The 1995 Acquisition was financed principally
through cash from the initial capitalization of the Company and borrowings under
the Credit Agreement, which at that time had a $35 million borrowing base. From
the consummation of the 1995 Acquisition through September 30, 1996, the Company
spent a total of approximately $4.3 million to acquire additional working
interests and develop and enhance these properties and has received net cash
flow of approximately $7.2 million. As of September 30, 1996, these properties,
net to the Company, had an estimated 22.9 MMBOE of reserves and a PV-10 of $90.9
million.
1996 Acquisition. On October 31, 1996, the Company acquired leasehold
interests in certain oil and gas producing fields situated in the Permian Basin
from a major integrated oil and gas company for a purchase price of
approximately $135.5 million. The 1996 Acquisition was financed with
indebtedness under the Credit Agreement and proceeds from the issuance of equity
in a private placement in September 1996. The net proceeds from this offering
will be used to reduce indebtedness under the Credit Agreement. See "Use of
Proceeds." As of September 30, 1996, these properties had an estimated 28.2
MMBOE of reserves and a PV-10 of $147.5 million.
ACQUISITIONS
The Company regularly pursues and evaluates acquisition opportunities
(including opportunities to acquire oil and gas properties or related assets or
entities owning oil and gas properties or related assets and opportunities to
engage in mergers, consolidations or other business combinations with entities
owning oil and gas properties or related assets) and at any given time may be in
various stages of evaluating such opportunities. Such stages may take the form
of internal financial and oil and gas property analysis, preliminary due
diligence, the submission of an indication of interest, preliminary
negotiations, negotiation of a letter of intent or negotiation of a definitive
agreement. While the Company is currently evaluating a number of potential
acquisition opportunities (some of which would be material in size to the
Company), it has not signed a letter of intent with respect to any material
acquisition and currently has no assurance of completing any particular material
acquisition or of entering into negotiations with respect to any particular
material acquisition.
PRINCIPAL OIL AND GAS PROPERTIES
Approximately 46% of the Company's PV-10 of total proved reserves is
concentrated in six principal fields, the Puckett, Dollarhide East, Foster, Mi
Vida, Barstow and North Robertson fields. In addition, approximately 24% of the
Company's PV-10 of total proved reserves is concentrated in six other fields,
the Gomez, University Waddell, Sand Hills, Evetts, Headlee and Petco. A
description of each of these 12 fields is set forth below. Cumulative field
production data is as of June 30, 1996 and may not include field production data
prior to 1966.
Puckett Field. The Company owns 1,280 gross leasehold acres (1,120 net
leasehold acres) in the Puckett Field in Pecos County, Texas. The Company's
working interests in this acreage range from 74% to 100%, and the Company
operates 100% of its PV-10 in this field. The primary producing formations in
the field are the Ellenburger and Devonian, which range from depths of 11,500
feet to 15,000 feet. Cumulative field production from these formations has been
3.4 Tcf and 464 Bcf, respectively. The Company's acreage has produced 207 Bcf
and 67 Bcf, respectively, from three wellbores in these formations. The Company
has identified two proved Ellenburger horizontal drilling replacement locations,
one of which has been drilled and is currently being completed. The Company has
also identified one workover opportunity in the Devonian formation, as well as a
recompletion opportunity in the Fusselman formation.
Dollarhide East Field. The Company owns approximately 2,500 gross leasehold
acres (approximately 2,200 net leasehold acres) in the Dollarhide East Field in
Andrews County, Texas. The Company's working
27
<PAGE> 28
interests in this field range from 69% to 100%, and the Company operates 100% of
its PV-10 in this field. The primary producing formations in the field are the
Devonian, Silurian and Ellenburger, which range from depths of 11,000 feet to
12,700 feet. Cumulative field production from these formations has been 8.2
MMBbls, 1.3 MMBbls and 6.2 MMBbls, respectively. The Company will use existing
3-D seismic to plan expansion of an existing waterflood program and analyze the
potential for tertiary recovery operations. Although no proved reserves have
been attributed to tertiary operations on the Company's acreage, tertiary
recovery operations have been underway on an adjacent analogous field since
1986.
Foster Field. The Company owns 6,280 gross leasehold acres (3,820 net
leasehold acres) in the Foster Field in Ector County, Texas. The Company's
interests in this field include a 19% working interest in the Amoco-operated
South Foster unit, a 40% working interest in the Conoco-operated Gist unit and
an 80% working interest in the Company-operated North Foster unit. The primary
producing formation in the field is the Grayburg at a maximum depth of 4,800
feet, with cumulative production in the field of 291 MMBbls.
Waterflood programs are underway on all three interests. The Company is
studying the economic feasibility of a tertiary recovery project in this field.
In the North Foster unit, the Company has identified four unproven drilling
locations to be defined further with 3-D seismic and five refracture stimulation
opportunities. Contingent on the success of the drilling of the four unproven
locations, the Company could drill 12 additional unproven locations.
Mi Vida Field. The Company owns approximately 5,900 gross leasehold acres
(approximately 4,300 net leasehold acres) in the Mi Vida Field in Ward County,
Texas. The Company's working interests in this field range from 54% to 98%, and
the Company operates 100% of its PV-10 in this field. The primary producing
formations in the field are the Fusselman, Ellenburger and Penn, which range
from depths of 14,500 feet to 19,100 feet. Cumulative field production from
these formations has been 740 Bcf, 181 Bcf and 6.0 Bcf, respectively.
The Company's plans include the installation of gas-lift equipment on three
wells and acquiring 3-D seismic on the entire field to identify infill, step-out
and sidetrack drilling opportunities. Subject to verification by the 3-D
seismic, the Company has identified four unproven sidetrack opportunities.
Barstow Field. The Company owns 2,315 gross leasehold acres (1,604 net
leasehold acres) in the Barstow Field in Ward County, Texas. The Company's
working interests in this field range from approximately 45% to 80%, and the
Company operates 100% of its PV-10 in this field. The primary producing
formations in the field are the Fusselman and Ellenburger, which range from
depths of 18,000 feet to 19,700 feet. Cumulative field production from these
formations has been 221 Bcf and 17 Bcf, respectively.
The Company completed a well in the Fusselman formation early in 1996. As
anticipated by the Company, bottom-hole pressure data indicated that a portion
of the field had repressurized since having been shut-in in 1981. Subsequently,
the Company conducted a 3-D seismic survey that identified two proved
undeveloped drilling locations. The first of those was spudded August 31, 1996.
The second well is planned for drilling in 1997. In addition, based on analysis
of the 3-D seismic, the Company has identified an exploratory drilling location
targeting the Ellenburger and Fusselman formations.
North Robertson Field. The Company owns approximately 5,400 gross leasehold
acres (approximately 860 net leasehold acres) in the North Robertson Field in
Gaines County, Texas. The Company's working interest in the North Robertson unit
is 16%. The primary producing formation in the unit is the Clearfork at a
maximum depth of 7,200 feet with cumulative field production of 111 MMBbls and
62 Bcf of gas.
The Company anticipates participating in 60 unproven 10-acre infill
development wells in the North Robertson Clearfork unit. Contingent on the
success of this infill program, the Company believes an additional 30 locations
could be drilled.
Gomez Field. The Company owns 2,490 gross leasehold acres (830 net
leasehold acres) in the Gomez Field in Pecos County, Texas. The Company's
working interests in this field range from 23% to 100%, and the Company operates
approximately 80% of its PV-10 in this field. The primary producing formations
in the field are the Ellenburger and Wolfcamp, which range from depths of 11,100
feet to 22,600 feet. Cumulative field production from these formations has been
4.7 Tcf and 54 Bcf with 3.8 MMBC, respectively.
28
<PAGE> 29
University Waddell Field. The Company currently owns approximately 1,200
gross leasehold acres (approximately 1,100 net leasehold acres) in the
University Waddell Field in Crane County, Texas. The Company's working interest
in the University Waddell Devonian Unit is 89.51% and the Company operates 100%
of its PV-10 in this field. The primary producing formation in the field is the
Devonian to a maximum depth of 9,000 feet. Cumulative production from the unit
has been approximately 19.3 Bcf of gas and 9.4 MMBbls of oil. Total field
production from the Devonian formation is approximately 67 MMBbls and 115 Bcf.
The Company believes that by altering the injection pattern and rates of the
existing waterflood program it can improve recoveries beyond the estimated
remaining proved reserves on the Company's properties in the field. The Company
is studying the feasibility of secondary recovery enhancements and tertiary
recovery opportunities.
Sand Hills Field. The Company currently owns approximately 9,100 gross
leasehold acres (approximately 9,100 net leasehold acres) in the Sand Hills
Field in Crane County, Texas. The Company has a 100% working interest in this
acreage, and the Company operates 100% of its PV-10 in this field. The primary
producing formations in the field are the Judkins, McKnight, San Angelo and
Tubb, which range from depths of 2,800 feet to 4,200 feet. Cumulative field gas
production from these formations has been 1.1 Tcf, 561 Bcf, 40 Bcf and 228 Bcf,
respectively. In addition, cumulative oil production from the Judkins, McKnight
and Tubb formations in the field has been 12 MMBbls, 125 MMBbls and 96 MMBbls,
respectively.
Evetts Field. The Company owns 1,280 gross leasehold acres (724 net
leasehold acres) in the Evetts Field in Winkler County, Texas. The Company's
working interests in this field range from 3% to 91%, and the Company operates
approximately 84% of its PV-10 in this field. In addition, the Company has an
approximate 4.28% working interest in the balance of the field, which is
operated by another company. The primary producing formations in the field are
the Ellenburger, Silurian and Penn, which range from depths of 15,500 feet to
20,800 feet. Cumulative field production from these formations has been 82 Bcf,
653 Bcf and 35 Bcf, respectively.
In this field, the Company has identified one proved undeveloped location
in the Silurian formation. The Company will conduct a 3-D seismic survey to
optimize this location. The Company has identified one unproven drilling
location targeting the Atoka formation and four unproven drilling locations
targeting the Bone Spring formation. The Company has identified these locations
using data gathered from wells directly offsetting the proposed locations.
Headlee Field. The Company currently owns approximately 16,000 gross
leasehold acres (approximately 460 net leasehold acres) in the Headlee Field in
Ector County, Texas. The Company has a 2.91% working interest in the Headlee
Devonian Unit. Since 1989, a gas blowdown in the unit has produced 388 Bcf.
Petco Field. The Company currently owns 2,560 gross leasehold acres (1,632
net leasehold acres) in the Petco Field in Pecos County, Texas. The Company's
working interests in this acreage range from 60% to 75%, and the Company
operates 100% of its PV-10 in this field. The primary producing formations in
the field are the Devonian and the Ellenburger, which range from depths of
11,000 feet to 13,700 feet. Cumulative field natural gas production from these
formations has been 13 Bcf and 9.5 Bcf, respectively. In the second quarter of
1996, the Company conducted a 3-D seismic survey covering 15 square miles of the
Petco field. Based on analysis of this seismic and production data and extensive
studies of subsurface mapping and dipmeters, the Company has identified a proved
undeveloped location on its acreage with a planned dual completion in the
Devonian and Ellenburger formations. The Company has also identified an
exploration prospect and plans to extend the 3-D seismic survey to further
delineate this and other potential prospects in the field.
OIL AND NATURAL GAS RESERVES
The following table summarizes the estimates of the Company's historical
net proved reserves as of December 31, 1995 and September 30, 1996 and pro forma
reserves as of December 31, 1995 and September 30, 1996, and the present values
attributable to these reserves at such dates. The reserve and present value data
as of December 31, 1995 were prepared by the Company. The reserve and present
value data of the Company and of the 1996 Acquisition as of September 30, 1996
were prepared by Williamson. The pro forma December 31, 1995 and September 30,
1996 reserve data and present values give effect to the 1996
29
<PAGE> 30
Acquisition as if it had occurred on the day indicated. Summaries of the
September 30, 1996 reserve reports and the letters of Williamson with respect
thereto are included as Appendix A to this Prospectus.
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1995 AS OF SEPTEMBER 30, 1996
------------------------ ------------------------
HISTORICAL PRO FORMA HISTORICAL PRO FORMA
---------- --------- ---------- ---------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Estimated proved reserves:
Oil (MBbls)................................... 6,146 16,460 6,563 17,843
Gas (MMcf).................................... 134,995 242,039 179,565 280,824
MBOE (6 Mcf per Bbl).......................... 28,645 56,800 36,491 64,647
Proved developed reserves as a percentage of
proved reserves............................... 47% 68% 42% 62%
PV-10(1)........................................ $ 89,753 $ 198,341 $ 144,532 $ 292,080
Standardized Measure of Discounted Future Net
Cash Flows(2)................................. $ 66,352 $ 176,421 $ 104,678 $ 229,199
</TABLE>
- ---------------
(1) The present value of future net revenue attributable to the Company's
reserves was prepared using prices in effect at the end of the respective
periods presented, discounted at 10% per annum on a pre-tax basis. Such
amounts reflect the effects of the Company's hedging activities. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
(2) The Standardized Measure of Discounted Future Net Cash Flows prepared by the
Company represents the present value of future net revenues after income
taxes discounted at 10%. Such amounts reflect the effects of the Company's
hedging activities. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Matters."
In accordance with applicable requirements of the Commission, estimates of
the Company's proved reserves and future net revenues are made using sales
prices estimated to be in effect as of the date of such reserve estimates and
are held constant throughout the life of the properties (except to the extent a
contract specifically provides for escalation). The sales prices used in the pro
forma estimates presented above were based on oil and gas prices that the
Company would have received at the end of each reported period without
escalation. The average prices for the Company's pro forma reserves as of
September 30, 1996 were $23.37 per Bbl of oil and $1.39 per Mcf of natural gas,
compared to average prices for the Company's reserves as of December 31, 1995 of
$17.66 per Bbl of oil and $1.38 per Mcf of natural gas.
Estimated quantities of proved reserves and future net revenues therefrom
are affected by natural gas prices, which have fluctuated widely in recent
years. There are numerous uncertainties inherent in estimating oil and gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Prospectus represents only
estimates. Reservoir 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, including those used by the Company,
may vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and gas prices, operating costs and other factors, which
revisions may be material. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered and are highly
dependent upon the accuracy of the assumptions upon which they are based. The
Company's estimated proved reserves have not been filed with or included in
reports to any federal agency. See "Risk Factors -- Uncertainty of Reserve
Information and Future Net Revenue Estimates."
Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be substantial, in the
estimated reserves.
30
<PAGE> 31
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's productive wells as of
September 30, 1996:
<TABLE>
<CAPTION>
ACTUAL PRO FORMA(1)
------------- -------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Oil.................................................... 626 187 1,351 444
Gas.................................................... 32 13 272 74
--- --- ----- ---
Total Productive Wells....................... 658 200 1,623 518
=== === ===== ===
</TABLE>
- ---------------
(1) Gives effect to the 1996 Acquisition as if it had occurred on September 30,
1996.
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, on a pro forma basis, nine had multiple completions.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional interests
owned in gross acres expressed as whole numbers and fractions thereof. The
following table sets forth the approximate developed and undeveloped acreage in
which the Company held a leasehold mineral or other interest at December 31,
1995 and, on a pro forma basis, at September 30, 1996.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
---------------------------------------- ---------------------------------------
ACTUAL PRO FORMA(1) ACTUAL PRO FORMA(1)
----------------- ------------------ ----------------- -----------------
GROSS NET GROSS NET GROSS NET GROSS NET
------ ------ ------- ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total.......... 48,050 13,113 141,604 48,258 33,364 17,116 48,760 27,258
</TABLE>
- ---------------
(1) Gives effect to the 1996 Acquisition as if it had occurred on September 30,
1996.
DRILLING ACTIVITIES
The following table sets forth the drilling activity of the Company on its
properties for the period from March 31, 1995 (inception) through December 31,
1995, and for the nine months ended September 30, 1996.
<TABLE>
<CAPTION>
NINE MONTHS
PERIOD ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
1995 1996
--------------- ---------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Exploratory Wells
Productive......................................... 1 0.5 -- --
Nonproductive...................................... 2 1.3 1 0.2
---- --- ---- ---
Total...................................... 3 1.8 1 0.2
==== === ==== ===
Development Wells
Productive......................................... -- -- 6 3.6
Nonproductive...................................... -- -- 1 0.2
---- --- ---- ---
Total...................................... -- -- 7 3.8
==== === ==== ===
</TABLE>
31
<PAGE> 32
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and
gas production, prices and costs attributable to all oil and gas property
interests owned by the Company for the period from March 31, 1995 (inception)
through December 31, 1995 and for the nine months ended September 30, 1996.
<TABLE>
<CAPTION>
PERIOD ENDED NINE MONTHS ENDED
DECEMBER 31, 1995 SEPTEMBER 30, 1996
--------------------------- ---------------------------
HISTORICAL PRO FORMA(1) HISTORICAL PRO FORMA(1)
---------- ------------ ---------- ------------
<S> <C> <C> <C> <C>
Production:
Oil (MBbls)....................... 30 2,004 388 1,311
Gas (MMcf)........................ 245 17,952 2,725 12,235
Total (MBOE)...................... 71 4,996 842 3,350
Average sales price(2):
Oil (per Bbl)..................... $16.80 $14.23 $17.25 $17.30
Gas (per Mcf)..................... .97 1.16 1.30 1.61
Per BOE........................... 10.46 9.88 12.16 12.66
Production costs, including
production taxes (per BOE)........ $ 4.28 $ 3.49 $ 5.15(3) $ 4.13(3)
General and administrative costs
(per BOE)......................... $21.77 $ .93 $ 1.72 $ 1.04
Depletion, depreciation and
amortization expenses (per BOE)... $ 4.21 $ 3.37 $ 2.69 $ 3.58
</TABLE>
- ---------------
(1) Gives effect to the 1995 Acquisition and the 1996 Acquisition as if those
transactions had occurred on January 1, 1995.
(2) Reflects results of hedging activities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters."
(3) Includes approximately $.77 per BOE of production costs attributable to
necessary rework operations on the 1995 Acquisition.
OIL AND GAS MARKETING AND MAJOR CUSTOMERS
The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and gas. The price received by the
Company for its oil and gas production depends on numerous factors beyond the
Company's control, including seasonality, the condition of the United States
economy, particularly the manufacturing sector, foreign imports, political
conditions in other oil-producing and gas-producing countries, the actions of
OPEC and domestic government regulation, legislation and policies. Decreases in
the prices of oil and natural gas could have an adverse effect on the carrying
value of the Company's proved reserves and the Company's revenues, profitability
and cash flow. Although the Company is not currently experiencing any
significant involuntary curtailment of its oil or gas production, market,
economic and regulatory factors may in the future materially affect the
Company's ability to sell its oil or gas production. See "Risk
Factors -- Volatility of Oil and Gas Prices" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
For the nine months ended September 30, 1996, sales to Enron Corp., and its
subsidiaries and affiliates, were approximately 52% of the Company's oil and gas
revenues. See "Certain Transactions." Certain of these sales were based on six
month contracts for crude oil and month-to-month spot sales for natural gas.
Due to the availability of other markets and pipeline connections, the
Company does not believe that the loss of any single crude oil or gas customer
would have a material adverse effect on the Company's results of operations.
COMPETITION
The oil and gas industry is highly competitive. The Company encounters
competition from other oil and gas companies in all areas of its operations,
including the acquisition of producing properties. The Company's competitors
include major integrated oil and gas companies and numerous independent oil and
gas companies, individuals and drilling and income programs. Many of its
competitors are large, well established companies
32
<PAGE> 33
with substantially larger operating staffs and greater capital resources than
the Company and which, in many instances, have been engaged in the energy
business for a much longer time than the Company. Such companies may be able to
pay more for productive oil and gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The Company's
ability to acquire additional properties and to discover reserves in the future
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment. See "Risk
Factors -- Competition" and "Risk Factors -- Substantial Capital Requirements."
OPERATING HAZARDS AND UNINSURED RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
gas may involve unprofitable efforts, not only from dry wells, but from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including title
problems, weather conditions, mechanical problems, compliance with governmental
requirements and shortages or delays in the delivery of equipment and services.
The Company's future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on the Company's
future results of operations and financial condition. See "Risk
Factors -- Drilling and Operating Risks."
In addition, the Company's use of 3-D seismic requires greater pre-drilling
expenditures than traditional drilling strategies. Although the Company believes
that its use of 3-D seismic will increase the probability of success of its
exploratory wells and should reduce average finding costs through the
elimination of prospects that might otherwise be drilled solely on the basis of
2-D seismic data and other traditional methods, unsuccessful wells are likely to
occur. There can be no assurance that the Company's drilling program will be
successful or that unsuccessful drilling efforts will not have a material
adverse effect on the Company.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and gas, such as fires, natural
disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others.
The Company expects to drill a number of deep vertical and horizontal wells
in the future. The Company's deep and/or horizontal drilling activities involve
greater risk of mechanical problems than other drilling operations. These wells
may be significantly more expensive to drill than those drilled to date.
The Company maintains insurance against some, but not all, of the risks
described above. The Company may elect to self-insure in circumstances in which
management believes that the cost of insurance, although available, is excessive
relative to the risks presented. The occurrence of an event that is not covered,
or not fully covered, by insurance could have a material adverse effect on the
Company's financial condition and results of operations.
EMPLOYEES
As of December 15, 1996, the Company had 28 full-time employees, none of
whom is represented by any labor union. Included in the total were 23 corporate
employees located in the Company's office in Midland, Texas, eight of whom are
involved in the management of the Company. As a result of the 1996 Acquisition,
the Company has hired eight new employees and plans to employ an additional 15
to 20 employees. The Company considers its relations with its employees to be
good.
OTHER FACILITIES
The Company currently leases approximately 14,750 square feet of office
space in Midland, Texas, where its principal offices are located. This office
lease is with an affiliate of Jack Hightower. See "Certain
33
<PAGE> 34
Transactions." The Company's principal offices are leased through December 31,
1998. The Company expects to lease additional space early in the first quarter
of 1997 and believes it can obtain such space on commercially reasonable terms.
TITLE TO PROPERTIES
The Company received title opinions relating to properties representing 80%
of the PV-10 of the 1995 Acquisition and 90% of the PV-10 of the 1996
Acquisition. The Company's land department and contract land professionals have
reviewed title records of substantially all its producing properties. The title
investigation performed by the Company prior to acquiring undeveloped properties
is thorough but less rigorous than that conducted prior to drilling, consistent
with industry standards. The Company believes it has satisfactory title to all
of its producing properties in accordance with standards generally accepted in
the oil and gas industry. The Company's properties are subject to customary
royalty interests, liens incident to operating agreements, liens for current
taxes and other burdens which the Company believes do not materially interfere
with the use of or affect the value of such properties. The Company's Credit
Agreement is secured by a first lien on properties that represented at least 80%
of the value of the Company's proved oil and gas properties (based on PV-10 as
of September 30, 1996). Presently, the Company keeps in force its leaseholds for
64% of its net acreage by virtue of production on that acreage in paying
quantities. The remaining acreage is held by lease rentals and similar
provisions and requires production in paying quantities prior to expiration of
various time periods to avoid lease termination.
GOVERNMENTAL REGULATION
The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, because such rules and regulations are
frequently amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of such wells.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions, which affect the
marketing of gas produced by the Company, as well as the revenues received by
the Company for sales of such production. Since the mid-1980s, FERC has issued a
series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"),
that have significantly altered the marketing and transportation of gas. Order
636 mandates a fundamental restructuring of interstate pipeline sales and
transportation service, including the unbundling by interstate pipelines of the
sale, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. One of FERC's purposes in issuing
the orders is to increase competition within all phases of the gas industry.
Order 636 and subsequent FERC orders on rehearing have been appealed and are
pending judicial review. Because these orders may be modified as a result of the
appeals, it is difficult to predict the ultimate impact of the orders on the
Company and its gas marketing efforts. Generally, Order 636 has eliminated or
substantially reduced the interstate pipelines' traditional role as wholesalers
of natural gas, and has substantially increased competition and volatility in
natural gas markets.
The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to market. Effective January 1,
1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rates
to inflation, subject to certain conditions and limitations. The Company is not
able to predict with certainty the effect, if
34
<PAGE> 35
any, of these regulations on its operations. However, the regulations may
increase transportation costs or reduce wellhead prices for oil and natural gas
liquids. See "Risk Factors -- Compliance with Government Regulations."
ENVIRONMENTAL MATTERS
The Company'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
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; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness and other protected areas; and impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various of the Company's operations are subject to
revocation, modification and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations, and
violations are subject to fines or injunction, or both. In the opinion of
management, the Company is in substantial compliance with current applicable
environmental laws and regulations, and the Company has no material commitments
for capital expenditures to comply with existing environmental requirements.
Nevertheless, changes in existing environmental laws and regulations or in
interpretations thereof could have a significant impact on the Company, as well
as the oil and gas industry in general. CERCLA and comparable state statutes
impose strict, joint and several liability on owners and operators of sites and
on persons who disposed of or arranged for the disposal of "hazardous
substances" found at such sites. It is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. RCRA
and comparable state statutes govern the disposal of "solid waste" and
"hazardous waste" and authorize the imposition of substantial fines and
penalties for noncompliance. Although CERCLA currently excludes petroleum from
its definition of "hazardous substance," state laws affecting the Company's
operations impose clean-up liability relating to petroleum and petroleum related
products. In addition, although RCRA classifies certain oil field wastes as
"nonhazardous," such exploration and production wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements.
The Company has acquired leasehold interests in numerous properties that
for many years have produced oil and gas. Although the previous owners of these
interests may have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties. In addition, some of the Company's
properties are operated by third parties over whom the Company has no control.
Notwithstanding the Company's lack of control over properties operated by
others, the failure of the operator to comply with applicable environmental
regulations may, in certain circumstances, adversely impact the Company. See
"Risk Factors -- Compliance with Environmental Regulations" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
ABANDONMENT COSTS
The Company is responsible for payment of plugging and abandonment costs on
the oil and gas properties pro rata to its working interest. Based on its
experience, the Company anticipates that the ultimate aggregate salvage value of
lease and well equipment located on its properties will exceed the costs of
abandoning such properties. There can be no assurance, however, that the Company
will be successful in avoiding additional expenses in connection with the
abandonment of any of its properties. In addition, abandonment costs and their
timing may change due to many factors including actual production results,
inflation rates and changes in environmental laws and regulations.
LEGAL PROCEEDINGS
The Company presently is not a party to any legal proceedings.
35
<PAGE> 36
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the executive
officers, directors and prospective director of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Jack D. Hightower....... 48 President, Chief Executive Officer and Chairman of the Board
George G. Staley........ 62 Executive Vice President, Exploration and Director
Rodney L. Woodard....... 41 Vice President, Engineering
Thomas H. Moore......... 52 Vice President, Business Development
Dan P. Colwell.......... 52 Vice President, Land
William K. White........ 54 Vice President, Finance and Chief Financial Officer
John L. Benfatti........ 51 Vice President, Accounting and Controller
Susan D. Rowland........ 36 Vice President, Corporate Administration and Secretary
David R. Albin.......... 37 Director
Kenneth A. Hersh........ 33 Director
William J. Vaughn,
Jr.................... 76 Director*
</TABLE>
- ---------------
* Expected to be elected as a director at the Company's first regular Board of
Directors meeting following the completion of this offering.
Set forth below is a description of the backgrounds of the executive
officers, directors and prospective director of the Company.
Jack D. Hightower has served as President, Chief Executive Officer and
Chairman of the Board of Directors of the Company since he founded the Company
in March 1995. Prior to forming the Company, from 1986 to January 1996, Mr.
Hightower served as Chairman of the Board and Chief Executive Officer of United
Oil Services, Inc., a complete oil field service company serving customers in
the Permian Basin. From 1978 to 1995, Mr. Hightower served as Chairman of the
Board and President of Amber Energy, Inc., a company formed to identify oil and
gas exploration prospects. From 1991 to 1994, Mr. Hightower served as Chairman
of the Board, Chief Executive Officer and President of Enertex, Inc., which
served as the operator of record for several oil and gas properties involving
Mr. Hightower and other nonoperators, including Selma International Investment
Limited. Prior to 1978, Mr. Hightower served in a number of positions for UNOCAL
and Texas Land and Mortgage. In 1981, Mr. Hightower was a founding director of
United Bank, Midland, which was sold to Texas Commerce Bank in 1990. Since 1990,
Mr. Hightower has served on the Board of Directors of Texas Commerce Bank, N.A.,
Midland. Mr. Hightower serves on the National Petroleum Council.
George G. Staley has served as Executive Vice President, Exploration and
Director of the Company since its formation. From 1975 until 1995, Mr. Staley
served as President and Chief Executive Officer of Staley Gas Co., Inc. and
Staley Operating Co., which are oil and gas exploration and operating companies.
Prior to 1975, Mr. Staley served in a number of positions with HNG Oil Company
and its predecessors.
Rodney L. Woodard has served as Vice President, Engineering for the Company
since its formation. From 1985 to 1995, Mr. Woodard served as Vice President of
Selma International Investment Limited. Mr. Woodard was employed by Delta
Drilling Company as West Texas Division Production Manager from 1984 to 1985 and
Division Engineering Manager from 1981 to 1984. From 1979 to 1981, Mr. Woodard
served as staff engineer for Delta Drilling Company. From 1977 to 1979, Mr.
Woodard was employed by AMOCO Production Company in a number of capacities,
including senior petroleum engineer.
Thomas H. Moore has served as Vice President, Business Development of the
Company since its formation. From 1992 to 1995, Mr. Moore served as Managing
Partner of Magnum Energy Corporation, L.L.C. From 1991 until 1992, Mr. Moore
served as Executive Vice President -- Exploration and Production, Chief
Operating Officer and Director of Clayton Williams Energy, Inc. From 1985 to
1991, Mr. Moore served
36
<PAGE> 37
as President, Chief Operating Officer and Director of Clayton W. Williams, Jr.
Inc. From 1981 to 1985, Mr. Moore served initially as Manager of Exploration and
then as General Manager of Clayton W. Williams, Jr., Inc. From 1974 until
joining the Williams organization in 1981, Mr. Moore was employed by Union Texas
Petroleum Corporation, initially as an exploration geologist and ultimately as
Exploration Manager.
Dan P. Colwell has served as Vice President, Land for the Company since its
formation. From 1993 to 1995, Mr. Colwell served as Vice President of Land for
Enertex, Inc. From 1991 to 1993, Mr. Colwell was employed by ARCO as Director of
Business Development from 1991 to 1993 and Area Land Manager from 1987 to 1991.
Prior to joining ARCO, Mr. Colwell served in a number of capacities for Texaco,
Inc., Adobe Oil and Gas Corp. and Valero Producing Co.
William K. White has served as Vice President, Finance and Chief Financial
Officer of the Company since September 1996. From 1994 to September 1996, Mr.
White was Senior Vice President of the Energy Investment Group of Trust Company
of The West. From 1991 to 1994, Mr. White was President of the Odessa
Associates, a private firm engaged in the practice of providing financial
consulting services to the oil and gas industry. Prior to 1991, Mr. White served
as Vice President and Chief Financial Officer of Eastex Energy, Inc., Senior
Vice President, Finance and Administration and Chief Financial Officer of
Ensource Inc., and as Vice President -- Finance and Treasurer of Lear Petroleum
Corporation and Mitchell Energy and Development Corp. Mr. White is a member of
the National Board of Governors of the Independent Petroleum Association of
America ("IPAA"), Chairman of the IPAA Capital Markets Committee and a member of
the Board of Directors of the Oil and Gas Investment Symposium.
John L. Benfatti has served as Vice President, Accounting and Controller of
the Company since its formation. From 1980 to 1995, Mr. Benfatti served as
Controller and Treasurer of Staley Gas Co., Inc. From 1978 to 1980, Mr. Benfatti
founded and operated a data processing consulting and service company in
Midland, Texas. From 1971 to 1978, Mr. Benfatti was employed by Houston Natural
Gas Production Company and its successor, HNG Oil Company, in a number of
capacities, including Manager of Information Management Systems.
Susan D. Rowland has served as Vice President, Corporate Administration and
Secretary of the Company since its formation. From 1986 to 1996, Ms. Rowland
served as a corporate officer and administrative manager of a number of
companies, including Amber Energy, Inc., Enertex, Inc., Haley Properties, Inc.
and United Oil Services, Inc.
David R. Albin has served as a director of the Company since its formation.
Since 1988, Mr. Albin has been a manager of the NGP investment funds, which were
organized to make direct equity investments in the North American oil and gas
industry. He is currently responsible for co-managing NGP's overall investment
portfolio. From December 1984 until November 1988, Mr. Albin was employed by
Bass Investment Limited Partnership, where he was also responsible for portfolio
management. Mr. Albin serves as a director of Offshore Energy Development
Corporation, an independent oil and gas company that does not materially compete
with the Company.
Kenneth A. Hersh has served as a director of the Company since its
formation. Since 1989, Mr. Hersh has served as a co-manager of the NGP
investment funds, which were organized to make direct equity investments in the
North American oil and gas industry. He is currently responsible for co-managing
NGP's overall investment portfolio. From 1985 to 1987, Mr. Hersh was employed by
the investment banking division of Morgan Stanley & Co., where he was a member
of the Energy Group specializing in oil and gas financing and merger and
acquisition transactions. Mr. Hersh serves as a director of Mesa Inc. and HS
Resources, Inc., two independent oil and gas companies whose operations do not
materially compete with those of the Company.
William J. Vaughn, Jr. is expected to be elected as director at the
Company's first regular Board of Directors meeting following the completion of
this offering. Since 1975, Mr. Vaughn has served as Chairman of the Board and
President of WJV, Inc. and DMV, Inc., which are oil and gas exploration
companies. From 1986 to 1996, Mr. Vaughn served as Vice President of United Oil
Services, Inc., a complete oil field service company. From 1975 to 1995, Mr.
Vaughn was an independent geologist in association with Mr. Hightower.
37
<PAGE> 38
From 1948 to 1975, Mr. Vaughn was employed as a petroleum geologist by Texaco,
Inc. From 1953 to 1958, Mr. Vaughn served as District Geologist in North Texas
and from 1958 to 1975 he was Division Geologist in Texaco's Midland Division.
All directors are elected to serve until the next annual meeting of
stockholders and until their successors are elected and qualified. Executive
officers are generally elected annually by the Board of Directors to serve,
subject to the discretion of the Board of Directors, until their successors are
elected or appointed.
COMMITTEES OF THE BOARD
Upon completion of this offering, the Company will establish two standing
committees of the Board of Directors: an Audit Committee and a Compensation
Committee. Messrs. Albin, Hersh and Vaughn are expected to be members of the
Audit Committee and Compensation Committee following completion of this
offering. The Audit Committee will review the functions of the Company's
management and independent accountants pertaining to the Company's financial
statements and perform such other related duties and functions as are deemed
appropriate by the Audit Committee or the Board of Directors. The Compensation
Committee of the Board of Directors will recommend to the Board of Directors the
base salaries, bonuses and other incentive compensation for the Company's
officers. The Board of Directors has designated the Compensation Committee as
the administrator of the Company's 1996 Incentive Plan. See "Management --
Employee Benefit Plans -- 1996 Incentive Plan."
DIRECTOR COMPENSATION
Directors who are also employees of the Company are not separately
compensated for serving on the Board of Directors. Directors who are not
employees of the Company receive $15,000 per year for their services as
directors. In addition, the Company reimburses them for the expenses incurred in
connection with attending meetings of the Board of Directors and its committees.
LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
In accordance with Section 102(b)(7) of the Delaware General Corporation
Law ("DGCL"), the Company's Certificate of Incorporation includes a provision
eliminating the personal liability of members of its Board of Directors to the
corporation or its stockholders for monetary damages for breach of fiduciary
duty as a director. Such provision does not eliminate or limit the liability of
a director (1) for any breach of a director's duty of loyalty to the corporation
or its stockholders, (2) for acts or omissions not in good faith or which
involve intentional misconduct or a knowing violation of a law, (3) for paying
an unlawful dividend or approving an illegal stock repurchase (as provided in
Section 174 of the DGCL), or (4) for any transaction from which the director
derived an improper personal benefit.
The Company has entered into indemnity agreements with each of its
executive officers and directors that provide for indemnification in certain
instances against liability and expenses incurred in connection with proceedings
brought by or in the right of the Company or by third parties by reason of a
person serving as an officer or director of the Company.
The Company believes that these provisions and agreements will assist the
Company in attracting and retaining qualified individuals to serve as directors
and officers.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of the members of the Compensation Committee is or has been an
employee of the Company. No executive officer of the Company serves as a member
of the board of directors or compensation committee of any entity that has one
or more executive officers serving as a member of the Company's Board of
Directors or Compensation Committee. Messrs. Hightower, Staley, Albin, Hersh and
Vaughn, or their affiliates, have acquired capital stock of the Company. See
"Certain Transactions."
38
<PAGE> 39
EXECUTIVE COMPENSATION
The following table sets forth all compensation paid for the last fiscal
year to the Company's Chief Executive Officer and each of the Company's other
executive officers whose annual salary exceeded $100,000 on an annualized basis
for the fiscal year ended December 31, 1995, as well as to certain other
executive officers whose projected annual salary and bonus for the fiscal year
ending December 31, 1996 is in each case expected to exceed $100,000 on an
annualized basis (collectively, the "Named Executive Officers").
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
AWARDS
ANNUAL COMPENSATION ------------
--------------------------------------------- SHARES
NAME AND OTHER ANNUAL UNDERLYING ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) OPTIONS (#) COMPENSATION(2)
- ---------------------------------------- ---- ------- ------ --------------- ------------ ---------------
<S> <C> <C> <C> <C> <C> <C>
Jack D. Hightower(3).................... 1995 $75,000 $1,000 $-- 1,682,491 $ 6,201
President and Chief Executive Officer
George G. Staley(4)..................... 1995 75,000 1,000 -- 975,313 10,423
Executive Vice President, Exploration
Rodney L. Woodard(5).................... 1995 67,500 1,000 -- 196,313 5,596
Vice President, Engineering
Thomas H. Moore(6)...................... 1995 54,000 1,000 -- 210,456 3,718
Vice President, Business Development
Dan P. Colwell(7)....................... 1995 54,000 1,000 -- 196,313 5,869
Vice President, Land
</TABLE>
- ---------------
(1) Other Annual Compensation does not include perquisites and other personal
benefits because the aggregate amount of such compensation does not exceed
the lesser of (i) $50,000 or (ii) 10% of individual combined salary and
bonus for the Named Executive Officers in each year.
(2) Consists of premiums paid by the Company under a life insurance program and
contributions by the Company under its 401(k) Retirement Plan of $5,076 and
$1,125, respectively, for Mr. Hightower; $9,298 and $1,125, respectively,
for Mr. Staley; $4,583 and $1,013, respectively, for Mr. Woodard; $2,908 and
$810, respectively, for Mr. Moore; and $5,059 and $810, respectively, for
Mr. Colwell.
(3) For the period from March 31, 1995 through December 31, 1995, Mr. Hightower
earned an annual base salary of $100,000. Upon completion of this offering,
Mr. Hightower's base salary will be $160,000.
(4) For the period from March 31, 1995 through December 31, 1995, Mr. Staley
earned an annual base salary of $100,000. Upon completion of this offering,
Mr. Staley's base salary will be $160,000.
(5) For the period from March 31, 1995 through December 31, 1995, Mr. Woodard
earned an annual base salary of $90,000. Upon completion of this offering,
Mr. Woodard's base salary will be $135,000.
(6) For the period from March 31, 1995 through December 31, 1995, Mr. Moore
earned an annual base salary of $72,000. Upon completion of this offering,
Mr. Moore's base salary will be $135,000.
(7) For the period from March 31, 1995 through December 31, 1995, Mr. Colwell
earned an annual base salary of $72,000. Upon completion of this offering,
Mr. Colwell's base salary will be $135,000.
William K. White was elected Vice President, Finance and Chief Financial
Officer of the Company on September 30, 1996 and receives an annual base salary
of $135,000.
39
<PAGE> 40
Option Grants
The following table contains information about stock option grants to the
Named Executive Officers in the Conversion that were substituted for option
grants to the Named Executive Officers in 1995:
OPTION GRANTS IN THE CONVERSION TO REPLACE GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
POTENTIAL REALIZED VALUE
AT ASSUMED ANNUAL RATES OF
STOCK PRICE APPRECIATION
INDIVIDUAL GRANTS FOR OPTION TERM(1)
-------------------------------------------------- --------------------------
NUMBER OF % OF TOTAL (DOLLARS IN THOUSANDS)
SECURITIES OPTIONS EXERCISE
UNDERLYING GRANTED TO OR BASE
OPTIONS EMPLOYEES IN PRICE EXPIRATION
NAME GRANTED (#) FISCAL YEAR ($/SH) DATE 0% ($) 5% ($) 10% ($)
---- ----------- ------------ -------- ---------- ------ ------ -------
<S> <C> <C> <C> <C> <C> <C> <C>
Jack D. Hightower............ 1,682,491 49.66 2.08 3/31/2001 15,008 20,123 26,600
George G. Staley............. 975,313 28.79 2.08 3/31/2001 8,700 11,665 15,420
Rodney L. Woodard............ 196,313 5.79 2.08 3/31/2001 1,751 2,348 3,104
Thomas H. Moore.............. 210,456 6.21 2.08 3/31/2001 1,877 2,517 3,327
Dan P. Colwell............... 196,313 5.79 2.08 3/31/2001 1,751 2,348 3,104
</TABLE>
- ---------------
(1) Amounts represent hypothetical gains that could be achieved for the options
if they are exercised at the end of the option term. Those gains are based
on assumed rates of stock price appreciation of 0%, 5% and 10% compounded
annually from March 31, 1995, as if such options had been granted on such
date, through the expiration date.
Option Exercises and Year-End Option Values
The following table provides information about the number of shares issued
upon option exercises by the Named Executive Officers during 1995, and the value
realized by the Named Executive Officers. The table also provides information
about the number and value of options that would have been held by the Named
Executive Officers at December 31, 1995 as if the options granted in the
Conversion to substitute for option grants in 1995 had been granted on March 31,
1995.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FY-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS
ACQUIRED OPTIONS AT FY-END(#) AT FY-END($)
ON EXERCISE VALUE ---------------------------- ----------------------------
NAME (#) REALIZED($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- ----------- ----------- ------------- ----------- -------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Jack D. Hightower....... 0 0 0 1,682,491 0 1,430
George G. Staley........ 0 0 0 975,313 0 829
Rodney L. Woodard....... 0 0 0 196,313 0 167
Thomas H. Moore......... 0 0 0 210,456 0 179
Dan P. Colwell.......... 0 0 0 196,313 0 167
</TABLE>
Employment Agreements
The Company and Jack Hightower are parties to an Employment Agreement (the
"Employment Agreement") that provides for the employment of Mr. Hightower as
President, Chief Executive Officer and Chairman of the Board of the Company for
a two year period. The agreement provides for an annual salary of $160,000,
subject to any increases that may be approved by the Compensation Committee of
the Board of Directors from time to time during the term of the Employment
Agreement. Under the Employment Agreement, Mr. Hightower shall be entitled to
participate in any employee benefit programs which the
40
<PAGE> 41
Company provides to its executive officers. As of the date hereof, the employee
benefit programs offered by the Company to its officers and employees include
group insurance coverage, participation in the Company's 401(k) Retirement Plan
and the 1996 Incentive Plan. Under the Employment Agreement, Mr. Hightower will
be entitled to receive up to one year's base salary if his employment is
terminated other than for cause prior to the expiration of his employment term.
The agreement also provides that Mr. Hightower will not compete with the Company
for a certain period of time following any termination of his employment for any
reason.
Each of the other executive officers of the Company is a party to a
confidentiality and noncompete agreement with the Company.
EMPLOYEE BENEFIT PLANS
Initial Stock Option Plan. An option plan was adopted by the Company (the
"Initial Stock Option Plan"), in connection with the Conversion. The Initial
Stock Option Plan replaces the Option Plan adopted by the Partnership upon its
formation (the "Partnership Option Plan"). The terms of the Initial Stock Option
Plan and the options granted thereunder are substantially the same as the terms
of the Partnership Option Plan and the options granted thereunder (the
"Partnership Options").
The Initial Stock Option Plan is for the benefit of the officers and
employees of the General Partner and the Partnership who held partnership
options. Options granted under the Initial Stock Option Plan may be exercised to
acquire up to an aggregate of 3,631,350 shares of Common Stock at an exercise
price per share of $2.08. Any option holder may elect to pay the exercise price
for an option in cash, or by delivery of the option holder's secured
interest-bearing promissory term note (payable to the Company in fifteen
months), or by any combination of the foregoing.
There are four different series of options authorized under the plan, the
terms of which are substantially the same, except for the vesting requirements.
The Series A Options, which cover 2,410,728 option shares, vest ratably over
three years upon each anniversary date of March 31, if the holder remains
employed by the Company as of such date. If the holder's employment is
terminated prior to a vesting date either voluntarily by such holder or by
action of the Company for reasons other than for cause, the Option may be
exercised within three months after such termination (if otherwise prior to the
date of expiration of the Option), to purchase the number of units then vested
(with pro-rata vesting if in mid-year). One third of the shares subject to the
Series A Options (803,576 shares) are currently vested. The Board of Directors
of the Company has adopted a resolution, pursuant to the terms of the Series B,
C and D options granted under the plan, which declares that the right to
exercise the Series B Options, which cover 387,265 option shares, will vest on
March 31, 1997, the right to exercise the Series C Options, which cover 406,390
shares, will vest on March 31, 1998 and the right to exercise the Series D
Options, which cover 426,967 shares, will vest on March 31, 1999.
1996 Incentive Plan. The Board of Directors and the stockholders of the
Company approved the adoption of the Company's 1996 Incentive Plan (the "1996
Incentive Plan") as of October 1, 1996. The purpose of the 1996 Incentive Plan
is to reward selected officers and key employees of the Company and others who
have been or may be in a position to benefit the Company, compensate them for
making significant contributions to the success of the Company and provide them
with a proprietary interest in the growth and performance of the Company.
Participants in the 1996 Incentive Plan are selected by the Board of
Directors or such committee of the Board as is designated by the Board to
administer the 1996 Incentive Plan (upon completion of this offering, the
Compensation Committee of the Board of Directors) from among those who hold
positions of responsibility with the Company and whose performance, in the
judgment of the Compensation Committee, can have a significant effect on the
success of the Company. An aggregate of 850,000 shares of Common Stock have been
authorized and reserved for issuance pursuant to the 1996 Incentive Plan. As of
October 1, 1996, options have been granted to participants under the 1996
Incentive Plan to purchase a total of 85,000 shares of Common Stock at an
exercise price per share equal to the Price to Public set forth on the cover
page of this Prospectus. These options vest ratably on each of the first through
fourth anniversaries of the grant date.
41
<PAGE> 42
Subject to the provisions of the 1996 Incentive Plan, the Compensation
Committee will be authorized to determine the type or types of awards made to
each participant and the terms, conditions and limitations applicable to each
award. In addition, the Compensation Committee will have the exclusive power to
interpret the 1996 Incentive Plan and to adopt such rules and regulations as it
may deem necessary or appropriate in keeping with the objectives of the 1996
Incentive Plan.
Pursuant to the 1996 Incentive Plan, participants will be eligible to
receive awards consisting of (i) stock options, (ii) stock appreciation rights,
(iii) stock, (iv) restricted stock, (v) cash or (vi) any combination of the
foregoing. Stock options may be either incentive stock options within the
meaning of Section 422 of the Internal Revenue Code of 1986, as amended, or
nonqualified stock options.
42
<PAGE> 43
CERTAIN TRANSACTIONS
On March 31, 1995, the Partnership was formed with an initial
capitalization of approximately $20.5 million by NGP and certain individuals,
including the following officers and directors of the Company: Jack D. Hightower
(President, Chief Executive Officer and Chairman of the Board), George G. Staley
(Executive Vice President, Exploration, and Director), Rodney L. Woodard (Vice
President, Engineering), Thomas H. Moore (Vice President, Business Development),
Dan P. Colwell (Vice President, Land), David R. Albin (Director), Kenneth A.
Hersh (Director) and William J. Vaughn, Jr. (prospective Director). On December
11, 1995, the Company sold partnership units equivalent to 3,423,194 shares and
1,711,597 shares of Common Stock to JEDI and First Union Corporation,
respectively, for $10 million and $5 million, respectively. In connection with
these transactions, the Company granted NGP, Jack Hightower, JEDI and First
Union Corporation certain registration rights. See "Description of Capital
Stock -- Registration Rights."
The Company has entered into an administrative services contract with
Staley Operating Co. ("Staley Operating"), an affiliate of Mr. Staley. Pursuant
to the agreement, the Company provided certain administrative, accounting and
other office and technical services on behalf of Staley Operating, in its
capacity as the operator of certain producing oil and gas properties, in return
for which the Company received the amounts charged by Staley Operating for
providing such services under the applicable operating agreements for such
properties. The amounts charged by, and in turn received by the Company from,
Staley Operating are determined on the same basis as amounts charged by the
Company to unaffiliated third parties with respect to properties for which the
Company serves as operator. The total amount of payments received by the Company
under such agreement was $241,563 in 1995 and $139,789 for the nine months ended
September 30, 1996.
Mr. Hightower and certain of his affiliates have a common ownership
interest in the Haley 1302 gas well located in Winkler County, Texas. The well
is operated by the Company and, in accordance with a standard industry operating
agreement, Mr. Hightower and certain of his affiliates make payments to the
Company of leasehold costs and lease operating and supervision charges. These
payments aggregated approximately $12,000 for the nine months ended December 31,
1995 and approximately $284,000 for the nine months ended September 30, 1996.
The fees charged by the Company to Mr. Hightower are the same as those charged
to unaffiliated third parties that are also party to the operating agreement.
The Company does not consider the property to constitute a material portion of
its assets.
In April 1995, the Company purchased certain oil and gas properties from
Enertex, Inc. ("Enertex"), an affiliate of Mr. Hightower, and from Staley Gas
Co. Inc. ("Staley"), an affiliate of George Staley. The purchase price for such
properties was approximately $1,065,000 for the Enertex properties and
approximately $77,000 for the Staley properties. Because the Company, with
approval of its independent directors, purchased these interests at their cost
to Enertex and Staley, the Company believes that the terms of the purchases were
no less favorable to the Company than could have been obtained from unaffiliated
third parties.
For advisory services in connection with the organization and initial
financing of the Company, the Company paid NGP $125,000. The Company is also a
party to separate financial advisory services contracts with ECT Securities
Corp. ("ECT") (an affiliate of JEDI) and NGP. In 1995, the Company made payments
to ECT and NGP of $200,000 and approximately $79,000, respectively, for fees and
expense reimbursements under these agreements. During 1996, ECT is entitled to
an annual fee of $100,000, payable quarterly in arrears, plus expense
reimbursements, and NGP is entitled to an annual fee of $85,000 payable
quarterly in arrears, plus expense reimbursements. Both agreements will
terminate as of the completion of this offering.
In November 1995, the Company entered into master agreements for energy
price swaps with ECTRC and First Union National Bank of North Carolina,
affiliates of JEDI and First Union Corporation, respectively. Pursuant to the
terms of these agreements and as a result of losses attributable to natural gas
hedges, during the nine months ended September 30, 1996, the Company paid
approximately $256,000 and $297,000 to ECTRC and First Union National Bank of
North Carolina, respectively. Prior to entering into these agreements, the
Company reviewed price swaps offered by other institutions and believes that the
terms of the agreements are no less favorable to it than could have been
obtained from unaffiliated third parties.
43
<PAGE> 44
For the nine months ended September 30, 1996, sales to Enron Corp. (an
affiliate of JEDI), its subsidiaries and affiliates were approximately 52% of
the Company's oil and gas revenues. The Company entered into the agreements
pursuant to which these sales were made after competitive bidding and believes
that the terms of these sales are no less favorable to it than could have been
obtained from unaffiliated third parties.
The Company's offices are in Fasken Center located at 500 West Texas, Suite
500, in Midland, Texas and are leased from Fasken Center Ltd., an affiliate of
Mr. Hightower. The lease is a noncancellable operating lease that terminates on
December 31, 1998 and requires monthly rent payments of $9,219. The rental rate
of $7.50 per square foot per year is below the average rental rate of $7.95 per
square foot per year for the remaining occupied space. The Company expects to
amend the lease in the fourth quarter of 1996 to obtain additional space at or
below $7.95 per square foot per year. In addition, the Company also regularly
uses certain aircraft owned by Lone Star Jet, Inc., an affiliate of Jack
Hightower. The Company is billed by Lone Star Jet, Inc. at a rate equal to the
price of a full-fare ticket on a commercial airline for any use of such aircraft
by Company personnel. Approximately $4,000 was paid by the Company for the use
of such aircraft in 1995 and approximately $11,000 was paid for the nine months
ended September 30, 1996. The Company believes that the terms of these
agreements and arrangements with affiliates of Mr. Hightower are no less
favorable to the Company than could be obtained from unaffiliated third parties.
First Union Bank of North Carolina, an affiliate of First Union
Corporation, is a member of the bank group that lends to the Company under the
Credit Agreement. See "Use of Proceeds."
44
<PAGE> 45
PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information regarding the beneficial
ownership of the Company's Common Stock as of September 30, 1996, and as
adjusted to give effect to the sale of 12,500,000 shares of Common Stock in this
offering, by (i) each person the Company knows to be the beneficial owner of 5%
or more of the outstanding shares of Common Stock, (ii) each Named Executive
Officer, (iii) each director of the Company, (iv) all executive officers and
directors of the Company as a group and (v) the Selling Stockholder. Except as
indicated in the footnotes to this table and pursuant to applicable community
property laws, the Company believes that each stockholder named in this table
has sole investment and voting power with respect to the shares set forth
opposite such stockholder's name.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED PRIOR TO THE OWNED AFTER THE
OFFERING(1) OFFERING(1)
--------------------- SHARES BEING ---------------------
BENEFICIAL OWNER NUMBER PERCENT OFFERED NUMBER PERCENT
---------------- --------- ------- ------------ --------- -------
<S> <C> <C> <C> <C> <C>
Natural Gas Partners II,
L.P(2)........................ 5,000,777 25.58% -- 5,000,777 15.60%
777 Main Street, Suite 2700
Fort Worth, Texas 76102
Natural Gas Partners, L.P.(3)... 4,767,407 24.39% -- 4,767,407 14.87%
777 Main Street, Suite 2700
Fort Worth, Texas 76102
Joint Energy Development(4)
Investments Limited
Partnership................... 3,423,194 17.51% -- 3,423,194 10.68%
1400 Smith Street
Houston, Texas 77002
First Union Corporation......... 1,711,597 8.75% 110,000 1,601,597 5.00%
One First Union Center
301 South College Street
Charlotte, North Carolina
28288
Jack D. Hightower(5)............ 3,255,988 16.33% -- 3,255,988 10.04%
500 West Texas, Suite 500
Midland, Texas 79701
George G. Staley(6)............. 428,231 2.17% -- 428,231 1.33%
Thomas H. Moore(7).............. 149,094 * -- 149,094 *
Dan P. Colwell(8)............... 94,598 * -- 94,598 *
Rodney L. Woodard(9)............ 95,518 * -- 95,518 *
David R. Albin(2)(10)........... 95,772 * -- 95,772 *
Kenneth A. Hersh(2)............. 49,881 * -- 49,881 *
William J. Vaughn, Jr.(11)...... 332,541 1.70% -- 332,541 1.04%
All executive officers and
directors as a group (10
persons)(12).................. 4,533,921 22.28% -- 4,533,921 13.80%
</TABLE>
- ---------------
* Represents less than 1% of outstanding Common Stock or voting power.
(1) Shares beneficially owned and percentage of ownership are based on
19,550,013 shares of Common Stock outstanding before this offering and
32,050,013 shares of Common Stock outstanding after the closing. Beneficial
ownership is determined in accordance with the rules of the Commission and
generally includes voting and investment power with respect to securities.
(2) David R. Albin and Kenneth A. Hersh are each managing members of the
general partner of Natural Gas Partners II, L.P. As such, Mr. Albin and Mr.
Hersh may be deemed to share voting and investment
45
<PAGE> 46
power with respect to the 5,000,777 shares beneficially owned by Natural
Gas Partners II, L.P. Mr. Albin and Mr. Hersh disclaim beneficial ownership
of such shares.
(3) G.F.W. Energy, L.P. ("GFW") is the general partner of Natural Gas Partners,
L.P., and R. Gamble Baldwin is the general partner of GFW.
(4) Enron Capital Management Limited Partnership ("ECMLP") is the general
partner of JEDI, and Enron Capital Corp., an indirectly wholly-owned
subsidiary of Enron Corp., is the general partner of ECMLP.
(5) Includes (i) 2,667,588 shares held by Mr. Hightower, (ii) 199,524 shares
held by Mr. Hightower's spouse and children, and (iii) 388,876 shares
subject to stock options that are exercisable within 60 days. Excludes
1,366,716 shares subject to stock options that are not exercisable within
60 days.
(6) Includes (i) 199,525 shares held by Mr. Staley, and (ii) 228,706 shares
subject to stock options that are exercisable within 60 days. Excludes
803,465 shares subject to stock options that are not exercisable within 60
days.
(7) Includes (i) 99,762 shares held by Mr. Moore, and (ii) 49,332 shares
subject to stock options that are exercisable within 60 days. Excludes
173,310 shares subject to stock options that are not exercisable within 60
days.
(8) Includes (i) 46,556 shares held by Mr. Colwell, and (ii) 48,042 shares
subject to stock options that are exercisable within 60 days. Excludes
168,577 shares subject to stock options that are not exercisable within 60
days.
(9) Includes (i) 46,556 shares held by Mr. Woodard, and (ii) 48,962 shares
subject to stock options that are exercisable within 60 days. Excludes
171,718 shares subject to stock options that are not exercisable within 60
days.
(10) All of these shares are held in trust for Mr. Albin.
(11) Includes 299,287 shares held in trust for Mr. Vaughn and his spouse and
33,254 shares held by an affiliate of Mr. Vaughn.
(12) Includes 796,216 shares that officers and directors as a group have the
right to acquire within 60 days through the exercise of options granted
pursuant to the Initial Stock Option Plan and the 1996 Incentive Plan.
Excludes 2,802,645 shares subject to stock options that are not exercisable
within 60 days.
46
<PAGE> 47
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 60,000,000 shares
of Common Stock, par value $.01 per share, and 10,000,000 shares of preferred
stock, par value $.01 per share ("Preferred Stock"). Of such authorized shares,
32,050,013 shares of Common Stock will be issued and outstanding upon completion
of this offering (33,941,513 shares if the Underwriters exercise their
over-allotment option in full). As of September 30, 1996, the Company had
outstanding 19,550,013 shares of Common Stock held of record by 24 stockholders
and stock options for an aggregate of 3,631,350 shares.
COMMON STOCK
The holders of Common Stock are entitled to one vote for each share held of
record on all matters submitted to the stockholders, and are entitled to
cumulate their votes for the election of directors. As a result of such
cumulative voting rights, any holder of at least 20% of the outstanding Common
Stock will be assured that such holder's nominee will be elected as a director
for so long as the Board of Directors of the Company consists of five members.
See "Risk Factors -- Control by Existing Stockholders." The Certificate of
Incorporation of the Company does not allow the stockholders to take action by
less than unanimous consent, but the Bylaws of the Company permit the holders of
10% or more of the Company's outstanding Common Stock to call a special meeting
of the stockholders not more frequently than once during each calendar year. The
affirmative vote of the holders of shares of capital stock representing at least
80% of the outstanding voting power shall be required to amend certain
provisions of the Certificate of Incorporation relating to the management of the
Company. Each share of Common Stock is entitled to participate equally in
dividends, if, as and when declared by the Company's Board of Directors, and in
the distribution of assets in the event of liquidation, subject in all cases to
any prior rights of outstanding shares of Preferred Stock. The Company has never
paid cash dividends on its Common Stock. The shares of Common Stock have no
preemptive or conversion rights, redemption rights, or sinking fund provisions.
The outstanding shares of Common Stock are, and the shares of Common Stock
offered hereby upon issuance and sale will be, duly authorized, validly issued,
fully paid, and nonassessable.
PREFERRED STOCK
As of September 30, 1996, the Company has no outstanding Preferred Stock.
The Company is authorized to issue 10,000,000 shares of Preferred Stock. The
Company's Board of Directors may establish, without stockholder approval, one or
more classes or series of Preferred Stock having the number of shares,
designations, relative voting rights, dividend rates, liquidation and other
rights, preferences, and limitations that the Board of Directors may designate.
The Company believes that this power to issue Preferred Stock will provide
flexibility in connection with possible corporate transactions. The issuance of
Preferred Stock, however, could adversely affect the voting power of holders of
Common Stock and restrict their rights to receive payments upon liquidation of
the Company. It could also have the effect of delaying, deferring or preventing
a change in control of the Company. The Company does not currently plan to issue
any shares of Preferred Stock.
DELAWARE LAW PROVISIONS
The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law. Generally, Section 203 prohibits the Company
from engaging in a "business combination" (as defined in Section 203) with an
"interested stockholder" (defined generally as a person owning 15% or more of
the Company's outstanding voting stock) for three years following the date that
person becomes an interested stockholder, unless (a) before that person became
an interested stockholder, the Company's Board of Directors approved the
transaction in which the interested stockholder became an interested stockholder
or approved the business combination; (b) upon completion of the transaction
that resulted in the interested stockholder's becoming an interested
stockholder, the interested stockholder owns at least 85% of the voting stock
outstanding at the time the transaction commenced (excluding stock held by
directors who are also officers of the Company and by employee stock plans that
do not provide employees with the right to determine confidentially whether
shares held subject to the plan will be tendered in a tender or exchange
47
<PAGE> 48
offer) or (c) following the transaction in which that person became an
interested stockholder, the business combination is approved by the Company's
Board of Directors and authorized at a meeting of stockholders by the
affirmative vote of the holders of at least two-thirds of the outstanding voting
stock not owned by the interested stockholder.
Under Section 203, these restrictions also do not apply to certain business
combinations proposed by an interested stockholder following the announcement or
notification of one of certain extraordinary transactions involving the Company
and a person who was not an interested stockholder during the previous three
years or who became an interested stockholder with the approval of a majority of
the Company's directors, if that extraordinary transaction is approved or not
opposed by a majority of the directors who were directors before any person
became an interested stockholder in the previous three years or who were
recommended for election or elected to succeed such directors by a majority of
such directors then in office.
REGISTRATION RIGHTS
The Company has entered into the Amended and Restated Registration Rights
Agreement with Natural Gas Partners, L.P., Natural Gas Partners, II, L.P., Jack
Hightower, JEDI, First Union Corporation and Selma International Investment
Limited (the "Shareholder Parties"). See "Management -- Certain Transactions."
Pursuant to the Amended and Restated Registration Rights Agreement, on three
separate occasions, commencing on the 180th day following the date of the
Company's initial registration statement under the securities laws, Shareholder
Parties owning at least 35% of the outstanding shares then subject to such
agreement may require the Company to register shares held by them under
applicable securities laws, provided that the shares to be registered have an
estimated aggregate offering price to the public of at least $3,000,000. The
Amended and Restated Registration Rights Agreement also provides that the
Shareholder Parties have piggyback registration rights pursuant to which such
persons may include shares of Common Stock held by them in certain registrations
initiated by the Company or by any other holder of the Company's Common Stock.
The piggyback rights are subject to customary cutback provisions.
The Amended and Restated Registration Rights Agreement provides for
customary indemnities by the Company in favor of persons including shares in a
registration pursuant to the Amended and Restated Registration Rights Agreement,
and by such persons in favor of the Company, with respect to information to be
included in the relevant registration statement. These registration rights have
been waived in connection with this offering and for 180 days after the date of
this Prospectus.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Common Stock is First Union
National Bank of North Carolina.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of this offering, the Company will have 32,050,013 shares
of Common Stock outstanding (33,941,513 shares if the Underwriters exercise
their over-allotment option in full). Of these shares, the 12,610,000 shares of
Common Stock sold in this offering will be freely transferable without
restriction under the Securities Act unless they are held by the Company's
affiliates, as that term is used in Rule 144 under the Securities Act. The
Company issued the remaining 19,440,013 shares of Common Stock in reliance on
exemptions from the registration requirements of the Securities Act, and those
shares are restricted securities under Rule 144. Those shares may not be sold
publicly unless they are registered under the Securities Act, sold in compliance
with Rule 144, or sold in a transaction that is exempt from registration. The
Company believes that the earliest date on which the 19,440,013 shares of its
Common Stock currently outstanding will be eligible for sale under Rule 144 is
October 1, 1998. Therefore, no shares will be eligible for immediate sale in the
public market without restriction under Rule 144(k), and no shares will be
eligible for immediate sale under the manner-of-sale, volume and other
limitations of Rule 144. Beginning October 1, 1998, all of the shares of Common
Stock currently outstanding will become eligible for sale under Rule 144, based
on current Commission rules and subject to compliance with the manner-of-sale,
volume and other
48
<PAGE> 49
requirements of Rule 144. Beginning October 1, 1999, all of those shares of
Common Stock will become eligible for sale under Rule 144(k) if they are not
held by affiliates of the Company.
In general, under Rule 144 a person (or persons whose sales are
aggregated), including an affiliate, who has beneficially owned shares for at
least two years is entitled to sell in broker transactions, within any three-
month period commencing 90 days after this offering, a number of shares that
does not exceed the greater of (i) 1% of the then outstanding Common Stock
(approximately 320,500 shares immediately after this offering) or (ii) the
average weekly trading volume in the Common Stock during the four calendar weeks
preceding the sale, subject to the filing of a Form 144 with respect to the sale
and other limitations. In addition, a person who was not an affiliate of the
Company during the three months preceding a sale and who has beneficially owned
the shares proposed to be sold for at least three years is entitled to sell the
shares under Rule 144(k) without regard to the manner-of-sale, volume and other
limitations of Rule 144. The Commission has proposed to shorten the holding
periods under Rule 144 for restricted securities. The Commission has indicated
that, if adopted, the proposed amendment would apply to all outstanding
restricted securities. All shares of Common Stock, other than those offered
hereby, are subject to lock-up agreements with the Underwriters for 180 days
after the date of this Prospectus. See "Underwriting."
The holders of approximately 13,225,429 shares of Common Stock and their
permitted transferees are entitled to demand registration of those shares under
the Securities Act beginning 180 days after the date of this Prospectus. See
"Description of Capital Stock -- Registration Rights."
The Company intends to file a registration statement under the Securities
Act to register Common Stock to be issued pursuant to the exercise of options,
including options under the Initial Stock Option Plan. Taking into account the
effect of the lock-up agreement with the holders of options, approximately
1,994,417 shares issuable upon exercise of vested options will be eligible for
sale in the public market beginning 180 days after commencement of this
offering, subject, in the case of sales by affiliates, to the manner-of-sale,
volume and other limitations requirements of Rule 144.
Prior to this offering, there has been no public market for the securities
of the Company. No prediction can be made of the effect, if any, that the sale
or availability for sale of shares of additional Common Stock will have on the
market price of the Common Stock. Nevertheless, sales of substantial numbers of
shares by existing stockholders or by stockholders purchasing in this offering
could have a negative effect on the market price of the Common Stock.
49
<PAGE> 50
UNDERWRITING
Under the terms and subject to the conditions contained in an Underwriting
Agreement dated December 16, 1996 (the "Underwriting Agreement"), the
Underwriters named below (the "Underwriters"), for whom Credit Suisse First
Boston Corporation; Donaldson, Lufkin & Jenrette Securities Corporation; Howard,
Weil, Labouisse, Friedrichs Incorporated; J.P. Morgan Securities Inc. and Petrie
Parkman & Co., Inc. are acting as representatives (the "Representatives"), have
severally, but not jointly, agreed to purchase from the Company and the Selling
Stockholder, the following respective numbers of shares of Common Stock:
<TABLE>
<CAPTION>
NUMBER
UNDERWRITERS OF SHARES
------------ ----------
<S> <C>
Credit Suisse First Boston Corporation.................... 1,486,000
Donaldson, Lufkin & Jenrette Securities Corporation....... 1,486,000
Howard, Weil, Labouisse, Friedrichs Incorporated.......... 1,486,000
J.P. Morgan Securities Inc................................ 1,486,000
Petrie Parkman & Co., Inc................................. 1,486,000
Bear, Stearns & Co. Inc................................... 280,000
J.C. Bradford & Co........................................ 140,000
BT Securities Corporation................................. 280,000
Cowen & Company........................................... 280,000
Credit Lyonnais Securities (USA) Inc...................... 280,000
Dillon, Read & Co. Inc.................................... 280,000
A.G. Edwards & Sons, Inc.................................. 280,000
EVEREN Securities, Inc.................................... 140,000
Gerard Klauer Mattison & Co., LLC......................... 140,000
Goldman, Sachs & Co....................................... 280,000
Hanifen, Imhoff Inc....................................... 140,000
Jefferies & Company, Inc.................................. 140,000
Johnson Rice & Company L.L.C.............................. 140,000
Kirkpatrick, Pettis, Smith, Polian Inc.................... 140,000
Lehman Brothers Inc....................................... 280,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated........ 280,000
Morgan Stanley & Co. Incorporated......................... 280,000
Nesbitt Burns Securities Inc.............................. 140,000
PaineWebber Incorporated.................................. 280,000
Prudential Securities Incorporated........................ 280,000
Rauscher Pierce Refsnes, Inc.............................. 140,000
Smith Barney Inc.......................................... 280,000
Wasserstein Perella Securities, Inc....................... 280,000
----------
Total........................................... 12,610,000
==========
</TABLE>
The Underwriting Agreement provides that the obligations of the
Underwriters are subject to certain conditions precedent and that the
Underwriters will be obligated to purchase all the shares of Common Stock
offered hereby (other than those shares covered by the over-allotment option
described below) if any are purchased. The Underwriting Agreement provides that,
in the event of a default by an Underwriter, in certain circumstances the
purchase commitments of nondefaulting Underwriters may be increased or the
Underwriting Agreement may be terminated.
The Company has granted to the Underwriters an option, expiring at the
close of business on the 30th day after the date of this Prospectus, to purchase
up to 1,891,500 additional shares of Common Stock at the initial public offering
price less the underwriting discounts and commissions, all as set forth on the
cover page of this Prospectus. Such option may be exercised only to cover
over-allotments in the sale of the shares of Common
50
<PAGE> 51
Stock. To the extent such option is exercised, each Underwriter will become
obligated, subject to certain conditions, to purchase approximately the same
percentage of such additional shares of Common Stock as it was obligated to
purchase pursuant to the Underwriting Agreement.
The Company has been advised by the Representatives that the Underwriters
propose to offer the shares of Common Stock to the public initially at the
public offering price set forth on the cover page of this Prospectus and,
through the Representatives, to certain dealers at such price less a concession
of $0.42 per share, and the Underwriters and such dealers may allow a discount
of $0.10 per share on sales to certain other dealers. After the initial public
offering, the public offering price and concession and discount to dealers may
be changed by the Representatives.
The Representatives have informed the Company that they do not expect
discretionary sales by the Underwriters to exceed five percent of the shares
being offered hereby.
The Company intends to use more than 10% of the net proceeds from the sale
of the shares offered by the Company to repay indebtedness owed by it to Morgan
Guaranty Trust Company of New York, an affiliate of one of the underwriters,
J.P. Morgan Securities Inc. Accordingly, this offering is being made in
compliance with the requirements of Rule 2720(c) of the Conduct Rules of the
National Association of Securities Dealers, Inc. This rule provides generally
that if more than 10% of the net proceeds from the sale of stock, not including
underwriting compensation, is paid to the underwriters of such stock or their
affiliates, the initial public offering price of the stock may not be higher
than that recommended by a "qualified independent underwriter" meeting certain
standards. Credit Suisse First Boston Corporation is assuming the
responsibilities of acting as the qualified independent underwriter in pricing
this offering and conducting due diligence. The initial public offering price of
the Shares set forth on the cover page of this Prospectus is no higher than the
price recommended by Credit Suisse First Boston Corporation.
The Company, its officers, directors, stockholders and optionholders have
agreed that they will not offer, sell, contract to sell, announce an intention
to sell, pledge or otherwise dispose of, directly or indirectly, or file with
the Commission a Registration Statement under the Securities Act, relating to,
any additional shares of the Company's Common Stock or securities convertible
into or exchangeable or exercisable for any shares of the Company's Common Stock
without the prior written consent of Credit Suisse First Boston Corporation for
a period of 180 days after the date of this Prospectus, except issuances
pursuant to the exercise of employee stock options outstanding on the date
hereof. See "Shares Eligible for Future Sale."
Prior to this offering, there has been no public market for the Common
Stock. The initial public offering price for the shares of Common Stock was
negotiated among the Company and the Underwriters. Among the factors considered
in determining the initial public offering price, in addition to prevailing
market conditions, are the history of, and prospects for, the industry in which
the Company operates, the earnings of the Company and comparable companies in
recent periods, management expertise and the Company's business potential and
earnings prospects.
The Underwriters are reserving up to 200,000 shares of Common Stock in this
offering for sales to officers, directors and employees of the Company and the
Selling Stockholder and their friends and relatives at the initial public
offering price. Any shares of Common Stock not purchased by those persons will
be sold to the general public in this offering.
The Company and the Selling Stockholder have agreed to indemnify the
Underwriters against certain liabilities, including civil liabilities under the
Securities Act, or contribute to payments which the Underwriters may be required
to make in respect thereof.
The shares of Common Stock have been approved for listing on The Nasdaq
Stock Market's National Market (the "NNM"), subject to official notice of
issuance, under the symbol "TEXP." In connection with the listing of the Common
Stock on the NNM, the Underwriters will undertake to sell round lots of 100
shares or more to a minimum of 400 beneficial owners.
51
<PAGE> 52
NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the shares of Common Stock in Canada is being made only
on a private placement basis exempt from the requirement that the Company
prepare and file a prospectus with the securities regulatory authorities in each
province where trades of the Common Stock are affected. Accordingly, any resale
of the shares of Common Stock in Canada must be made in accordance with
applicable securities laws, which will vary depending on the relevant
jurisdiction, and which may require resales to be made in accordance with
available statutory exemptions or pursuant to a discretionary exemption granted
by the applicable Canadian securities regulatory authority. Canadian purchasers
are advised to seek legal advice prior to any resale of the Common Stock.
REPRESENTATIONS OF PURCHASERS
Each purchaser of the Common Stock in Canada who receives a purchase
confirmation will be deemed to represent to the Company and the dealer from whom
such purchase confirmation is received that (i) such purchaser is entitled under
applicable provincial securities laws to purchase such Common Stock without the
benefit of a prospectus qualified under such securities laws, (ii) where
required by law, that such purchaser is purchasing as principal and not as
agent, and (iii) such purchaser has reviewed the text above under "Resale
Restrictions."
RIGHTS AND ACTIONS OF ENFORCEMENT
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the Securities Act (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.
All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Ontario purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of shares of Common Stock to whom the Securities Act (British
Columbia) applies is advised that such purchaser is required to file with the
British Columbia Securities Commission a report within ten days of the sale of
any shares of Common Stock acquired by such purchaser pursuant to this Offering.
Such report must be in the form attached to British Columbia Securities
Commission Blanket Order BOR #95/17, a copy of which may be obtained from the
Company. Only one such report must be filed in respect of shares of the Common
Stock acquired on the same date and under the same prospectus exemption.
LEGAL MATTERS
Certain legal matters in connection with the Common Stock being offered
hereby will be passed upon for the Company by Thompson & Knight, P.C., Dallas,
Texas. Certain matters relating to this offering will be passed upon for the
Underwriters by Vinson & Elkins L.L.P., Dallas, Texas.
EXPERTS
The consolidated financial statements of the Company as of December 31,
1995 and for the period March 31, 1995 (date of inception) to December 31, 1995,
the statements of revenues and direct operating expenses of the 1996 Acquisition
for the years ended December 31, 1993, 1994 and 1995, and the statements
52
<PAGE> 53
of revenues and direct operating expenses of the 1995 Acquisition for the years
ended December 31, 1993 and 1994, and the period ended December 11, 1995, have
been included herein and in the registration statement in reliance upon the
report of KPMG Peat Marwick LLP, independent certified public accountants,
appearing elsewhere herein, and upon the authority of said firm as experts in
accounting and auditing.
With respect to the unaudited interim financial information for the periods
ended September 30, 1995 and 1996, included herein, the independent certified
public accountants have reported that they applied limited procedures in
accordance with professional standards for a review of such information.
However, their report included herein, states that they did not audit and they
do not express an opinion on such interim financial information. Accordingly,
the degree of reliance on their report on such information should be restricted
in light of the limited nature of the review procedures applied. The accountants
are not subject to the liability provisions of Section 11 of the Securities Act
for their report on the unaudited interim financial information because that
report is not a "report" or a "part" of the registration statement prepared or
certified by the accountants within the meaning of Sections 7 and 11 of the
Securities Act.
The letters of Williamson Petroleum Consultants, Inc., independent oil and
gas consultants, set forth in Appendix A, have been included herein in reliance
upon the firm as experts with respect to the matters contained in those letters.
In addition, the information with respect to the reserve reports prepared by
Williamson has been included herein in reliance upon the firm as experts with
respect to such information.
ADDITIONAL INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-1 (as amended and together with all exhibits thereto, the "Registration
Statement") under the Securities Act, with respect to the shares of Common Stock
offered by this Prospectus. This Prospectus constitutes a part of the
Registration Statement and does not contain all of the information set forth in
the Registration Statement, certain parts of which are omitted from this
Prospectus as permitted by the rules and regulations of the Commission.
Statements contained in this Prospectus as to the contents of any contract,
agreement or other document referred to herein are not necessarily complete.
Statements in this Prospectus about the contents of any contract or other
document are not necessarily complete; reference is made in each instance to the
copy of the contract or other document filed as an exhibit to the Registration
Statement. Each such statement is qualified in all respects by such reference.
The Registration Statement and accompanying exhibits and schedules may by
inspected and copies may be obtained (at prescribed rates) at the public
reference facilities of the Commission at Judiciary Plaza, 450 Fifth Street,
N.W., Room 1024, Washington, D.C. 20549. Copies of the Registration Statement
may also be inspected at the Commission's regional offices at 7 World Trade
Center, Suite 1300, New York, New York 10048 and Citicorp Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661-2511. In addition, the
Common Stock will be listed on the Nasdaq National Market, 1735 K Street, N.W.,
Washington, D.C. 20006-1500, where such material may also be inspected and
copied.
As a result of this offering, the Company will become subject to the
information and periodic reporting requirements of the Securities Exchange Act
of 1934, and, in accordance therewith, will file periodic reports, proxy
statements and other information with the Commission. Such periodic reports,
proxy statements and other information will be available for inspection and
copying at the public reference facilities, regional offices and stock exchange
referred to above. In addition, these reports, proxy statements and other
information may also be obtained from the web site that the Commission maintains
at http://www.sec.gov.
53
<PAGE> 54
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and this Prospectus. Unless otherwise indicated in this
Prospectus, natural gas volumes are stated at the legal pressure base of the
state or area in which the reserves are located and at 60 degrees Fahrenheit and
in most instances are rounded to the nearest major multiple. BOEs are determined
using the ratio of six Mcf of natural gas to one Bbl of oil.
"Bbl" means a barrel of 42 U.S. gallons of oil.
"BBtu" means one billion British Thermal Units.
"Bcf" means billion cubic feet of natural gas.
"Blowdown" means the reduction of pressure in a formation as a result of
the production of gas.
"BOE" means barrels of oil equivalent.
"Btu" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit.
"Completion" means the installation of permanent equipment for the
production of oil or gas.
"Condensate" means a hydrocarbon mixture that becomes liquid and separates
from natural gas when the gas is produced and is similar to crude oil.
"Development well" means a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
"Down-spacing" means providing for more dense spacing by infill drilling.
"Exploratory well" means a well drilled to find and produce oil or gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
"Gross," when used with respect to acres or wells, refers to the total
acres or wells in which the Company has a working interest.
"Infill drilling" means drilling of an additional well or wells provided
for by an existing spacing order to more adequately drain a reservoir.
"MBbls" means thousands of barrels of oil.
"Mcf" means thousand cubic feet of natural gas.
"MMBbls" means millions of barrels of oil.
"MMBC" means millions of barrels of condensate.
"MMBOE" means millions of barrels of oil equivalent on a 6:1 basis.
"MMBtu" means one million British Thermal Units.
"MMcf" means million cubic feet of natural gas.
"Net," when used with respect to acres or wells, refers to gross acres of
wells multiplied, in each case, by the percentage working interest owned by the
Company.
"Net production" means production that is owned by the Company less
royalties and production due others.
"Oil" means crude oil or condensate.
"Operator" means the individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
54
<PAGE> 55
"Present Value of Future Net Revenues" or "PV-10" means the pretax present
value of estimated future revenues to be generated from the production of proved
reserves calculated in accordance with Commission guidelines, net of estimated
production and future development costs, using prices and costs as of the date
of estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
"Project" means a proposal to add a producing completion of oil or gas. A
proposal may vary in range from work authorized to be performed to proposals
that are founded in geologic and engineering principles yet require further
research before funds are authorized.
"Proved developed reserves" means reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
"Proved reserves" means the estimated quantities of crude oil, natural gas,
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
ii. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
iii. Estimates of proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (C) crude oil, natural gas, and natural gas liquids that
may occur in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids that may be recovered from oil shales, coal, gilsonite
and other such sources.
"Proved undeveloped reserves" means reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
"Recompletion" means the completion for production of an existing well bore
in another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
55
<PAGE> 56
"Royalty" means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"Sidetrack drilling" means an operation involving the use of a portion of
an existing well to drill a second hole, resulting in a well that is partly old
and partly new.
"Spud" means to start drilling a new well (or restart).
"3-D seismic" means seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
"Spudded" means the first boring of the hole in the drilling of a well.
"Step-out well" means a well drilled adjacent to a proven well but located
in an unproven area; a well drilled as a "step-out" from proven territory in an
effort to ascertain the extent and boundaries of a producing formation.
"Tcf" means trillion cubic feet of natural gas.
"Tertiary recovery" means enhanced recovery methods for the production of
oil or gas. Enhanced recovery of crude oil requires a means for displacing oil
from the reservoir rock, modifying the properties of the fluids in the reservoir
and/or the reservoir rock to cause movement of oil in an efficient manner, and
providing the energy and drive mechanism to force its flow to a production well.
The Company injects chemicals or energy as required for displacement and for the
control of flow rate and flow pattern in the reservoir, and a fluid drive is
provided to force the oil toward a production well.
"Waterflood" means the injection of water into a reservoir to fill pores
vacated by produced fluids, thus maintaining reservoir pressure and assisting
production.
"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
"Workover" means operations on a producing well to restore or increase
production.
56
<PAGE> 57
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Financial Statements of Titan Exploration, Inc.
Pro Forma Condensed Balance Sheet as of September 30, 1996 (unaudited).............. F1-2
Pro Forma Condensed Statement of Operations for the year ended December 31, 1995
(unaudited)...................................................................... F1-3
Pro Forma Condensed Statement of Operations for the nine months ended September 30,
1996 (unaudited)................................................................. F1-4
Notes to Unaudited Pro Forma Condensed Financial Statements......................... F1-5
Independent Auditor's Report........................................................ F2-1
Independent Accountant's Review Report.............................................. F2-2
Consolidated Balance Sheets as of December 31, 1995 and September 30, 1996
(unaudited)...................................................................... F2-3
Consolidated Statements of Operations for the period March 31, 1995 (date of
inception) through December 31, 1995 and the periods ended September 30, 1995 and
1996
(unaudited)...................................................................... F2-4
Consolidated Statements of Stockholders' Equity for the period March 31, 1995 (date
of inception) through December 31, 1995 and the period ended September 30, 1996
(unaudited)...................................................................... F2-5
Consolidated Statements of Cash Flows for the period March 31, 1995 (date of
inception) through December 31, 1995 and the periods ended September 30, 1995 and
1996
(unaudited)...................................................................... F2-6
Notes to Consolidated Financial Statements.......................................... F2-7
Financial Statements of the 1995 Acquisition:
Independent Auditors' Report........................................................ F3-1
Statements of Revenues and Direct Operating Expenses for the years ended December
31, 1993 and 1994 and the period ended December 11, 1995......................... F3-2
Notes to the Statements of Revenues and Direct Operating Expenses................... F3-3
Financial Statements of the 1996 Acquisition:
Independent Auditors' Report........................................................ F4-1
Statements of Revenues and Direct Operating Expenses for the years ended December
31, 1993, 1994 and 1995, and the nine months ended September 30, 1995 and 1996
(unaudited)...................................................................... F4-2
Notes to the Statements of Revenues and Direct Operating Expenses................... F4-3
</TABLE>
F-1
<PAGE> 58
PRO FORMA CONDENSED FINANCIAL STATEMENTS
The Unaudited Pro Forma Condensed Financial Statements of the Company have
been prepared to give effect to the 1995 Acquisition and the 1996 Acquisition,
the Conversion, and this offering and the application of the estimated net
proceeds therefrom as if such transactions (to the extent not already reflected)
had taken place on September 30, 1996 for purposes of the Pro Forma Condensed
Balance Sheet and as if the transactions had taken place on January 1, 1995 for
purposes of the Pro Forma Condensed Statements of Operations. The Pro Forma
Condensed Financial Statements of the Company are not necessarily indicative of
the results for the periods presented had the 1995 Acquisition and the 1996
Acquisition, the Conversion, and this offering and the application of the
estimated net proceeds therefrom taken place on January 1, 1995. In addition,
future results may vary significantly from the results reflected in the
accompanying Pro Forma Condensed Financial Statements because of normal
production declines, changes in product prices, and the success of future
exploration and development activities, among other factors. This information
should be read in conjunction with the Consolidated Financial Statements of
Titan Exploration, Inc., and the Statements of Revenues and Direct Operating
Expenses with respect to the properties acquired in the 1995 Acquisition and the
1996 Acquisition, all included elsewhere herein.
F1-1
<PAGE> 59
TITAN EXPLORATION, INC.
PRO FORMA CONDENSED BALANCE SHEET -- UNAUDITED
SEPTEMBER 30, 1996
(IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA OFFERING PRO FORMA
TITAN ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
-------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Current assets:
Cash and cash equivalents.................. $ 10,803 $ 10,803 $ 128,050(b) $ 10,803
(128,050)(c)
Accounts receivable:
Oil and gas............................. 1,844 1,844 1,844
Other................................... 1,143 1,143 1,143
Prepaid expenses and other current
assets.................................. 42 42 42
-------- --------- ---------
Total current assets............... 13,832 13,832 13,832
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties....................... 62,022 $ 127,034(a) 189,056 189,056
Unproved properties..................... 507 507 507
Accumulated depletion, depreciation and
amortization............................ (2,361) (2,361) (2,361)
-------- --------- ---------
60,168 187,202 187,202
Other property and equipment, net.......... 277 277 277
Other assets, net.......................... 547 450(a) 997 997
-------- --------- ---------
$ 74,824 $ 202,308 $ 202,308
======== ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Trade accounts payable..................... $ 4,810 $ 4,810 $ 4,810
Accrued interest........................... 112 112 112
Other current liabilities.................. 150 307(a) 457 457
-------- --------- ---------
Total current liabilities.......... 5,072 5,379 5,379
Long-term debt............................. 28,000 125,877(a) 153,877 (128,050)(c) 25,827
Other liabilities.......................... 803 1,300(a) 2,103 2,103
Deferred income taxes...................... 2,998 2,998 2,998
-------- --------- ---------
Total liabilities.................. 36,873 164,357 36,307
Stockholders' equity:
Preferred Stock, $.01 par value, 10,000
shares authorized, no shares issued..... -- --
Common Stock, $.01 par value, 60,000 shares
authorized, 19,550 shares issued and
outstanding............................. 195 195 125(b) 320
Additional paid-in capital................. 54,180 54,180 127,925(b) 182,105
Deferred compensation...................... (16,424) (16,424) (16,424)
-------- --------- ---------
Total stockholders' equity......... 37,951 37,951 166,001
-------- --------- ---------
$ 74,824 $ 202,308 $ 202,308
======== ========= =========
</TABLE>
See accompanying notes to unaudited pro forma condensed financial statements.
F1-2
<PAGE> 60
TITAN EXPLORATION, INC.
PRO FORMA CONDENSED STATEMENT OF OPERATIONS -- UNAUDITED
YEAR ENDED DECEMBER 31, 1995
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
PERIOD
MARCH 31, 1995
(DATE OF INCEPTION)
THROUGH
DECEMBER 31, 1995 PRO FORMA
------------------- 1995 1996 PRO FORMA OFFERING PRO FORMA
TITAN ACQUISITION ACQUISITION ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
------------------- ----------- ----------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues................ $ 985 $10,829 $37,777 $49,591 $49,591
------ ------- ------- ------- -------
Expenses:
Oil and gas
production......... 304 4,619 12,512 17,435 17,435
General and
administrative..... 1,546 -- -- 3,079(d) 4,625 4,625
Amortization of stock
option awards...... 576 -- -- 576 576
Exploration and
abandonments....... 490 -- -- 490 490
Depletion,
depreciation and
amortization....... 299 -- -- 16,533(e) 16,832 16,832
Interest.............. 97 -- -- 10,791(f) 10,888 (8,743)(g) 2,145
Other................. (796) -- -- (796) (796)
------ ------- ------- ------- -------
2,516 4,619 12,512 50,050 41,307
------ ------- ------- ------- -------
Net income (loss) before
federal income
taxes................. (1,531) 6,210 25,265 (459) 8,284
Provision for federal
income taxes.......... -- -- -- -- 2,899(h) 2,899
------ ------- ------- ------- -------
Net income (loss)....... $(1,531) $ 6,210 $25,265 $ (459) $ 5,385
====== ======= ======= ======= =======
Net income (loss) per
share................. $ (.11) $ (.03) $ .18
====== ======= =======
</TABLE>
See accompanying notes to unaudited pro forma condensed financial statements.
F1-3
<PAGE> 61
TITAN EXPLORATION, INC.
PRO FORMA CONDENSED STATEMENT OF OPERATIONS -- UNAUDITED
NINE MONTHS ENDED SEPTEMBER 30, 1996
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, 1996 PRO FORMA
------------------ 1996 PRO FORMA OFFERING PRO FORMA
TITAN ACQUISITION ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
------------------ ----------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Revenues............................. $ 10,377 $32,177 $42,554 $42,554
------ ------- ------- -------
Expenses:
Oil and gas production............. 4,339 9,481 13,820 13,820
General and administrative......... 1,452 -- 2,017(d) 3,469 3,469
Amortization of stock option
awards.......................... 576 576 576
Exploration and abandonments....... 110 -- 110 110
Depletion, depreciation and
amortization.................... 2,269 -- 9,732(e) 12,001 12,001
Interest........................... 1,179 -- 6,723(f) 7,902 (6,307)(g) 1,595
Other.............................. (336) -- (336) (336)
------ ------- ------- -------
9,589 9,481 37,542 31,235
------ ------- ------- -------
Net income before federal income
taxes.............................. 788 22,696 5,012 11,319
Provision for federal income taxes... 2,998 -- 1,754(h) 4,752 (791)(h) 3,961
------ ------- ------- -------
Net income (loss).................... $ (2,210) $22,696 $ 260 $ 7,358
====== ======= ======= =======
Net income (loss) per share.......... $ (.12) $ .01 $ .21
====== ======= =======
</TABLE>
See accompanying notes to unaudited pro forma condensed financial statements.
F1-4
<PAGE> 62
TITAN EXPLORATION, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS
(1) BASIS OF PRESENTATION
The Pro Forma Condensed Financial Statements of the Company have been
prepared to give effect to the 1995 Acquisition and the 1996 Acquisition, the
Corporate Reorganization and this offering and the application of estimated net
proceeds therefrom as if such transactions had taken place on September 30, 1996
for purposes of the Pro Forma Condensed Balance Sheet (with the exception of the
1995 Acquisition which was previously reflected in the balance sheet of Titan
Exploration, Inc.), and as if each of the transactions had taken place on
January 1, 1995 for purposes of the Pro Forma Condensed Statements of
Operations. The 1995 Acquisition and 1996 Acquisition are accounted for by the
purchase method.
Titan -- Represents the consolidated balance sheet of Titan
Exploration, Inc. as of September 30, 1996 and the related consolidated
statements of operations for the period March 31, 1995 (date of inception)
through December 31, 1995 and the nine months ended September 30, 1996.
1995 Acquisition -- Represents the revenues and direct operating
expenses of the properties acquired in the 1995 Acquisition for the period
from January 1, 1995 to December 11, 1995 (date of the 1995 Acquisition).
1996 Acquisition -- Represents the revenues and direct operating
expenses of the properties acquired in the 1996 Acquisition for the year
ended December 31, 1995 and the nine months ended September 30, 1996. The
1996 Acquisition was consummated on October 31, 1996.
(2) PRO FORMA ENTRIES
(a) To record the issuance of additional long-term debt under the Credit
Agreement, to record the related debt issuance costs, and to record the use of
the net proceeds for the 1996 Acquisition.
(b) To reflect the issuance of 12,500,000 shares of Common Stock at the
offering price of $11.00 per share for estimated proceeds of $128,050,000, net
of estimated expenses of this offering.
(c) To record the use of the estimated net proceeds of this offering to
partially repay borrowings under the Credit Agreement.
(d) Estimated incremental general and administrative expenses necessary to
administer the properties acquired in the 1995 and 1996 acquisitions of
approximately $2,742,000 for the year ended December 31, 1995 and $1,764,000 for
the nine months ended September 30, 1996, and increased public reporting and
administration costs of approximately $337,000 per year. In the aggregate, these
costs include salary and benefits for one executive level employee and
approximately 20 additional administrative personnel, directors' fees, insurance
coverage, and estimated costs to administer shareholder communications.
(e) To record estimated incremental depletion expense for the properties
acquired in the 1995 Acquisition from January 1, 1995 through December 11, 1995
(date of the 1995 Acquisition) and for the properties acquired in the 1996
Acquisition from January 1, 1995 through September 30, 1996.
(f) To adjust interest expense to reflect additional borrowings for the
properties acquired in the 1995 Acquisition from January 1, 1995 to December 11,
1995 (date of the 1995 Acquisition) and for the properties acquired in the 1996
Acquisition from January 1, 1995 through September 30, 1996. Also included is
the amortization of estimated debt issuance costs of $450,000 over approximately
a four-year period.
F1-5
<PAGE> 63
TITAN EXPLORATION, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (CONTINUED)
(2) PRO FORMA ENTRIES (CONTINUED)
Incremental interest expense includes the following components:
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
(IN THOUSANDS)
<S> <C> <C>
Additional interest on borrowings associated with the
1995 Acquisition for the period January 1, 1995
through December 11, 1995 (average rate 6.82%)..... $ 1,289 $ --
Additional interest on borrowings for the 1996
Acquisition (average rate of 6.82% in 1995 and
6.75% in 1996)..................................... 9,392 6,640
Amortization of loan fees............................ 110 83
------- -------
$ 10,791 $ 6,723
======== =======
</TABLE>
(g) To adjust interest expense to reflect the partial repayment of
borrowings under the Credit Agreement with net proceeds of this offering of
approximately $128,050,000 at average rates described in (f) above.
(h) To record income tax expense.
(3) INCOME TAXES
The Company accounts for income taxes pursuant to the provisions of SFAS
109. At September 30, 1996, the pro forma book basis of the Company's assets and
liabilities exceeded the pro forma tax basis by approximately $8,818,000, giving
rise to an estimated deferred tax liability of approximately $2,998,000. The
temporary differences are primarily related to the differences in book and tax
basis of oil and gas properties due to the expensing of intangible development
costs for tax purposes and other income tax differences arising from the tax
treatment of oil and gas producing activities.
(4) NET INCOME (LOSS) PER SHARE
Net income (loss) per share is calculated based on the pro forma weighted
average shares outstanding during the respective periods. Weighted average
shares reflect the pro forma issuance of 5,134,791 shares of Common Stock on
December 11, 1995, the pro forma issuance of 13,692,776 shares of Common Stock
to the original holders prior to January 1, 1995 and the issuance on September
27, 1996 of 722,446 shares for total consideration of $5,000,000. In addition,
the issuance of 12,500,000 shares in this offering is assumed to have taken
place on January 1, 1995 and assumes that the underwriters' overallotment option
is not exercised.
Outstanding options to acquire 3,631,350 shares at $2.08 per share are
treated as Common Stock equivalents for each period shown if dilutive. The
number of equivalent shares was determined by the treasury stock method based on
the offering price of $11.00 per share.
F1-6
<PAGE> 64
TITAN EXPLORATION, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (CONTINUED)
(5) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The estimates of proved oil and gas reserves, which are located in the
United States, were prepared by the Company as of December 31, 1993, 1994 and
1995. Reserves were estimated in accordance with guidelines established by the
Securities and Exchange Commission and FASB which require that reserve estimates
be prepared under existing economic and operating conditions with no provision
for price and cost escalations except by contractual arrangements. The Company
has presented the pro forma reserve estimates utilizing an oil price of $23.37
per Bbl and a gas price of $1.39 per Mcf as of September 30, 1996. The pro forma
information assumes that both the 1995 Acquisition and the 1996 Acquisition took
place on January 1, 1995.
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
<TABLE>
<CAPTION>
OIL AND NATURAL
CONDENSATE (MBBLS) GAS (MMCF)
------------------ ----------
<S> <C> <C>
Total Proved Reserves:
Balance, January 1, 1995............................... 16,823 225,555
Revision of previous estimates....................... 1,533 711
Extensions and discoveries........................... 108 33,724
Production........................................... (2,004) (17,951)
------ -------
Balance, December 31, 1995............................. 16,460 242,039
Extensions and discoveries........................... 180 45,931
Purchases of minerals-in-place....................... 704 264
Revision of previous estimates....................... 1,810 4,825
Production........................................... (1,311) (12,235)
------ -------
Balance, September 30, 1996............................ 17,843 280,824
====== =======
Proved Developed Reserves at December 31, 1995......... 14,259 145,023
====== =======
Proved Developed Reserves at September 30, 1996........ 15,533 148,477
====== =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas
Reserves
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on period-end costs) to be incurred in developing and producing the
proved reserves, less estimated future income tax expenses (based on period-end
statutory tax rates, with consideration of future tax rates already legislated)
to be incurred on pretax net cash flows less tax basis of the properties and
available credits, and assuming continuation of existing economic conditions.
The estimated future net cash flows are then discounted using a rate of 10% per
year to reflect the estimated timing of the future cash flows.
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks
F1-7
<PAGE> 65
TITAN EXPLORATION, INC.
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL STATEMENTS (CONTINUED)
(5) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (CONTINUED)
associated with future production. Because of these and other considerations,
any estimate of fair value is necessarily subjective and imprecise.
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Future:
Cash inflows.............................................. $ 654,666 $ 808,031
Production and development costs.......................... (262,007) (302,959)
Future income taxes....................................... (73,518) (108,740)
---------- ----------
Net cash flows......................................... 319,141 396,332
10% annual discount for estimated timing of cash flows...... (142,720) (167,133)
---------- ----------
Standardized measure of discounted net cash flows........... $ 176,421 $ 229,199
========= ==========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows From
Proved Reserves
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
1995 1996
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Standardized measure, beginning of period................... $186,689 $176,421
Extensions and discoveries and improved recovery, net of
future production and development costs................ 18,421 31,919
Accretion of discount..................................... 18,689 13,195
Net change in sales prices, net of production costs....... 12,844 32,502
Net change in income taxes................................ (40,630) (22,251)
Change in estimated future development cost............... -- 692
Purchase of minerals-in-place............................. -- 4,928
Revision of quantity estimates............................ 6,642 12,502
Sales, net of production costs............................ (31,914) (28,594)
Other..................................................... 5,680 7,885
-------- --------
Standardized measure, end of period......................... $176,421 $229,199
======== ========
</TABLE>
F1-8
<PAGE> 66
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Titan Exploration, Inc.
We have audited the accompanying consolidated balance sheet of Titan
Exploration, Inc. and subsidiaries (the Company) as of December 31, 1995, and
the related consolidated statement of operations, stockholders' equity, and cash
flows for the period from March 31, 1995 (date of inception) through December
31, 1995. 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Titan Exploration, Inc. and subsidiaries as of December 31, 1995, and the
results of its operations and its cash flows for the period from March 31, 1995
(date of inception) through December 31, 1995, in conformity with generally
accepted accounting principles.
Midland, Texas KPMG PEAT MARWICK LLP
March 21, 1996,
except as to Note 1,
which is as of
September 30, 1996.
F2-1
<PAGE> 67
INDEPENDENT ACCOUNTANTS' REVIEW REPORT
The Board of Directors and Shareholders
Titan Exploration, Inc.
We have reviewed the consolidated balance sheet of Titan Exploration, Inc.
and subsidiaries as of September 30, 1996, and the related consolidated
statements of operations and cash flows for the period March 31, 1995 (date of
inception) through September 30, 1995 and the nine-month period ended September
30, 1996. These financial statements are the responsibility of the Company's
management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical review
procedures to financial data and making inquiries of persons responsible for
financial and accounting matters. It is substantially less in scope than an
audit conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the consolidated financial statements referred to above for
them to be in conformity with generally accepted accounting principles.
KPMG PEAT MARWICK LLP
Midland, Texas
November 4, 1996
F2-2
<PAGE> 68
TITAN EXPLORATION, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
(UNAUDITED)
<S> <C> <C>
Current assets:
Cash and cash equivalents........................................ $ 6,213 $ 10,803
Short-term investment -- certificate of deposit.................. 5,000 --
Accounts receivable:
Oil and gas................................................... 996 1,844
Other......................................................... 1,554 1,143
Prepaid expenses and other current assets........................ 80 42
-------- ---------
Total current assets..................................... 13,843 13,832
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of
accounting:
Proved properties............................................. 42,895 62,022
Unproved properties........................................... 190 507
Accumulated depletion, depreciation and amortization............. (216) (2,361)
-------- ---------
42,869 60,168
Other property and equipment, net................................ 129 277
-------- ---------
42,998 60,445
Other assets, net of accumulated amortization of $78 in 1995 and
$177 in 1996..................................................... 646 547
-------- ---------
$ 57,487 $ 74,824
======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Trade......................................................... $ 1,766 $ 4,810
Accrued interest.............................................. 97 112
Other......................................................... 75 150
-------- ---------
Total current liabilities................................ 1,938 5,072
Long-term debt..................................................... 20,000 28,000
Other liabilities.................................................. 964 803
Deferred income tax payable........................................ -- 2,998
Stockholders' equity:
Preferred Stock, $.01 par value, 10,000 shares authorized, no
shares issued................................................. -- --
Common Stock, $.01 par value, 60,000 shares authorized, 19,550
shares issued and outstanding................................. 188 195
Additional paid-in capital....................................... 36,893 54,180
Deferred compensation............................................ (2,496) (16,424)
-------- ---------
Total stockholders' equity............................... 34,585 37,951
-------- ---------
$ 57,487 $ 74,824
======== =========
</TABLE>
These consolidated financial statements reflect the reorganization described in
Note 1.
See accompanying notes to consolidated financial statements.
F2-3
<PAGE> 69
TITAN EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
PERIOD PERIOD
MARCH 31, 1995 MARCH 31, 1995
(DATE OF INCEPTION) (DATE OF INCEPTION) NINE MONTHS
THROUGH THROUGH ENDED
DECEMBER 31, SEPTEMBER 30, SEPTEMBER 30,
1995 1995 1996
------------------- ------------------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Revenues:
Oil and gas sales............................. $ 743 $ 12 $10,237
Management fees -- affiliate.................. 242 161 140
------- ----- -------
Total revenues........................ 985 173 10,377
Expenses:
Oil and gas production........................ 304 37 4,339
General and administrative.................... 1,546 668 1,452
Amortization of stock option awards........... 576 -- 576
Exploration and abandonment................... 490 -- 110
Depletion, depreciation and amortization...... 299 57 2,269
------- ----- -------
Total expenses........................ 3,215 762 8,746
------- ----- -------
Operating income (loss)............... (2,230) (589) 1,631
Other income (expense):
Interest income............................... 699 471 336
Interest expense.............................. (97) -- (1,179)
Gain on sale of assets........................ 244 198 --
Loss on commodity derivative contracts........ (147) -- --
------- ----- -------
Net income (loss) before federal income
taxes.................................... $(1,531) $ 80 $ 788
======= ===== =======
Provision for federal income taxes:
Current....................................... -- -- --
Deferred...................................... -- -- 2,998
------- ----- -------
Net income (loss).......................... $(1,531) $ 80 $(2,210)
======= ===== =======
Net income (loss) per share................ $ (.11) $ .01 $ (.12)
======= ===== =======
</TABLE>
These consolidated financial statements reflect the reorganization described in
Note 1.
See accompanying notes to consolidated financial statements.
F2-4
<PAGE> 70
TITAN EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID-IN DEFERRED STOCKHOLDERS'
STOCK CAPITAL COMPENSATION EQUITY
------ ---------- ------------ ------------
<S> <C> <C> <C> <C>
Balance at March 31, 1995..................... $ -- $ -- $ -- $ --
Capital contributions....................... -- 35,540 -- 35,540
Common stock issued......................... 188 (188) -- --
Deferred compensation....................... -- 3,072 (2,496) 576
Net loss.................................... -- (1,531) -- (1,531)
---- -------- -------- --------
Balance at December 31, 1995.................. 188 36,893 (2,496) 34,585
Sale of common shares (unaudited)........... 7 4,993 -- 5,000
Deferred compensation (unaudited)........... -- -- 576 576
September 30, 1996 stock plan (unaudited)... -- 14,504 (14,504) --
Net loss (unaudited).......................... -- (2,210) -- (2,210)
---- -------- -------- --------
Balance at September 30, 1996 (unaudited)..... $195 $ 54,180 $(16,424) $ 37,951
==== ======== ======== ========
</TABLE>
These consolidated financial statements reflect the reorganization described in
Note 1.
See accompanying notes to consolidated financial statements.
F2-5
<PAGE> 71
TITAN EXPLORATION, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
PERIOD PERIOD
MARCH 31, 1995 MARCH 31, 1995 NINE
(DATE OF INCEPTION) (DATE OF INCEPTION) MONTHS
THROUGH THROUGH ENDED
DECEMBER 31, SEPTEMBER 30, SEPTEMBER 30,
1995 1995 1996
------------------- ------------------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)................................. $ (1,531) $ 80 $ (2,210)
Adjustments to reconcile net income (loss) to net
cash used in operating activities:
Depletion, depreciation and amortization....... 299 57 2,269
Amortization of stock option awards............ 576 -- 576
Dry holes and abandonments..................... 434 -- 21
Gain on sale of assets......................... (244) (198) --
Deferred income taxes.......................... -- -- 2,998
Changes in assets and liabilities:
Increase in accounts receivable................ (2,153) (166) (833)
(Increase) decrease in prepaid expenses and
other current assets......................... (80) (11) 38
Increase in other assets....................... (724) (506) --
Increase in accounts payable and accrued
liabilities.................................. 1,659 231 2,794
--------- ------- --------
Total adjustments......................... (233) (593) 7,863
--------- ------- --------
Net cash provided by (used in) operating
activities.............................. (1,764) (513) 5,653
--------- ------- --------
Cash flows from investing activities:
Purchase of short-term investment................. (5,000) (5,000) --
Redemption of short-term investment............... -- -- 5,000
The 1995 Acquisition.............................. (39,881) -- --
Additions to oil and gas properties............... (3,796) (2,333) (17,590)
Additions to other property and equipment......... (134) (54) (173)
Proceeds from sale of nonproducing oil and gas
properties, net of commissions paid............ 1,248 948 --
--------- ------- --------
Net cash used in investing activities..... (47,563) (6,439) (12,763)
--------- ------- --------
Cash flows from financing activities:
Proceeds from the issuance of long-term debt...... 28,000 -- 8,000
Payments of long-term debt........................ (8,000) -- --
Capital contributions............................. 35,540 20,540 3,700
--------- ------- --------
Net cash provided by financing
activities.............................. 55,540 20,540 11,700
--------- ------- --------
Net increase in cash and cash
equivalents............................. 6,213 13,588 4,590
Cash and cash equivalents, beginning of period...... -- -- 6,213
--------- ------- --------
Cash and cash equivalents, end of period............ $ 6,213 $13,588 $ 10,803
========= ======= ========
</TABLE>
These consolidated financial statements reflect the reorganization described in
Note 1.
See accompanying notes to consolidated financial statements.
F2-6
<PAGE> 72
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(1) ORGANIZATION AND NATURE OF OPERATIONS
Titan Exploration, Inc. (the "Company"), a Delaware corporation, was
organized on September 27, 1996 and began operations on September 30, 1996 with
the combination, pursuant to the terms of an Exchange Agreement and Plan of
Reorganization (the "Exchange Agreement"), of Titan Resources I, Inc. (the
"General Partner"), a Texas corporation, and Titan Resources, L.P. (the
"Partnership"). Under the exchange agreement, the limited partners of the
Partnership transferred all of their limited partnership interests to the
Company in exchange for 19,318,199 shares of common stock, and the shareholders
of the General Partner transferred all of the issued and outstanding stock of
that corporation to the Company in exchange for an aggregate of 231,814 shares
of common stock. These transactions are referred to as the "Conversion."
Prior to the Conversion, the Company had no issued or outstanding shares of
common stock and there was no public market for the General Partner's common
stock. All shares of the Company currently outstanding were issued in the
Conversion to the shareholders of the General Partner or to the limited partners
of the Partnership. The combination of the Company, the General Partner and the
Partnership is treated as a combination of entities under common control because
of the 100% commonality of control between the Company subsequent to the
Conversion and the Partnership prior to the Conversion. All partners of the
Partnership were party to the exchange of shares in the Conversion.
Consequently, the accompanying consolidated financial statements have given
effect to the Conversion as if it were a pooling of interests. Revenues and
costs arising from transactions between the two predecessor entities (the
General Partner and the Partnership) have been eliminated. The following table
sets forth revenues and net income with respect to the two predecessor entities
(in thousands):
<TABLE>
<CAPTION>
PERIOD PERIOD
MARCH 31, 1995 MARCH 31, 1995
(DATE OF INCEPTION) (DATE OF INCEPTION) NINE MONTHS
THROUGH THROUGH ENDED
DECEMBER 31, SEPTEMBER 30, SEPTEMBER 30,
1995 1995 1996
------------------- ------------------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Revenues:
General Partner...................... $ 680 $ 453 $ 729
Partnership.......................... 985 173 10,377
Intercompany eliminations............ (680) (453) (729)
------- ----- -------
$ 985 $ 173 $10,377
======= ===== =======
Net income (loss):
General Partner...................... $ (9) $ 13 $ (26)
Partnership.......................... (1,522) 67 (2,184)
Intercompany eliminations............ -- -- --
------- ----- -------
$(1,531) $ 80 $(2,210)
======= ===== =======
</TABLE>
The Company is an independent energy company engaged in the exploration,
development and acquisition of oil and gas properties. Since its inception in
March 1995, the Company has experienced significant growth, primarily through
the acquisition of oil and gas properties and the exploitation of these
properties in the Permian Basin region of west Texas and southeastern New
Mexico.
F2-7
<PAGE> 73
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its subsidiaries, each of which is wholly owned, since their formation (See
Note 1). All material intercompany accounts and transactions have been
eliminated in the consolidation.
Use of Estimates
Preparation of the accompanying consolidated financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Company considers all
demand deposits, money market accounts and certificates of deposit purchased
with an original maturity of three months or less to be cash equivalents.
Oil and Gas Properties
The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all costs associated
with productive wells and nonproductive development wells are capitalized.
Exploration costs are capitalized pending determination of whether proved
reserves have been found. If no proved reserves are found, previously
capitalized exploration costs are charged to expense.
Costs of significant nonproducing properties, wells in the process of being
drilled and development projects are excluded from depletion until such time as
the related project is developed and proved reserves are established or
impairment is determined. The Company capitalizes interest on expenditures for
significant development projects until such time as significant operations
commence.
Capitalized costs of individual properties abandoned or retired are charged
to accumulated depletion, depreciation and amortization. Sales proceeds from
sales of individual properties are credited to property costs. No gain or loss
is recognized until the entire amortization base is sold or abandoned.
Other property and equipment are recorded at cost. Major renewals and
betterments are capitalized while the costs of repairs and maintenance are
charged to operating expenses in the period incurred. With respect to
dispositions of assets other than oil and gas properties, the cost of assets
retired or otherwise disposed of, and the applicable accumulated depreciation
are removed from the accounts, and the resulting gains or losses, if any, are
reflected in operations.
Depletion, Depreciation and Amortization
Provision for depletion of oil and gas properties is calculated using the
unit-of-production method on the basis of an aggregation of properties with a
common geologic structural feature or stratigraphic condition, typically a field
or reservoir. In addition, estimated costs of future dismantlement, restoration
and abandonment, if any, are accrued as a part of depreciation, depletion and
amortization expense on a unit of production basis; actual costs are charged to
the accrual. Other property and equipment is depreciated using the straight-line
method over the estimated useful lives of the assets. Organization costs are
amortized over five years, while loan costs are amortized over the life of the
related loan.
F2-8
<PAGE> 74
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Impairment of Long-Lived Assets
The Company follows 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 ("FAS 121"). Consequently, the Company
reviews its long-lived assets to be held and used, including oil and gas
properties accounted for under the successful efforts method of accounting,
whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. An impairment loss is indicated if the sum of the
expected future cash flows is less than the carrying amount of the assets. No
impairment was determined to exist during the period March 31, 1995 (date of
inception) through December 31, 1995 or during the nine months ended September
30, 1996.
The Company accounts for long-lived assets to be disposed of at the lower
of their carrying amount or fair value less cost to sell once management has
committed to a plan to dispose of the assets.
Net Income (Loss) per Share
Net income (loss) per share is calculated based on the weighted average
number of shares and share equivalents, if dilutive, outstanding during the
period.
Income Taxes
The Company follows the provisions of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("FAS 109"). Under the asset and liability
method of FAS 109, 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. 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. Under FAS
109, the effect on deferred tax assets and liabilities of a change in tax rate
is recognized in income in the period that includes the enactment date.
The Company has recorded the tax effect of the differences between the book
and tax basis of it assets and liabilities as a deferred tax liability and a
corresponding charge to deferred income tax expense. At September 30, 1996, the
excess of book basis over tax basis of assets and liabilities is $8,818,000.
Environmental
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
of a noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.
Revenue Recognition
The Company uses the sales method of accounting for crude oil revenues.
Under this method, revenues are recognized based on actual volumes of oil sold
to purchasers.
F2-9
<PAGE> 75
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
The Company uses the entitlements method of accounting for natural gas
revenues. Under this method, revenues are recognized based on the Company's
proportionate share of actual sales of natural gas. Natural gas revenues would
not have been significantly altered in any period had the sales method of
recognizing natural gas revenues been utilized.
Commodity Hedging
The Company periodically enters into commodity derivative contracts (swaps)
in order to hedge the effect of price changes on commodities the Company
produces and sells. Gains and losses on contracts that are designed to hedge
commodities are included in income recognized from the sale of those
commodities. Gains and losses on derivative contracts which do not qualify as
hedges are recognized in each period based on the market value of the related
instrument.
Interest Rate Swap Agreements
The Company enters into interest rate swap agreements to effectively
convert a portion of its floating-rate borrowings into fixed rate obligations.
The interest rate differential to be received or paid is recognized over the
lives of the agreements as an adjustment to interest expense.
Interim Consolidated Financial Statements
The interim consolidated financial information as of September 30, 1996 and
for the periods ended September 30, 1995 and 1996, is unaudited. However, in the
opinion of management, these interim consolidated financial statements include
all the necessary adjustments to fairly present the results of the interim
periods, and all such adjustments are of a normal recurring nature. The interim
consolidated financial statements should be read in conjunction with the audited
financial statements for the period March 31, 1995 (date of inception) through
December 31, 1995.
(3) DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amount of cash, short-term investments, accounts receivable,
accounts payable, and accrued liabilities approximates fair value because of the
short maturity of these instruments.
The carrying amount of long-term debt approximates fair value because the
Company's current borrowing rate does not materially differ from market rates
for similar bank borrowings.
The fair market values of commodity derivative instruments are estimated
based upon the current market price of the respective commodities at the date of
valuation. It represents the amount which the Company would be required to pay
or able to receive based upon the differential between a fixed and a variable
commodity price as specified in the hedge contracts. At December 31, 1995 and
September 30, 1996, the Company would be required to pay approximately $606,000
and $652,000, respectively, to terminate the existing contracts.
The fair values of interest rate swap agreements are obtained from bank
quotes. This value represents the estimated amount the Company would pay to
terminate the agreement, taking into consideration current interest rates. The
Company estimates that, at December 31, 1995, the Company would be required to
pay approximately $17,000 to terminate the existing interest rate swap
agreement. At September 30, 1996, Titan would be entitled to receive
approximately $3,900.
F2-10
<PAGE> 76
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(4) LONG-TERM DEBT
Long-term debt consists of the following at December 31, 1995 (in
thousands):
<TABLE>
<S> <C>
Note payable to bank secured by substantially all of the Company's
oil and gas properties, due in twenty quarterly payments
commencing January 1, 1998....................................... $20,000
=======
</TABLE>
On December 11, 1995, the Company entered into a credit agreement with
Texas Commerce Bank. The note provides for a two-year revolving line of credit
of $100,000,000 with an initial borrowing base of $35,000,000. The note converts
to a five-year term loan requiring twenty quarterly principal payments beginning
January 1, 1998. The borrowing base is subject to redetermination every six
months with the next redetermination date being September 1, 1996. The note is
secured by substantially all of the Company's oil and gas properties. Commitment
fees are due quarterly and range from .300% to .375% per annum on the difference
between the borrowing base amount and the average daily amount outstanding.
The unpaid principal balance on the note bears interest at the Company's
option based on (i) the higher of (a) the prime rate of Texas Commerce Bank, or
(b) one-half of one percent plus the Federal Funds rate, or (ii) a Eurodollar
rate (based upon a floating rate for a designated maturity of ninety days
adjusted for a Eurodollar margin percentage as defined in the credit agreement).
The interest rate in effect at December 31, 1995 was the Eurodollar rate of
7.0625%. The interest rate in effect at September 30, 1996 was 6.75%.
The credit agreement contains various restrictive covenants and compliance
requirements, which include (1) limiting the incurrence of additional
indebtedness, (2) limiting any mergers or consolidations with any party not
owned or controlled more than 50% by certain limited partners, on a consolidated
basis, and (3) prohibition of any return of capital payments or distributions to
any of its partners other than for taxes due as a result of their partnership
interest.
The Company is a party to an interest rate swap agreement entered into on
December 21, 1995. The effect of this agreement is to provide the Company with a
fixed interest rate of 6.72% on $10,000,000 of its revolving line of credit
through December 23, 1996.
Maturities of long-term debt are as follows (in thousands):
<TABLE>
<S> <C>
1996...................................................... $ --
1997...................................................... --
1998...................................................... 4,000
1999...................................................... 4,000
2000...................................................... 4,000
Thereafter................................................ 8,000
</TABLE>
On July 15, 1996, the Company borrowed an additional $8 million under its
line of credit in order to fund the required escrow payment on a potential
acquisition of certain oil and gas properties. (See Note 12).
F2-11
<PAGE> 77
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(5) ACQUISITION OF OIL AND GAS PROPERTIES
On December 11, 1995, the Company completed the acquisition of certain oil
and gas properties from a large independent oil and gas company (the "1995
Acquisition"). The Company funded the acquisition from the bank credit agreement
described in Note 4. The total consideration paid for the properties was
$39,881,094. The acquisition of these oil and gas properties, accounted for
using the purchase method, resulted in the following noncash investing
activities:
<TABLE>
<S> <C>
Recorded amount of assets acquired, including receivables of
$396,719...................................................... $40,992,065
Liabilities assumed............................................. (1,110,971)
-----------
Cash paid....................................................... $39,881,094
===========
</TABLE>
Included in liabilities assumed is a $963,898 long-term liability recorded
as a purchase price adjustment related to the 1995 Acquisition for a gas
imbalance liability.
Pro Forma Results of Operations (Unaudited)
The following table reflects the pro forma results of operations for the
year ended December 31, 1995 as though the 1995 Acquisition had occurred as of
January 1, 1995 and as if the Conversion had taken place on January 1, 1995. The
pro forma amounts are not necessarily indicative of the results that may be
reported in the future (in thousands).
<TABLE>
<S> <C>
Revenues........................................................... $11,814
Net loss........................................................... (2,736)
Net loss per share................................................. (0.19)
</TABLE>
(6) STATEMENTS OF CASH FLOWS
No interest was paid in 1995. Interest expense of $1,164,399 was paid as of
September 30, 1996.
At December 31, 1995 and September 30, 1996, there were $131,993 and
$618,588, respectively, of property additions accrued in accounts payable.
At September 30, 1996, a $1,300,000 noncash capital contribution was made
in exchange for certain interests in oil and gas properties.
(7) DERIVATIVE FINANCIAL INSTRUMENTS
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. They are used to manage
well-defined interest rate and commodity price risks. The Company is exposed to
credit losses in the event of nonperformance by the counterparties to its
interest rate swap agreements and its commodity hedges. The Company anticipates,
however, that such counterparties will be able to fully satisfy their
obligations under the contracts. The Company does not obtain collateral or other
security to support financial instruments subject to credit risk but monitors
the credit standing of the counterparties.
F2-12
<PAGE> 78
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(7) DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED)
Commodity Hedges
The Company utilizes various swap contracts to hedge the effect of price
changes on future oil and gas production. The following table sets forth the
future volumes hedged by year and the weighted average price to be received
based upon the fixed price of the individual swap contracts at December 31,
1995:
<TABLE>
<CAPTION>
GAS OIL
VOLUME VOLUME PRICE PER
YEAR (MMBTUS) (BBLS) MMBTU/BBL
---- --------- ------- ---------
<S> <C> <C> <C>
Gas production:
1996.......................................... 2,640,000 -- $ 1.70
Oil production:
1996.......................................... -- 300,000 $ 17.18
</TABLE>
Under two separate natural gas swap agreements with a limited partner and
an affiliate of a limited partner, the Company receives the fixed price set
forth above. The Company pays a floating price determined as the NYMEX price,
reduced by 53% of the difference between the NYMEX price and the fixed price
received.
The Company relies upon the correlation that generally exists between the
NYMEX gas futures price and the cash prices realizable to effectively hedge its
production. However, with the lack of recent correlation between the NYMEX gas
futures price and the cash prices realizable in gas markets outside the
Northeastern United States, the Company recognized in December 1995 an
approximate $147,000 loss related to an uncorrelated position for early 1996 gas
production.
In April 1996, the Company entered into a natural gas swap agreement that
hedges a portion of the basis differential between the NYMEX price paid under
the contracts described above and actual cash prices received at local delivery
points. Under this contract covering 1,760,000 MMBtus of natural gas, the
Company pays a price equal to a Permian Basin index price and receives a price
based on the NYMEX price minus $.325 per MMBtu.
Interest Rate Swap Agreements
These instruments are used to reduce the potential impact of increases in
interest rates on floating-rate long-term debt. At December 31, 1995 and
September 30, 1996, the Company was a party to one interest rate swap agreement.
(See Note 4).
(8) RELATED PARTY TRANSACTIONS
During 1995, the Company received $241,563 for administrative services from
a related party. For the nine months ended September 30, 1996, revenue received
was $139,789.
Financial advisory service fees of $428,958 were paid to two shareholders
and two affiliates of shareholders during 1995. For the nine months ended
September 30, 1996, $146,250 of advisory service fees were paid to two
shareholders.
Director's fees of $20,833 and $7,500 were paid during 1995 and for the
nine months ended September 30, 1996, respectively.
The Company has recorded in other assets approximately $425,000 of
organization costs which were paid to related parties for consulting and
advisory fees. These costs are being amortized over a period of five years.
F2-13
<PAGE> 79
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(8) RELATED PARTY TRANSACTIONS (CONTINUED)
The Company has entered into natural gas swap agreements with certain
related parties. (See Note 7).
Certain properties that were owned or controlled by certain shareholders
were acquired by the Company for $1,142,000, which approximates the predecessor
cost of the properties.
The Company entered into a three-year noncancellable operating lease with
an entity controlled by an officer of the General Partner for office facilities
on January 1, 1996.
Future minimum lease commitments under the lease at December 31, 1995 are
as follows:
<TABLE>
<S> <C>
1996...................................................... $110,625
1997...................................................... 110,625
1998...................................................... 110,625
</TABLE>
Lease expense paid through September 30, 1996 was $82,969.
The Company is a party to two financial advisory service contracts with a
shareholder and an affiliate of a shareholder. These contracts require
consolidated annual payments of $185,000 per year to be paid by the Company
until any one of the following events occur:
(i) the date of dissolution of the Company;
(ii) the first date on which the respective shareholder no longer owns
at least 35% of the outstanding shares of common stock of the Company;
(iii) the first date on which the Company or its successors complete
an equity offering to the public, or
(iv) written notice by the respective party of their election to
terminate the contracts with the Company.
The Company regularly uses certain aircraft owned by an affiliate. The
Company is billed for any use of such aircraft by Company personnel. Payments
made for the use of such aircraft were $4,140 for the period March 31, 1995
(date of inception) through December 31, 1995 and $10,859 for the nine months
ended September 30, 1996.
The President, Chief Executive Officer and Chairman of the Board of the
Company, and certain of his affiliates have a common ownership interest in an
oil and gas property that is operated by the Company and, in accordance with a
standard industry operating agreement, make payments to the Company of leasehold
costs and lease operating and supervision charges. These payments were
approximately $12,000 for the period March 31, 1995 (date of inception) through
December 31, 1995 and $284,000 for the nine months ended September 30, 1996.
(9) COMPANY OPTION PLANS
During 1995, the Titan Resources, L.P. established a unit option plan (the
"Plan") for certain officers and key employees of the Partnership and the
General Partner. The Plan provided for the issuance of 5,460,000 options in four
separate series with an initial exercise price of $1 which was to be increased
10% per annum from the initial plan adoption date of March 31, 1995. Option A
series, covering 3,624,706 units, was to vest at a rate of one-third of the
options at each of the dates of March 31, 1996, 1997 and 1998. Option B, C, and
D series were to vest on the dates that the Board determines that the current
value of partnership units had increased by a factor of 3, 4, and 5,
respectively or on the date that such per unit amounts of cash or other
F2-14
<PAGE> 80
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(9) COMPANY OPTION PLANS (CONTINUED)
assets have been or are authorized to be distributed to the Partners. Option B,
C, and D series cover 582,282, 611,037, and 641,975 units, respectively. As of
December 31, 1995, 5,093,616 unit options had been awarded and none were vested
or exercised.
Based on the price of equity interests sold at December 11, 1995, the
Company recorded deferred compensation for the expected value of the options,
amortized over the period from March 31, 1995 through March 31, 1998.
On September 30, 1996, upon the consolidation of Titan Resources, L.P., the
Plan was replaced by a new stock option plan the ("Stock Plan"). The Stock Plan
provides for the issuance of 3,631,350 options to acquire common stock of the
Company, in four separate series with a fixed exercise price of $2.08. Option A
series, covering 2,410,728 shares of common stock, was to vest at a rate of
one-third of the options at each of the dates of March 31, 1996, 1997 and 1998.
Option B, C, and D series cover 387,265, 406,390, and 426,967 shares of common
stock, respectively and vest over a period through March 31, 1999. Deferred
compensation was recorded based on the value of the Company's common stock on
September 30, 1996, and will be amortized to expense over a 39 month period.
Deferred compensation of approximately $17,576,000 (before reduction by amounts
previously amortized to expense under the Plan, as described above) was recorded
at September 30, 1996.
(10) 401(K) PLAN
The Company has established a qualified cash or deferred arrangement under
IRS code section 401(k) covering substantially all employees. Under the plan,
the employees have an option to make elective contributions of a portion of
their eligible compensation, not to exceed specified annual limitations, to the
plan and the Company has an option to match a portion of the employee's
contribution. The Company has made matching contributions to the plan totaling
$8,199 in 1995 and $16,604 for the nine months ended September 30, 1996.
(11) MAJOR CUSTOMERS
The following purchasers accounted for 10% or more of the Company's oil and
gas sales for the period March 31, 1995 (date of inception) through December 31,
1995 and the nine months ended September 30, 1996.
<TABLE>
<CAPTION>
1995 1996
----- ------
<S> <C> <C>
Purchaser A................................................ -- 52.50%
</TABLE>
(12) SUBSEQUENT EVENTS
On October 31, 1996, the Company acquired from a major integrated company
(the "1996 Acquisition") certain oil and gas properties for approximately $135.5
million. The properties are located primarily in west Texas and southeastern New
Mexico. The transaction will be accounted for using the purchase method.
F2-15
<PAGE> 81
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(12) SUBSEQUENT EVENTS (CONTINUED)
Pro Forma Results of Operations (Unaudited)
The following table reflects the pro forma results of operations for the
nine months ended September 30, 1995 and 1996, as though the 1996 Acquisition
had occurred as of January 1, 1995. The pro forma amounts are not necessarily
indicative of the results that may be reported in the future (in thousands).
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------
1995 1996
------- -------
<S> <C> <C>
Revenues................................. $37,535 $42,554
Net income (loss)........................ (623) 260
Net income (loss) per share.............. (.05) .01
</TABLE>
In connection with the foregoing, the Company entered into a new credit
agreement (the "Credit Agreement") with Chase Securities, Inc., an affiliate of
the Company's current lender, which establishes a four year revolving credit
facility, up to the maximum amount of $250 million, subject to a borrowing base
to be determined semiannually by the lenders based on certain proved oil and gas
reserves and other assets of the Company. Proceeds of the credit facility will
be utilized to fund the 1996 Acquisition, development of oil and gas reserves,
and for general corporate requirements.
The initial borrowing base is $165 million with the next redetermination
date scheduled for April 1, 1997. The credit agreement, which is secured by the
Company's proved oil and gas reserves, is subject to mandatory prepayments. To
the extent that the borrowing base is less than the aggregate principal amount
of all outstanding loans and letters of credit under the Credit Agreement, such
deficiency must be cured by the Company ratably within 180 days, by either
prepaying a portion of the outstanding amounts or pledging additional
collateral.
At the Company's option, borrowings under the Credit Agreement bear
interest at either (i) the "Alternate Base Rate" (i.e. the higher of the agent's
prime commercial lending rate, or the federal funds rate plus 0.5% per annum),
or (ii) the Eurodollar rate plus a margin ranging from 1% to 1.50% per annum,
which margin increases as the level of the Company's aggregate outstanding
borrowings under the Credit Agreement increases.
The loan documents governing the Credit Agreement contain certain covenants
and restrictions that are customary in the oil and gas industry relating to the
Company's operations.
F2-16
<PAGE> 82
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(13) OIL AND GAS EXPENDITURES
The following table reflects costs incurred in oil and gas property
acquisition, exploration and development activities:
<TABLE>
<CAPTION>
PERIOD
MARCH 31, 1995
(DATE OF INCEPTION) NINE MONTHS
THROUGH ENDED
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------------- -------------
(IN THOUSANDS)
<S> <C> <C>
(UNAUDITED)
Property acquisition costs:
Proved............................................... $40,873 $11,837
Unproved............................................. 1,040 300
Exploration............................................ 448 107
Development............................................ 1,580 7,358
------- -------
$43,941 $19,602
======= =======
</TABLE>
(14) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The estimates of proved oil and gas reserves, which are located principally
in the United States, were prepared by the Company as of December 31, 1995, and
Williamson Petroleum Consultants as of September 30, 1996. Reserves were
estimated in accordance with guidelines established by the SEC and FASB which
require that reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations except by
contractual arrangements. The Company has presented the reserve estimates
utilizing an oil price of $16.78 per Bbl and a gas price of $1.20 per Mcf as of
December 31, 1995 and an oil price of $23.36 per Bbl and a gas price of $1.32
per Mcf as of September 30, 1996.
Oil and Gas Producing Activities
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
F2-17
<PAGE> 83
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(14) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
OIL AND
CONDENSATE NATURAL GAS
(MBBLS) (MMCF)
---------- -----------
<S> <C> <C>
Total Proved Reserves:
Balance, January 1, 1995............................................. -- --
Extensions and discoveries......................................... 108 33,724
Production......................................................... (30) (245)
Purchases of minerals-in-place..................................... 6,068 101,516
----- -------
Balance, December 31, 1995........................................... 6,146 134,995
Extensions and discoveries......................................... 180 45,931
Purchases of minerals-in-place..................................... 704 264
Revision of previous estimates..................................... (79) 1,100
Production......................................................... (388) (2,725)
----- -------
Balance, September 30, 1996.......................................... 6,563 179,565
===== =======
Proved Developed Reserves:
January 1, 1995.................................................... -- --
December 31, 1995.................................................. 5,945 45,470
September 30, 1996................................................. 6,252 54,119
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas
Reserves
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on period-end costs) to be incurred in developing and producing the
proved reserves, less estimated future income tax expenses (based on period-end
statutory tax rates, with consideration of future tax rates already legislated)
to be incurred on pretax net cash flows less tax basis of the properties and
available credits, and assuming continuation of existing economic conditions.
The estimated future net cash flows are then discounted using a rate of 10% per
year to reflect the estimated timing of the future cash flows.
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
(IN THOUSANDS)
<S> <C> <C>
Future:
Cash inflows............................................. $270,965 391,187
Production and development costs......................... (95,490) (128,223)
Future income taxes...................................... (45,754) (72,502)
-------- ---------
Net cash flows................................... 129,721 190,462
10% annual discount for estimated timing of cash flows... (63,369) (85,784)
-------- ---------
Standardized measure of discounted net cash flows........ $ 66,352 104,678
======== =========
</TABLE>
F2-18
<PAGE> 84
TITAN EXPLORATION, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(THE INFORMATION AND AMOUNTS FOR INTERIM PERIODS ARE UNAUDITED)
(14) SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (CONTINUED)
Changes in Standardized Measure of Discounted Future Net Cash Flows From Proved
Reserves
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
(IN THOUSANDS)
<S> <C> <C>
Standardized measure, beginning of period.......................... $ -- $ 66,352
Extensions and discoveries and improved recovery, net of future
production and development costs.............................. 18,087 31,920
Accretion of discount............................................ -- 4,963
Net change in sales prices, net of production costs.............. -- 15,992
Net change in income taxes....................................... (23,401) (16,453)
Change in estimated future development costs..................... -- 658
Purchase of minerals-in-place.................................... 71,561 4,928
Revision of quantity estimates................................... -- 445
Sales, net of production costs................................... (439) (5,898)
Other............................................................ 544 1,771
-------- ---------
Standardized measure, end of period................................ $ 66,352 $ 104,678
======== =========
</TABLE>
F2-19
<PAGE> 85
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Titan Exploration, Inc.:
We have audited the accompanying statements of revenues and direct
operating expenses of the oil and gas properties acquired (1995 Acquisition) by
Titan Exploration, Inc. for the years ended December 31, 1993 and 1994 and the
period ended December 11, 1995. These statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
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 statements of revenues and direct
operating expenses 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 statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
The accompanying statements of revenues and direct operating expenses were
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in Form S-1 of Titan
Exploration, Inc. as described in Note 1) and are not intended to be a complete
presentation of the 1995 Acquisition revenues and expenses.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of the 1995 Acquisition for the years ended December
31, 1993 and 1994 and the period ended December 11, 1995 in conformity with
generally accepted accounting principles.
KPMG PEAT MARWICK LLP
Houston, Texas
September 23, 1996
F3-1
<PAGE> 86
TITAN EXPLORATION, INC.
1995 ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED PERIOD ENDED
DECEMBER 31, DECEMBER 11,
------------------ ------------
1993 1994 1995
------- ------- ------------
<S> <C> <C> <C>
Revenues:
Oil and condensate......................................... $ 8,847 $ 7,590 $ 7,130
Natural gas................................................ 6,441 5,229 3,699
------- ------- --------
15,288 12,819 10,829
Direct operating expenses:
Lease operating............................................ 3,277 3,436 3,515
Production taxes........................................... 1,223 1,271 1,104
------- ------- --------
4,500 4,707 4,619
------- ------- --------
Revenues in excess of direct operating expenses.............. $10,788 $ 8,112 $ 6,210
======= ======= ========
</TABLE>
See accompanying notes to statements of revenues and direct operating expenses.
F3-2
<PAGE> 87
TITAN EXPLORATION, INC.
1995 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) BASIS OF PRESENTATION
On December 11, 1995, Titan Exploration, Inc. (the "Company") acquired from
a large independent oil and gas company certain oil and gas properties (the
"1995 Acquisition") for $39,881,094. The accompanying statements of revenues and
direct operating expenses for the 1995 Acquisition do not include general and
administrative expenses, interest income or expense, a provision for
depreciation, depletion and amortization, or any provision for income taxes
since historical expenses of this nature incurred by Anadarko are not
necessarily indicative of the costs to be incurred by the Company.
Historical financial information reflecting financial position, results of
operations, and cash flows of the 1995 Acquisition, are not presented because
the purchase price was assigned to the oil and gas property interests acquired.
Other assets acquired and liabilities assumed were not material. In addition,
the properties acquired were a part of a much larger enterprise prior to
acquisition by the Company and representative amounts of general and
administrative expenses, depreciation, depletion and amortization, interest and
other indirect costs were not necessarily allocated to the specific properties
acquired, nor would such allocated historical costs be relevant to future
operations of the properties. Development and exploration expenditures related
to these properties have been insignificant in the relevant periods.
Accordingly, the historical statements of revenues and direct operating expenses
of the 1995 Acquisition are presented in lieu of the financial statements
required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.
Revenues in the accompanying statements of revenues and direct operating
expenses are recognized on the sales method. Under this method, revenues are
recognized based on actual volumes of oil and gas sold to purchasers. Direct
operating expenses are recognized on the accrual method.
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Estimated Quantities of Proved Oil and Gas Reserves
Reserve information presented below is based on reserve estimates prepared
by the Company.
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these reserve estimates are
expected to change as additional information becomes available in the future.
F3-3
<PAGE> 88
TITAN EXPLORATION, INC.
1995 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES (CONTINUED)
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
Below are the net estimated quantities of proved reserves and proved
developed reserves for the 1995 Acquisition.
<TABLE>
<CAPTION>
OIL AND NATURAL
CONDENSATE (MBBLS) GAS (MMCF)
------------------ ----------
<S> <C> <C>
Proved reserves at December 31, 1992.................. 7,598 116,693
Revision of previous estimates...................... (869) (226)
Production.......................................... (535) (4,291)
----- -------
Proved reserves at December 31, 1993.................. 6,194 112,176
Revision of previous estimates...................... 470 (1,612)
Production.......................................... (491) (4,002)
----- -------
Proved reserves at December 31, 1994.................. 6,173 106,562
Revision of previous estimates...................... 320 (1,517)
Production.......................................... (425) (3,529)
----- -------
Proved reserves at December 11, 1995.................. 6,068 101,516
===== =======
Proved developed reserves at December 11, 1995........ 5,923 45,707
===== =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas
Reserves
The Company has estimated the standardized measure of discounted future net
cash flows and changes therein relating to proved oil and gas reserves in
accordance with the standards established by the Financial Accounting Standards
Board through its Statement No. 69. The estimates of future cash flows and
future production and development costs are based on period-end sales prices for
oil and gas, estimated future production of proved reserves, and estimated
future production and development costs of proved reserves, based on current
costs and economic conditions. The estimated future net cash flows are then
discounted at a rate of 10%.
Discounted future net cash flow estimates like those shown below are not
intended to represent estimates of the fair market value of oil and gas
properties. Estimates of fair market value should also consider probable
reserves, anticipated future oil and gas prices, interest rates, changes in
development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair market value is
necessarily subjective and imprecise.
F3-4
<PAGE> 89
TITAN EXPLORATION, INC.
1995 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT
OPERATING EXPENSES (CONTINUED)
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
The following are the Company's estimated standardized measure of
discounted future net cash flows from proved reserves attributable to the 1995
Acquisition:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- DECEMBER 11,
1993 1994 1995
-------- -------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future:
Cash inflows................................... $272,478 $202,316 $221,731
Production and development costs............... (87,704) (82,079) (82,753)
-------- -------- --------
Net cash flows......................... 184,774 120,237 138,978
10% annual discount for estimated timing of
cash flows..................................... (98,187) (60,881) (67,837)
-------- -------- --------
Standardized measure of discounted future net
cash flows..................................... $ 86,587 $ 59,356 $ 71,141
======== ======== ========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows From
Proved Reserves
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER
31, PERIOD ENDED
--------------------- DECEMBER 11,
1993 1994 1995
-------- -------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of period........ $ 93,099 $ 86,587 $ 59,356
Accretion of discount............................ 9,309 8,658 5,276
Net change in sales prices, net of production
costs.......................................... (773) (28,377) 12,556
Revision of quantity estimates................... (3,227) 516 215
Sales, net of production costs................... (10,788) (8,112) (6,210)
Other............................................ (1,033) 84 (52)
-------- -------- --------
Standardized measure, end of period.............. $ 86,587 $ 59,356 $ 71,141
======== ======== ========
</TABLE>
F3-5
<PAGE> 90
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Titan Exploration, Inc.:
We have audited the accompanying statements of revenues and direct
operating expenses of the oil and gas properties to be acquired (1996
Acquisition) by Titan Exploration Inc. for the years ended December 31, 1993,
1994 and 1995. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses 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 statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
The accompanying statements of revenues and direct operating expenses were
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in Form S-1 of Titan
Exploration, Inc. as described in Note 1) and are not intended to be a complete
presentation of the 1996 Acquisition revenues and expenses.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of the 1996 Acquisition for the years ended December
31, 1993, 1994 and 1995 in conformity with generally accepted accounting
principles.
KPMG PEAT MARWICK LLP
Dallas, Texas
September 25, 1996
F4-1
<PAGE> 91
TITAN EXPLORATION, INC.
1996 ACQUISITION
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEARS ENDED NINE MONTHS ENDED
DECEMBER 31, SEPTEMBER 30,
------------------------------- -------------------
1993 1994 1995 1995 1996
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and condensate..................... $25,627 $22,708 $20,891 $15,878 $15,991
Natural gas............................ 22,670 18,522 16,886 12,915 16,186
------- ------- ------- ------- -------
48,297 41,230 37,777 28,793 32,177
Direct operating expenses:
Lease operating........................ 13,151 11,428 10,538 8,290 7,842
Production taxes....................... 3,045 2,436 1,974 1,512 1,639
------- ------- ------- ------- -------
16,196 13,864 12,512 9,802 9,481
------- ------- ------- ------- -------
Revenues in excess of direct operating
expenses............................... $32,101 $27,366 $25,265 $18,991 $22,696
======= ======= ======= ======= =======
</TABLE>
See accompanying notes to statements of revenues and direct operating expenses.
F4-2
<PAGE> 92
TITAN EXPLORATION, INC.
1996 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) BASIS OF PRESENTATION
On October 31, 1996, Titan Exploration, Inc. (the "Company") acquired from
a major integrated company certain oil and gas properties located in the Permian
Basin (the "1996 Acquisition") for $135,524,139. The accompanying statements of
revenues and direct operating expenses for the 1996 Acquisition do not include
general and administrative expenses, interest income or expense, a provision for
depreciation, depletion and amortization, or any provision for income taxes
since historical expenses of this nature incurred by Mobil are not necessarily
indicative of the costs to be incurred by the Company.
Historical financial information reflecting financial position, results of
operations, and cash flows of the 1996 Acquisition, are not presented because
the purchase price will be assigned to the oil and gas property interests
acquired. Other assets acquired and liabilities assumed were not material. In
addition, the properties acquired were a part of a much larger enterprise prior
to acquisition by the Company and representative amounts of general and
administrative expenses, depreciation, depletion and amortization, interest and
other indirect costs were not necessarily allocated to the specific properties
acquired, nor would such allocated historical costs be relevant to future
operations of the properties. Development and exploration expenditures related
to these properties have been insignificant in the relevant periods.
Accordingly, the historical statements of revenues and direct operating expenses
of the 1996 Acquisition are presented in lieu of the financial statements
required under Rule 3-05 of Securities and Exchange Commission Regulation S-X.
Revenues in the accompanying statements of revenues and direct operating
expenses are recognized on the sales method. Under this method, revenues are
recognized based on actual volumes of oil and gas sold to purchasers. Direct
operating expenses are recognized on the accrual basis.
The financial information for the nine months ended September 30, 1995 and
1996, is unaudited. However, in the opinion of management, the statements of
revenues and direct operating expenses for the nine months ended September 30,
1995 and 1996 include all the necessary adjustments to fairly present the
results of these periods.
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Estimated Quantities of Proved Oil and Gas Reserves
Reserve information presented below is based on reserve estimates prepared
by the Company.
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected to
be recovered through existing wells with existing equipment and operating
methods. Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these reserve estimates are
expected to change as additional information becomes available in the future.
F4-3
<PAGE> 93
TITAN EXPLORATION, INC.
1996 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (CONTINUED)
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
Below are the net estimated quantities of proved reserves and proved
developed reserves for the 1996 Acquisition.
<TABLE>
<CAPTION>
OIL AND NATURAL
CONDENSATE (MBBLS) GAS (MMCF)
------------------ ----------
<S> <C> <C>
Proved reserves at December 31, 1992.................... 12,951 132,445
Revision of previous estimates........................ 76 10,901
Production............................................ (1,857) (12,650)
------- -------
Proved reserves at December 31, 1993.................... 11,170 130,696
Revision of previous estimates........................ 1,284 421
Production............................................ (1,804) (12,124)
------- -------
Proved reserves at December 31, 1994.................... 10,650 118,993
Revision of previous estimates........................ 1,213 2,228
Production............................................ (1,549) (14,177)
------- -------
Proved reserves at December 31, 1995.................... 10,314 107,044
Revision of previous estimates........................ 1,889 3,725
Production............................................ (923) (9,510)
------- -------
Proved reserves at September 30, 1996................... 11,280 101,259
======= =======
Proved developed reserves at December 31, 1995.......... 8,314 99,553
======= =======
Proved developed reserves at September 30, 1996......... 9,281 94,358
======= =======
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows of Proved Oil and Gas
Reserves
The Company has estimated the standardized measure of discounted future net
cash flows and changes therein relating to proved oil and gas reserves in
accordance with the standards established by the Financial Accounting Standards
Board through its Statement No. 69. The estimates of future cash flows and
future production and development costs are based on period-end sales prices for
oil and gas, estimated future production of proved reserves, and estimated
future production and development costs of proved reserves, based on current
costs and economic conditions. The estimated future net cash flows are then
discounted at a rate of 10%.
Discounted future net cash flow estimates like those shown below are not
intended to represent estimates of the fair market value of oil and gas
properties. Estimates of fair market value should also consider probable
reserves, anticipated future oil and gas prices, interest rates, changes in
development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair market value is
necessarily subjective and imprecise.
F4-4
<PAGE> 94
TITAN EXPLORATION, INC.
1996 ACQUISITION
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES (CONTINUED)
(2) SUPPLEMENTARY FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
The following are the Company's estimated standardized measure of
discounted future net cash flows from proved reserves attributable to the 1996
Acquisition:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
--------- --------- --------- -------------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Future:
Cash inflows....................... $ 396,798 $ 393,721 $ 383,701 $ 416,844
Production and development costs... (172,110) (160,629) (166,517) (174,736)
--------- --------- --------- ---------
Net cash flows............. 224,688 233,092 217,184 242,108
10% annual discount for estimated
timing of cash flows............ (91,315) (105,759) (89,886) (94,559)
--------- --------- --------- ---------
Standardized measure of discounted
future net cash flows........... $ 133,373 $ 127,333 $ 127,298 $ 147,549
========= ========= ========= =========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows From
Proved Reserves
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, PERIOD ENDED
----------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
--------- --------- --------- -------------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Standardized measure, beginning of
period............................. $ 163,590 $ 133,373 $ 127,333 $ 127,298
Accretion of discount................ 16,359 13,337 12,733 9,521
Net change in sales prices, net of
production costs................... (17,086) 13,823 (1,673) 15,581
Revision of quantity estimates....... 7,821 5,770 7,320 13,404
Sales, net of production costs....... (32,101) (27,366) (25,265) (22,696)
Other................................ (5,210) (11,604) 6,850 4,441
--------- --------- --------- ---------
Standardized measure, end of
period............................. $ 133,373 $ 127,333 $ 127,298 $ 147,549
========= ========= ========= =========
</TABLE>
F4-5
<PAGE> 95
[WILLIAMSON PETROLEUM CONSULTANTS, INC. LETTERHEAD]
November 15, 1996
Titan Exploration, Inc.
500 West Texas, Suite 500
Midland, Texas 79701
Attention Mr. Rodney Woodard
Gentlemen:
Subject: Summary Letter (for Inclusion in a Prospectus Included in a
Registration Statement for Titan Exploration, Inc. on Form S-1)
Combining Specific Data from Two Williamson Petroleum Consultants, Inc.
Evaluations (1) to the Interests of Titan Exploration, Inc. in Titan
Original Properties and Properties Acquired from a Large Independent
Oil Company in 1995, Effective October 1, 1996 (the 1995 Acquisition
Properties) and (2) to the Interests in Properties Acquired from a
Major Integrated Oil and Gas Company (the Integrated Company),
Effective October 1, 1996 (the 1996 Acquisition Properties), for
Disclosure to the Securities and Exchange Commission, Williamson
Project 6.8432
In accordance with your request, Williamson Petroleum Consultants, Inc.
(Williamson) has prepared a summary letter for inclusion in a prospectus for
Titan Exploration, Inc. (Titan). This summary letter includes specific data from
two evaluations the subjects of which are described in Item I. All values and
discussion of proved reserves and net revenues, data utilized, assumptions, and
qualifications are taken from and include by reference data from these two
evaluations.
Interests in this summary letter represent the October 1, 1996 effective
date consolidation of the ownership interests of Titan and the ownership
interests purchased from the Integrated Company in various properties included
in the March 1996 Permian Basin Divestiture Package. The Titan properties
include interests in those properties designated as the Titan original
properties and the 1995 Acquisition Properties purchased by Titan in 1995. Titan
concluded the purchase of the 1996 Acquisition Properties on October 31, 1996.
The evaluation of the 1996 Acquisition Properties with an effective date of
October 1, 1996 and the summation with the Titan properties herein is based on
the October 31, 1996 closing on the 1996 Acquisition Properties.
I. THE TWO SUBJECT EVALUATIONS
This summary letter combines certain proved oil and gas reserves and
revenues from the following two Williamson evaluations:
(1) Evaluation of Oil and Gas Reserves to the Interests of Titan
Exploration, Inc. in Titan Original Properties and 1995 Acquisition
Properties, Effective October 1, 1996, for Disclosure to the Securities and
Exchange Commission, Williamson Project 6.8432 (the Titan report)
(2) Evaluation of Oil and Gas Reserves to the Interests in the 1996
Acquisition Properties, Effective October 1, 1996, for Disclosure to the
Securities and Exchange Commission, Williamson Project 6.8432 (the 1996
Acquisition report)
II. ESTIMATED SEC RESERVES AND FUTURE NET REVENUES
Projections of the reserves that are attributable to the consolidated
interests in this summary letter were based on economic parameters and operating
conditions considered applicable as of October 1, 1996 and are pursuant to the
requirements of the Securities and Exchange Commission (SEC).
A-1
<PAGE> 96
The present values of the estimated future net revenues from proved
reserves were calculated using a discount rate of 10.00 percent per year and
were computed in accordance with the financial reporting requirements of the
SEC. Following is a summary of the results of the two evaluations effective
October 1, 1996:
<TABLE>
<CAPTION>
PROVED PROVED
DEVELOPED DEVELOPED PROVED TOTAL
PRODUCING NONPRODUCING UNDEVELOPED PROVED
----------- ------------ ----------- -----------
<S> <C> <C> <C> <C>
Net Reserves to the Evaluated Interests:
Oil/Condensate, BBL.................... 15,506,378 26,417 2,310,102 17,842,897
Gas, MCF............................... 146,956,923 1,520,000 132,346,148 280,823,071
Future Net Revenue, $:
Undiscounted........................... 320,390,801 3,142,479 181,538,841 505,072,121
Discounted Per Annum at 10.00
Percent............................. 190,304,344 2,404,343 99,371,000 292,079,687
</TABLE>
- ---------------
Note: The values presented in this table are taken from the evaluations
described in Item I and include by reference all data, qualifications, and
assumptions from these evaluations. Realization of these values is
contingent on achieving successful results from the various schedules and
assumptions in these evaluations. The available engineering data and the
completeness and/or quality of data utilized in evaluating the properties
are detailed in the specific evaluation. Review of any additionally
available data may necessitate revision to these interpretations and
assumptions and impact these values.
III. DEFINITIONS OF SEC RESERVES(1)
The estimated reserves presented in this summary letter are net proved
reserves, including proved developed producing, proved developed nonproducing,
and proved undeveloped reserves, and were computed in accordance with the
financial reporting requirements of the SEC. In preparing these evaluations, no
attempt has been made to quantify the element of uncertainty associated with any
category. Reserves were assigned to each category as warranted. The definitions
of oil and gas reserves pursuant to the requirements of the Securities Exchange
Act are:
Proved Reserves(2)
Proved reserves are the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under the economic criteria employed and existing operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices and costs include
consideration of changes provided only by contractual arrangements but not on
escalations based upon an estimate of future conditions.
A. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes:
1. that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
2. the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
B. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project,
- ---------------
(1) For evaluations prepared for disclosure to the Securities and Exchange
Commission, see SEC Accounting Rules. Commerce Clearing House, Inc. October
1981, Paragraph 290, Regulation 210.4-10, p. 329.
(2) Any variations to these definitions will be clearly stated in the report.
A-2
<PAGE> 97
or the operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
C. Estimates of proved reserves do not include the following:
1. oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
2. crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors;
3. crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
4. crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal(3), gilsonite, and other such sources.
Proved Developed Reserves(4)
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
Proved Undeveloped Reserves
Proved undeveloped reserves are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the exiting productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
IV. DISCUSSION OF SEC RESERVES
A. The Titan Report
A total of 113 properties in 44 fields were evaluated in the Titan report.
These properties are located in the states of New Mexico and Texas with the
majority of value in Texas. Overall net reserves are 6,562,947 barrels of oil
(BO) and 179,564,506 thousand cubic feet of gas (MCF) or 36,490,365 barrels of
oil equivalent (BOE) at a conversion rate of six MCF of gas to one BO.
Associated future net revenue discounted at 10.00 percent per annum (DFNR) is
$144,531,504. Five fields in Texas represent a combined DFNR of $101,371,218 or
approximately 70.14 percent of the total Titan DFNR. These five fields are, in
descending order of DFNR, Puckett field, Pecos County, Texas; Foster field,
Ector County, Texas; Barstow field, Ward County, Texas; Gomez field, Pecos
County, Texas; and Evetts field, Loving and Winkler Counties, Texas. These
fields include 18 properties in the proved developed category and ten properties
in the proved
- ---------------
(3) According to Staff Accounting Bulletin 85, excluding certain coalbed methane
gas.
(4) Williamson Petroleum Consultants, Inc. separates proved developed reserves
into proved developed producing and proved developed nonproducing reserves.
This is to identify proved developed producing reserves as those to be
recovered from actively producing wells; proved developed nonproducing
reserves as those to be recovered from wells or intervals within wells,
which are completed but shut in waiting on equipment or pipeline
connections, or wells where a relatively minor expenditure is required for
recompletion to another zone.
A-3
<PAGE> 98
undeveloped category. The proved developed properties contribute $41,128,552
DFNR while the proved undeveloped properties in these five fields contribute
$60,242,666 DFNR. A more detailed property review is included in the Titan
report.
Prices for oil were based on data available as of September 26, 1996 and
were used as effective date prices. Prices were based on posted prices as of
September 26, 1996 and associated premiums being paid by the pipeline purchaser
or trucking purchaser for West Texas intermediate or West Texas sour crude oil.
Information pertaining to postings, premiums, purchaser, and quality of crude
oil were provided by Titan. When not provided, Williamson estimated oil prices
by analogy to similar properties. After the effective date, prices were held
constant for the life of the properties. The overall average oil price for all
properties was $23.36 per BO. No attempt has been made to account for oil price
fluctuations which have occurred in the market subsequent to the effective date
of the report.
The 1995 Acquisition Properties are subject to a hedging contract. This
hedging contract results in a penalty on oil sales through December 31, 1996.
Titan estimated the amount of these penalties and provided Williamson the
projected amount of dollars lost during October, November, and December 1996.
These negative dollars were included on a "Cost Tract" and deducted from the
total future net revenue.
Gas prices based on September 1996 prices or indexes were provided by Titan
and were used as effective date prices. After the effective date, prices were
held constant for the life of the properties. All gas prices were applied to
projected wellhead volumes. To account for known differences between sales and
produced volumes, any given residue gas sales price was adjusted by a factor in
order to make the price applicable to the wellhead stream. Similar adjustments
were made to account for any known lease use. Gas prices were also adjusted for
any known income from plant products not projected separately. When not
provided, Williamson estimated gas prices by analogy to similar properties. The
overall average gas price for all properties was $1.324 per MCF.
State production taxes have been deducted at the published rates as
appropriate. Ad valorem taxes were deducted based on information provided by
Titan or on published rates.
B. The 1996 Acquisition Report
A total of 142 properties in 54 fields were evaluated in the 1996
Acquisition report. These properties are located in the states of New Mexico and
Texas with the majority of value in Texas. Overall net reserves are 11,279,950
BO and 101,258,565 MCF of gas or 28,156,378 BOE. Associated DFNR is
$147,548,183. Five fields/areas in Texas and one area in New Mexico have a
combined DFNR of $97,551,043 or approximately 66.11 percent of the total
Integrated Company DFNR. These fields/areas are, in descending order of DFNR:
East Dollarhide field, Andrews County, Texas; Mi Vida field, Ward and Reeves
Counties, Texas; North Robertson field, Gaines County, Texas; Eunice field area,
Lea County, New Mexico; University Waddell field, Crane County, Texas; and
Headlee (Devonian) field, Ector County, Texas. These fields/areas include 34
properties in the proved developed producing category and 10 properties
classified as proved undeveloped. The proved developed producing category
contributes $78,479,044 DFNR while the proved undeveloped properties contribute
$19,071,999 DFNR. A more detailed property review is included in the 1996
Acquisition report.
Oil prices were provided by Titan and were used as effective date prices.
These were reported to be the Integrated Company's posted prices received by the
Integrated Company on September 26, 1996 for all properties they operate or in
which they retain a nonoperating working interest. These prices were used for
October and November 1996. Starting December 1, 1996, oil prices were set at the
Enron Oil Trading and Transportation Energy Operating Limited Partnership (EOTT)
postings as of September 26, 1996 plus premiums in accordance with a contract
for EOTT to purchase oil from Titan on the 1996 Acquisition Properties starting
December 1, 1996. On properties not covered by EOTT, the price at December 1,
1996 was set at prices consistent with September postings plus premiums for
trucked oil. When not provided, Williamson estimated oil prices by analogy to
similar properties. After December 1, 1996, prices were held constant for the
life of the properties. The overall average oil price for all properties was
$23.37 per BO. No
A-4
<PAGE> 99
attempt has been made to account for oil price fluctuations which have occurred
in the market subsequent to the effective date of the report.
Gas prices based on September 1996 prices or indexes were provided by Titan
and were used as effective date prices. After the effective date, prices were
held constant for the life of the properties. All gas prices were applied to
projected wellhead volumes. To account for known differences between sales and
produced volumes, any given residue gas sales price was adjusted by a factor in
order to make the price applicable to the wellhead stream. Similar adjustments
were made to account for any known lease use. Gas prices were also adjusted for
any known income from plant products not projected separately. When not
provided, Williamson estimated gas prices by analogy to similar properties. The
overall average gas price for all properties was $1.513 per MCF.
State production taxes have been deducted at the published rates as
appropriate. Ad valorem taxes were deducted based on information provided by
Titan or on published rates for all operated properties. On properties not
operated by the Integrated Company, ad valorem taxes were provided by Titan or,
if not provided, were assumed to be included in the operating costs.
V. GENERAL EVALUATION CONSIDERATIONS PERTAINING TO THE TITAN AND 1996
ACQUISITION REPORTS
The individual projections prepared to produce this summary letter include
data that describe the production forecasts and associated evaluation parameters
such as interests, taxes, product prices, operating costs, investments, salvage
values, abandonment costs, and net profit interests, as applicable.
Net income to the evaluated interests is the future net revenue after
consideration of royalty revenue payable to others, taxes, operating expenses,
investments, salvage values, abandonment costs, and net profit interests, as
applicable. The future net revenue is before federal income tax and excludes
consideration of any encumbrances against the properties if such exist.
No opinion is expressed by Williamson as to the fair market value of the
evaluated properties.
The future net revenue values presented in this summary letter were based
on projections of oil and gas production. It was assumed there would be no
significant delay between the date of oil and gas production and the receipt of
the associated revenue for this production.
This summary letter includes only those costs and revenues which are
considered by Titan to be directly attributable to individual leases and areas.
There could exist other revenues, overhead costs, or other costs associated with
Titan or the Integrated Company which are not included in this summary letter.
Such additional costs and revenues are outside the scope of this summary letter.
This summary letter is not a financial statement for Titan and should not be
used as the sole basis for any transaction concerning Titan, the Integrated
Company, or the evaluated properties.
The reserves projections in this summary letter are based on the use of the
available data and accepted industry engineering methods. Future changes in any
operational or economic parameters or production characteristics of the
evaluated properties could increase or decrease their reserves. Unforeseen
changes in market demand or allowables set by various regulatory agencies could
also cause actual production rates to vary from those projected. The dates of
first production for nonproducing properties were based on estimates by Titan or
Williamson and the actual dates may vary from those estimated. Williamson
reserves the right to alter any of the reserves projections and the associated
economics included in this summary letter in any future evaluations based on
additional data that may be acquired.
All data utilized in the preparation of this summary letter with respect to
interests, reversionary status, oil and gas prices, gas categories, gas contract
terms, operating expenses, investments, salvage values, abandonment costs, net
profit interests, well information, and current operating conditions, as
applicable, were provided by Titan and the operators. Production data from
public records were used where available. If public records were not available,
production data provided by Titan and various other operators were utilized.
Production data generally through February or June 1996 were obtained for the
properties in the Titan report and through January or June 1996 for the
properties in the 1996 Acquisition report. Additional production
A-5
<PAGE> 100
data for the months of July or August were provided by Titan or the operators on
various properties. All data have been reviewed for reasonableness and, unless
obvious errors were detected, have been accepted as correct. It should be
emphasized that revisions to the projections of reserves and economics included
in this summary letter may be required if the provided data are revised for any
reason. No inspection of the properties was made as this was not considered
within the scope of these projects. No investigation was made of any
environmental liabilities that might apply to the evaluated properties, and no
costs are included for any possible related expenses.
Operating expenses were provided by Titan and represented, when possible,
the latest available 12- to 18-month average of all recurring expenses which are
billable to the working interest owners. These expenses included, but were not
limited to, all direct operating expenses, field overhead costs, and any ad
valorem taxes not deducted separately. Expenses for workovers, well
stimulations, and other maintenance were not included in the operating expenses
unless such work was expected on a recurring basis. Judgments for the exclusion
of the nonrecurring expenses were made by Titan. The economic limit for each
property was determined using these costs. Any internal indirect overhead costs
(general and administrative) which are billable to the working interest owners
were included, while those not billable were not included. For new and
developing properties where data were unavailable, operating expenses were
estimated by Titan or Williamson based on analogy with similar properties.
Operating costs were held constant for the life of the properties.
Unless specifically identified and documented by Titan as having
curtailment problems, gas production trends have been assumed to be a function
of well productivity and not of market conditions. The effect of "take or pay"
clauses in gas contracts was not considered.
Oil reserves are expressed in United States (U.S.) barrels of 42 U.S.
gallons. Gas volumes are expressed in MCF's at 60 degrees Fahrenheit and at the
legal pressure base that prevails in the state in which the reserves are
located. No adjustment of the individual gas volumes to a common pressure base
has been made.
Titan represented to Williamson that it has, or can generate, the financial
and operational capabilities to accomplish those projects evaluated by
Williamson which require capital expenditures.
All capital costs for drilling and completion of wells and nonrecurring
workover or operating costs have been deducted as applicable. These costs were
provided by Titan or, where not supplied, were estimated by Williamson. No
adjustments were made to account for the potential effect of inflation on these
costs.
Neither salvage values nor abandonment costs were provided by Titan to be
included in this evaluation.
The estimates of reserves contained in this summary letter were determined
by accepted industry methods and in accordance with the definitions of oil and
gas reserves set forth above. Methods utilized in this summary letter include
extrapolation of historical production trends, material balance determinations,
analogy to similar properties, and volumetric calculations.
Where sufficient production history and other data were available, reserves
for producing properties were determined by extrapolation of historical
production trends or through the use of material balance determinations. Analogy
to similar properties or volumetric calculations were used for nonproducing
properties and those producing properties which lacked sufficient production
history and other data to yield a definitive estimate of reserves. Reserves
projections based on analogy are subject to change due to subsequent changes in
the analogous properties or subsequent production from the evaluated properties.
Volumetric calculations are often based upon limited log and/or core analysis
data and incomplete reservoir fluid and formation rock data. Since these limited
data must frequently be extrapolated over an assumed drainage area, subsequent
production performance trends or material balance calculations may cause the
need for significant revisions to the estimates of reserves.
It should be emphasized that with the current economic uncertainties,
fluctuation in market conditions could significantly change the economics in
this summary letter.
A-6
<PAGE> 101
VII. DECLARATION OF INDEPENDENT STATUS AND CONSENT
We understand that our estimates are to be included in a Registration
Statement on Form S-1 (the Registration Statement) to be filed by you with the
SEC and in the Prospectus for Titan as included in such Registration Statement
which will be registered under the Securities Act of 1933, as amended.
Williamson is an independent consulting firm and does not own any interests
in the oil and gas properties covered by this summary letter. No employee,
officer, or director of Williamson is an employee, officer, or director of
Titan. Neither the employment of nor the compensation received by Williamson is
contingent upon the values assigned to the oil and gas properties covered by
this summary letter.
We consent to the inclusion of this summary letter in the Registration
Statement, the inclusion in the Registration Statement of data extracted from
this summary letter, and to all references to our firm in the Prospectus,
including any references to our firm as Experts.
Yours very truly,
WILLIAMSON PETROLEUM CONSULTANTS, INC.
A-7
<PAGE> 102
================================================================================
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY, THE SELLING STOCKHOLDER OR ANY
UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY
JURISDICTION TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION.
NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER
ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT
AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN
THE AFFAIRS OF THE COMPANY SINCE SUCH DATE.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 8
The Company........................... 14
Use of Proceeds....................... 14
Dividend Policy....................... 14
Dilution.............................. 15
Capitalization........................ 16
Selected Consolidated Financial
Data................................ 17
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 19
Business and Properties............... 25
Management............................ 36
Certain Transactions.................. 43
Principal and Selling Stockholders.... 45
Description of Capital Stock.......... 47
Shares Eligible for Future Sale....... 48
Underwriting.......................... 50
Notice to Canadian Residents.......... 52
Legal Matters......................... 52
Experts............................... 52
Additional Information................ 53
Glossary of Oil and Gas Terms......... 54
Index to Consolidated Financial
Statements.......................... F-1
Letter of Williamson Petroleum
Consultants, Inc.................... A-1
</TABLE>
---------------------
UNTIL JANUARY 10, 1997 (25 DAYS AFTER THE COMMENCEMENT OF THIS OFFERING),
ALL DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED SECURITIES, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.
================================================================================
================================================================================
Titan Exploration, Inc.
12,610,000 Shares
Common Stock
($.01 par value)
PROSPECTUS
Credit Suisse First Boston
Donaldson, Lufkin & Jenrette
Securities Corporation
Howard, Weil, Labouisse, Friedrichs
Incorporated
J.P. Morgan & Co.
Petrie Parkman & Co.
================================================================================
