<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------------------------------
FORM 10-Q
--------------------------------------------
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the quarterly period ended September 30, 1999
or
[_] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _____ to _____
Commission File Number: 000-21843
TITAN EXPLORATION, INC.
(Exact name of Registrant as specified in its charter)
Delaware 75-2671582
(State or other jurisdiction (I.R.S. Employer
of incorporation or Identification No.)
organization
500 W. Texas, Suite 200 79701
Midland, Texas (Zip Code)
(Address of principal executive offices)
(915) 498-8600
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
---- ----
As of November 1, 1999, 36,730,675 of common stock, par value $.01 per
share of Titan Exploration, Inc. were outstanding.
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<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
<S> <C>
Forward Looking Information and Risk Factors.................................................... 1
PART I -- FINANCIAL INFORMATION
Item 1. Financial Statements
--------------------
Consolidated Balance Sheets as of September 30, 1999 (Unaudited) and
December 31, 1998.................................................................... 2
Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended
September 30, 1999 and 1998.......................................................... 3
Unaudited Consolidated Statements of Cash Flows for the Three and Nine Months Ended
September 30, 1999 and 1998.......................................................... 4
Notes to Consolidated Financial Statements........................................... 5
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 11
-------------------------------------------------------------------------------------
Item 3. Quantitative and Qualitative Disclosures About Market Risk............................. 21
----------------------------------------------------------
PART II -- OTHER INFORMATION
Item 1. Legal Proceedings.................................................................... 23
-----------------
Item 4. Submission of Matters to a Vote of Security Holders.................................. 23
---------------------------------------------------
Item 5. Other Information.................................................................... 23
-----------------
Item 6. Exhibits and Reports on Form 8-K..................................................... 23
--------------------------------
Signatures........................................................................... 24
</TABLE>
<PAGE>
TITAN EXPLORATION, INC.
FORWARD LOOKING INFORMATION AND RISK FACTORS
Titan Exploration, Inc. (the "Company") or its representatives may make
forward looking statements, oral or written, including statements in this
report's Management's Discussion and Analysis of Financial Condition and Results
of Operations, press releases and filings with the Securities and Exchange
Commission, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells the Company anticipates drilling through 1999, potential reserves and
the Company's financial position, business strategy and other plans and
objectives for future operations. Although the Company believes that the
expectations reflected in these forward looking statements are reasonable, there
can be no assurance that the actual results or developments anticipated by the
Company will be realized or, even if substantially realized, that they will have
the expected effects on its business or operations. Among the factors that
could cause actual results to differ materially from the Company's expectations
are general economic conditions, inherent uncertainties in interpreting
engineering data, operating hazards, delays or cancellations of drilling
operations for a variety of reasons, competition, fluctuations in oil and gas
prices, government regulations, Year 2000 compliance issues and other factors
set forth in the Company's Annual Report on Form 10-K. All subsequent oral and
written forward looking statements attributable to the Company or persons acting
on its behalf are expressly qualified in their entirety by these factors. The
Company assumes no obligation to update any of these statements.
1
<PAGE>
Item 1. Financial Statements
TITAN EXPLORATION, INC.
Consolidated Balance Sheets
(in thousands, except share data)
<TABLE>
<CAPTION>
September 30, December 31,
ASSETS 1999 1998
---- ----
(unaudited)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 1,754 $ 610
Accounts receivable:
Oil and gas 9,981 13,497
Other 408 761
Inventories 699 1,276
Assets held for sale 15,128 109,452
Prepaid expenses and other current assets 128 316
--------- --------
Total current assets 28,098 125,912
--------- --------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties 304,880 299,412
Unproved properties 7,894 6,699
Other property and equipment 6,613 6,340
Accumulated depletion, depreciation and amortization (111,878) (98,095)
--------- --------
207,509 214,356
--------- --------
Other assets, net of accumulated amortization of $841 in 1999 and $639 in 1998 311 754
--------- --------
$ 235,918 $341,022
========= ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Trade $ 5,306 $ 14,097
Accrued interest 829 466
Other (Note 6) 8,582 5,652
--------- --------
Total current liabilities 14,717 20,215
--------- --------
Long-term debt 75,000 144,200
Other liabilities (Note 6) 1,184 5,253
Deferred income tax payable - -
Stockholders' equity:
Preferred Stock, $.01 par value, 10,000,000 shares authorized; none issued
and outstanding - -
Common Stock, $.01 par value, 60,000,000 shares authorized; 40,534,675 shares
issued and outstanding at September 30, 1999 and December 31, 1998
405 405
Additional paid-in capital 278,105 278,109
Treasury stock, at cost; 3,054,000 and 2,600,000 shares at September 30, 1999
and December 31, 1998, respectively (22,243) (20,020)
Deferred compensation (1,259) (5,053)
Accumulated deficit (109,991) (82,087)
--------- --------
Total stockholders' equity 145,017 171,354
--------- --------
Commitments and contingencies (Note 3)
$ 235,918 $341,022
========= ========
</TABLE>
See accompanying notes to consolidated financial statements.
2
<PAGE>
TITAN EXPLORATION, INC.
Unaudited Consolidated Statements of Operations
(in thousands, except per share data)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------- --------------------------------------
1999 1998 1999 1998
------------------ ------------------ ------------------ ------------------
<S> <C> <C> <C> <C>
Revenues:
Gas sales $11,032 $ 9,440 $ 28,092 $ 33,820
Oil sales 10,193 7,231 25,354 23,319
------- -------- -------- --------
Total revenues 21,225 16,671 53,446 57,139
------- -------- -------- --------
Expenses:
Oil and gas production 4,408 6,111 14,199 21,288
Production and other taxes 1,656 1,263 4,228 4,355
General and administrative 1,838 2,347 5,884 7,672
Amortization of stock option awards 1,263 1,263 3,790 3,790
Exploration and abandonments 2,668 1,876 8,207 6,077
Depletion, depreciation and amortization
5,043 6,481 14,248 19,456
Impairment of long-lived assets - 5,126 25,900 13,143
------- -------- -------- --------
Total expenses 16,876 24,467 76,456 75,781
------- -------- -------- --------
Operating income (loss) 4,349 (7,796) (23,010) (18,642)
------- -------- -------- --------
Other income (expense):
Interest income 4 24 23 125
Interest expense (1,296) (2,349) (5,876) (6,040)
Equity in net loss of affiliates (45) (108) (182) (349)
Gain (loss) on sale of assets 695 4 667 (7)
Other 707 87 1,036 454
------- -------- -------- --------
Income (loss) before income taxes 4,414 (10,138) (27,342) (24,459)
------- -------- -------- --------
Income tax expense (benefit) 540 (3,706) 562 (8,803)
------- -------- -------- --------
Net income (loss) $ 3,874 $ (6,432) $(27,904) $(15,656)
======= ======== ======== ========
Net income (loss) per share $ .10 $ (.17) $ (.74) $ (.40)
======= ======== ======== ========
Net income (loss) per share - assuming
dilution $ .10 $ (.17) $ (.74) $ (.40)
======= ======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
3
<PAGE>
TITAN EXPLORATION, INC.
Unaudited Consolidated Statements of Cash Flows
(in thousands)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ----------------------
1999 1998 1999 1998
--------- --------- ---------- ----------
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 3,874 $ (6,432) $(27,904) $(15,656)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization 5,043 6,481 14,248 19,456
Impairment of long-lived assets - 5,126 25,900 13,143
Amortization of stock option awards 1,263 1,263 3,790 3,790
Exploration and abandonments 2,296 974 6,877 3,506
Equity in net loss of affiliates 45 108 182 349
Loss (gain) on sale of assets (695) (4) (667) 7
Deferred income taxes - (3,706) - (8,803)
Other items 99 83 239 282
Changes in assets and liabilities:
Accounts receivable (2,816) (79) 3,087 4,044
Prepaid expenses and other current assets
132 282 306 (909)
Other assets 80 (21) 263 (39)
Accounts payable and accrued liabilities (35) 784 (7,099) (6,062)
------- -------- -------- --------
Total adjustments 5,412 11,291 47,126 28,764
------- -------- -------- --------
Net cash provided by operating activities 9,286 4,859 19,222 13,108
------- -------- -------- --------
Cash flows from investing activities:
Redemption of restricted investment - - - 2,331
Investing in oil and gas properties (7,793) (18,698) (19,774) (42,709)
Additions to other property and equipment 73 (163) (151) (3,858)
Capital contribution in equity investments (45) (368) (741) (931)
Proceeds from sale of assets 1,034 1,381 74,155 1,396
------- -------- -------- --------
Net cash provided by (used in) investing
activities (6,731) (17,848) 53,489 (43,771)
------- -------- -------- --------
Cash flows from financing activities:
Proceeds (payments) from revolving debt, net (1,300) 22,300 (69,200) 51,200
Payments of debt - - - (1,350)
Exercise of stock options - 209 - 424
Purchase of treasury stock (1,039) (7,986) (2,223) (18,316)
Other financing activities (34) (576) (144) (810)
------- -------- -------- --------
Net cash provided by (used in) financing
activities (2,373) 13,947 (71,567) 31,148
------- -------- -------- --------
Net increase in cash and cash equivalents
182 958 1,144 485
Cash and cash equivalents, beginning of period 1,572 1,130 610 1,603
------- -------- -------- --------
Cash and cash equivalents, end of period $ 1,754 $ 2,088 $ 1,754 $ 2,088
======= ======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
4
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
September 30, 1999 and 1998
(Unaudited)
(1) Basis of Presentation
---------------------
In the opinion of management, the unaudited consolidated financial
statements of Titan Exploration, Inc. (the "Company") as of September 30, 1999
and for the three and nine months ended September 30, 1999 and 1998 include all
adjustments and accruals, consisting only of normal recurring accrual
adjustments, which are necessary for a fair presentation of the results for the
interim period. These interim results are not necessarily indicative of results
for a full year.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules and
regulations of the Securities and Exchange Commission. These consolidated
financial statements should be read in conjunction with the audited consolidated
financial statements and notes thereto included in the Company's 1998 Form 10-K.
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.
Reclassifications
Certain reclassifications have been made to the 1998 amounts to conform to
the 1999 presentations.
(2) Debt
Line of Credit
In June 1999, the Company entered into an amended and restated credit
agreement (the "Credit Agreement") with Chase Bank of Texas, N.A. (the "Bank"),
which established a revolving credit facility of $250 million subject to a
borrowing base. All amounts outstanding are due and payable in full on January
1, 2001. The borrowing base, which is $175 million at September 30, 1999, is
subject to redetermination annually each April by the lenders based on certain
proved oil and gas reserves and other assets of the Company. At September 30,
1999, the outstanding principal was $75 million and the available capacity was
approximately $100 million.
Unsecured Credit Agreement
In April 1997, the Company entered into a credit agreement, as amended (the
"Unsecured Credit Agreement"), with the Bank which establishes a revolving
credit facility, up to the maximum of $5 million. Individual borrowings may be
made for up to a three week period. The Unsecured Credit Agreement has no
maturity date and is cancellable at anytime by the Bank. The interest of each
loan under the Unsecured Credit Agreement is at a rate determined by agreement
between the Company and the Bank. The rate shall not exceed the maximum
interest rate permitted under applicable law. Interest rates generally are at
the Bank's cost of funds plus 1% per annum. At September 30, 1999, there was no
outstanding principal balance under the Unsecured Credit Agreement.
5
<PAGE>
(3) Commitments and Contingencies
Litigation
The following is a brief description of certain litigation to which the
Company is subject, as a result of assuming the obligations of Offshore Energy
Development Corporation ("OEDC"). Both cases discussed below have reached a
settlement that has received preliminary approval by the court. The amount of
the settlement related to the Company is not material and does not exceed any
existing provision.
OEDC and certain of its officers and directors, as well as Natural Gas
Partners, L.P. ("NGP"), the managing underwriters of OEDC's initial public
offering and an analyst from each of the managing underwriters, have been named
as defendants in a suit styled Eric Baron and Edward C. Allen, On behalf of
Themselves and all Others Similarly Situated, v. David B. Strassner, Douglas H.
Kiesewetter, David R. Albin, Natural Gas Partners, L.P., David Garcia, John J.
Myers, Offshore Energy Development Corporation, Morgan Keegan & Company, Inc.
and Principal Securities Inc., which was filed October 20, 1997, in the Texas
State District Court of Harris County, Texas 270th Judicial District and
subsequently removed to federal court in the United States Southern District of
Texas.
OEDC and certain of its officers and directors, as well as NGP, have also
been named defendants in a suit styled John W. Robertson, et al. v. David B.
Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P.
and Offshore Energy Development Corporation, which was filed February 6, 1998,
in the United States Southern District of Texas, Houston Division.
The Company is involved in other various claims and legal actions arising
in the ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a material adverse effect on the
Company's financial position, results of operations or liquidity.
Letters of Credit
At September 30, 1999, the Company had outstanding letters of credit of
$144,000, which were issued through the Credit Agreement.
6
<PAGE>
(4) Earnings per Common Share
The following table sets forth the computation of basic and diluted
earnings per common share:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ----------------------
1999 1998 1999 1998
-------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
(in thousands, except per share data)
Numerator:
Net income (loss) and numerator for basic and
diluted net income (loss) per common share -
income available to common stockholders $ 3,874 $(6,432) $(27,904) $(15,656)
------- ------- -------- --------
Denominator:
Denominator for basic net income (loss) per common
share - weighted average common shares 37,667 38,252 37,825 39,109
Effect of dilutive securities - employee stock
options 1,856 - - -
-------- --------- --------- ---------
Denominator for diluted net income (loss) per
common share - adjusted weighted average common
shares and assumed conversions 39,523 38,252 37,825 39,109
======= ======= ======== ========
Basic net income (loss) per common share $ .10 $ (.17) $ (.74) $ (.40)
======= ======= ======== ========
Diluted net income (loss) per common share $ .10 $ (.17) $ (.74) $ (.40)
======= ======= ======== ========
</TABLE>
Employee stock options to purchase 670,662, 4,398,596, 3,809,109 and
3,809,109 shares of common stock were outstanding during the three and nine
months ended September 30, 1999 and 1998, respectively, but were not included in
the computation of diluted net income (loss) per common share because either (i)
the employee stock options' exercise price was greater than the average market
price of the common stock of the Company or (ii) the Company had a loss from
continuing operations and, therefore, the effect would be antidilutive.
7
<PAGE>
(5) Derivative Financial Instruments
The Company utilizes various option and swap contracts and other financial
instruments to hedge the effect of price changes on future oil and gas
production. The index price for the natural gas collars settles based on NYMEX
Henry Hub, while the oil collar settles based on the prices for West Texas
Intermediate on the NYMEX. The basis swaps lock in the basis differential
between NYMEX Henry Hub and the El Paso/Permian delivery point or the Waha West
Texas delivery point.
The following table sets forth the future volumes hedged by year and the
range of prices to be received based upon the fixed price of the individual
option and swap contracts and other financial instruments outstanding at
September 30, 1999:
<TABLE>
<CAPTION>
1999 2000 2001
--------------- --------------- ---------------
<S> <C> <C> <C>
Gas related derivatives:
Collar options (a):
Volume (MMBtu) 1,380,000 6,855,000 2,715,000
Index price per MMBtu (floor-ceiling prices) $ 2.20 - $2.55 $ 2.52 - $2.97 $ 2.60 - $3.08
Basis swaps:
Volume (MMBtu) 3,680,000 8,215,000 -
Index Price per MMBtu $.153 $.132 $ -
Oil related derivatives:
Collar options (b):
Volume (Bbls) 322,000 1,463,000 452,500
Index price per Bbl (floor - ceiling prices) $16.93 - $21.16 $17.06 - $21.47 $16.50 - $20.48
</TABLE>
________________
(a) Includes amounts of a counterparty which has the option to extend the collar
option from October 1, 2000 to June 30, 2001 on volumes of 15,000 MMBtu per
day at a floor and ceiling price of $2.60 and $3.08 per MMBtu, respectively.
(b) Includes amounts of a counterparty which has the option to extend the collar
option from July 1, 2000 to June 30, 2001, on volumes of 2,500 Bbls per day
at a floor and ceiling price of $16.50 and $20.48 per barrel, respectively.
8
<PAGE>
(6) Other Liabilities
The other current and noncurrent liabilities consist of the following (in
thousands):
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
---- ----
(unaudited)
<S> <C> <C>
Other current liabilities:
Capital costs and operating expenses $4,802 $2,220
Gas processing obligation - 564
Restructuring costs 61 625
Oil and gas payables 770 1,106
Asset sales related 720
Other 2,229 1,137
------ ------
$8,582 $5,652
====== ======
Other noncurrent liabilities:
Gas processing obligation $ - $1,130
Environmental reserve 808 824
Plugging and abandonment reserve - 2,483
Gas and pipeline imbalances (21) 225
Other 397 591
------ ------
$1,184 $5,253
====== ======
</TABLE>
(7) Exploration and Abandonment
Exploration and abandonment expense consist of the following (in
thousands):
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
-------------------------------- ---------------------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Geological and geophysical staff $ 158 $ 345 $ 596 $1,010
Uneconomical exploratory projects 1,556 136 4,326 1,504
Seismic costs 611 686 2,422 1,311
Delay rentals 51 354 189 1,141
Plugging and abandonment reserve 129 - 129 526
Other 163 355 545 585
------ ------ ------ ------
$2,668 $1,876 $8,207 $6,077
====== ====== ====== ======
</TABLE>
9
<PAGE>
(8) Impairment of Long-Lived Assets
In the fourth quarter of 1998, the Company approved a plan to dispose of
non-strategic assets, including its Gulf of Mexico, Gulf Coast and certain
Permian Basin assets. The Company's reason to dispose of these assets varied
depending on the portfolio of assets being considered. The disposition would
allow the Company to (a) realize full value for certain assets whose value is
not fully reflected in the public valuation of the Company in the capital
markets, (b) redeploy capital to higher return projects or acquisitions, (c)
invest in projects that will accelerate cash flow to the Company, (d) eliminate
certain administrative costs and (e) reduce the Company's debt obligations.
In the first quarter of 1999, the Company recognized an impairment of $25.9
million on the assets held for sale. The impairment was the result of comparing
the estimated sales proceeds, less costs to sell, to the underlying net cost
basis of each specific portfolio of assets.
In the second quarter and third quarter of 1998, the Company recognized an
impairment of $8.0 million and $5.1 million, respectively. The impairments were
a consequence of the book value of certain properties being greater than the
estimated net cash flows from those properties.
(9) Common Stock
In May 1997, the Company originally announced a plan to repurchase up to
$25 million, which in August 1999 the Company's board of directors increased to
$35 million, of the Company's common stock. The repurchases will be made
periodically, depending on market conditions, and will be funded with cash flow
from operations and, as necessary, borrowings under the Credit Agreement. At
September 30, 1999 and December 31, 1998, the Company had purchased, pursuant to
the repurchase plan, 3,001,000 and 2,547,000 shares of its common stock for
approximately $21.8 million and $19.6 million, respectively. Subsequent to
September 30, 1999, the Company purchased an additional 750,000 shares of its
common stock for approximately $3.5 million.
10
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
General
The Company is an independent energy company engaged in the exploitation,
development, exploration and acquisition of oil and gas properties. The
Company's strategy is to grow reserves, production and net income per share
through (i) the exploitation and development of its reserve base, (ii) the
acquisition of producing properties that provide significant development and
exploratory drilling potential, (iii) the exploration for oil and gas reserves,
(iv) capitalization on advanced technology to identify, explore and exploit
projects, (v) financial flexibility, and (vi) a low overhead and operating cost
structure. The Company has grown rapidly through the acquisition and
exploitation of oil and gas properties.
The Company's growth from acquisitions has impacted its financial results
in a number of ways. Acquired properties may not have received focused attention
prior to sale. After acquisition, certain of these properties required extensive
maintenance, workovers, recompletions and other remedial activity that while not
constituting capital expenditures may initially increase lease operating
expenses. The Company may dispose of certain of the properties it determines 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, the Company has incurred increases in its general
administrative expense levels in prior periods.
The Company 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, and geological and
geophysical costs 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.
Recent Developments
Asset Divestitures
In the fourth quarter of 1998, the Company approved a plan to dispose of
non-strategic assets, including its Gulf of Mexico, Gulf Coast and certain
Permian Basin assets. The Company's reason to dispose of these assets varied
depending on the portfolio of assets being considered. The disposition would
allow the Company to (a) realize full value for certain assets whose value is
not fully reflected in the public valuation of the Company in the capital
markets, (b) redeploy capital to higher return projects or acquisitions, (c)
invest in projects that will accelerate cash flow to the Company, (d) eliminate
certain administrative costs and (e) reduce the Company's debt obligations.
In May 1999, the Company sold its assets in the Gulf of Mexico to Coastal
Oil & Gas Corporation for $71.3 million in cash. In the first quarter of 1999,
the Company wrote down its cost in these assets by $24.5 million based on the
then expected proceeds.
The Company closed the sale of its Gulf Coast properties in April 1999 for
$5.4 million in cash. In the first quarter of 1999, the Company wrote down its
cost in these assets by $1.4 million based on the then expected proceeds.
In July 1999, the Company terminated a purchase and sale agreement to sell
a small package of Permian Basin oil and gas properties. The agreement was
terminated due to the purchaser's inability to close the transaction under the
terms of the agreement. The Company's plan, at September 30, 1999, remains to
dispose of this group of assets and expects the completion of such disposal
before the end of the first quarter of 2000.
11
<PAGE>
Equity Offering
In July 1999, Natural Gas Partners, L.P. and Natural Gas Partners II, L.P.
(collectively, "NGP"), the Company's largest single shareholder group then
owning approximately 30.6% of the Company's common stock, completed the sale of
11,517,629 shares of their common stock holdings in the Company in an
underwritten public offering. No single person or group received more that
715,000 shares in the offering. NGP's sale of the Company's common stock was due
to the requirements of its limited partnership agreements. The Company received
no proceeds from the offering.
Impact of Crude Oil Prices
During 1998 and through the first quarter of 1999, the posted price of West
Texas intermediate crude oil (the "West Texas Crude Oil Price") ranged from
$15.75 to $8.00 per barrel. These low prices are thought to be caused
primarily by an oversupply of crude oil inventory created, in part, by an
unusually warm winter in the United States and Europe, the apparent
unwillingness of Organization of Petroleum Exporting Countries ("OPEC") to abide
by crude oil production quotas and a decline in demand in certain Asian markets.
The prices for crude oil during the second and third quarters of 1999 have shown
significant improvement over that of the previous fifteen months.
If the West Texas Crude Oil Price worsens, as it did in 1998 and early
1999, for a protracted period, it will adversely affect the Company's revenues,
net income and cash flows from operations, and the Company may delay or postpone
certain of its capital projects. It is the Company's expectation that it will
not have positive earnings in 1999.
Year 2000 Issues
Many computer software systems, as well as certain hardware and equipment
using date-sensitive data, were structured to use a two-digit date field,
meaning that they may not be able to properly recognize dates in the year 2000.
The Company is addressing this issue through a process that entails evaluation
of the Company's critical software and, to the extent possible, its hardware and
equipment to identify and assess year 2000 issues and to remediate, replace or
establish alternative procedures addressing non-Year 2000 compliant systems,
hardware and equipment.
The Company substantially completed an inventory of its systems and
equipment including computer systems and business applications. Based upon this
review, the Company currently believes that all of its critical software and
computer hardware systems are Year 2000 compliant. The Company continues to
inventory its equipment and facilities to determine if they contain embedded
date-sensitive technology. If problems are discovered, remediation, replacement
or alternative procedures for noncompliant equipment and facilities will be
undertaken on a business priority basis. The Company has tested most of its
critical software systems and believes the systems will adequately function in
the Year 2000. As of September 30, 1999, the Company had not incurred any
material amount of expense related to its Year 2000 compliance efforts. These
costs are currently being expensed as they are incurred. However, in certain
instances the Company may determine that replacing existing equipment may be
more efficient, particularly where additional functionality is available. These
replacements may be capitalized and therefore would reduce the estimated 1999
expenses associated with the Year 2000 issue. The Company currently expects
total out-of-pocket costs to become Year 2000 compliant to be less than
$100,000. The Company currently expects that such costs will not have a material
adverse effect on the Company's financial condition, operations or liquidity.
The foregoing timetable and assessment of costs to become Year 2000
compliant reflect management's current best estimates. These estimates are based
on many assumptions, including assumptions about the costs availability and
ability of resources to locate, remediate and modify affected systems, equipment
and facilities. Based upon its activities to date, the Company does not
currently believe that these factors will cause results to differ significantly
from those estimated. However, the Company cannot reasonably estimate the
potential impact on its financial condition and operations if key third parties
including, among others, suppliers, contractors, joint venture partners,
financial institutions, customers and governments do not become Year 2000
compliant on a
12
<PAGE>
timely basis. The Company is contacting many of these third parties to determine
whether they will be able to resolve in timely fashion their Year 2000 issues as
they may affect the Company.
In the event that those with whom the Company conducts business are
unsuccessful in implementing timely solutions, Year 2000 issues could have a
material adverse effect in the Company's liquidity and results of operations.
At this time, the potential effect in the event third parties are unable to
timely resolve their Year 2000 problems is not determinable; however, the
Company currently believes it has resolved its significant Year 2000 issues.
The disclosure set forth in this section is provided pursuant to Securities
Act Release No. 33-7558. As such it is protected as a forward-looking statement
under the Private Securities Litigation Reform Act of 1995. See "Forward-
Looking Statements." This disclosure is also subject to protection under the
Year 2000 Information and Readiness Disclosure Act of 1998, Public Law 105-271,
as a "Year 2000 Statement" and "Year 2000 Readiness Disclosure" as defined
therein.
13
<PAGE>
Operating Data
The following table sets forth the Company's historical operating data for
the periods indicated.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------- --------------------------------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Production:
Oil (MBbls) 543 618 1,719 1,877
Gas (MMcf) 5,959 6,392 17,680 20,516
Total (MMcfe) 9,217 10,100 27,994 31,778
Average Sales Prices Per Unit (excluding
effects of hedging activities):
Oil (Bbl) $19.32 $ 11.70 $ 14.93 $ 12.31
Gas (Mcf) $ 1.95 $ 1.40 $ 1.58 $ 1.52
Total (Mcfe) $ 2.40 $ 1.60 $ 1.91 $ 1.71
Average Sales Prices Per Unit (including
effects of hedging activities):
Oil (Bbl) $18.75 $ 11.70 $ 14.75 $ 12.42
Gas (Mcf) $ 1.85 $ 1.48 $ 1.59 $ 1.65
Total (Mcfe) $ 2.30 $ 1.65 $ 1.91 $ 1.80
Expenses Per Mcfe:
Production costs, excluding production
and other taxes $ .48 $ .61 $ .51 $ .67
Production and other taxes $ .18 $ .13 $ .15 $ .14
General and administrative $ .20 $ .23 $ .21 $ .24
Depletion, depreciation and amortization $ .55 $ .64 $ .51 $ .61
</TABLE>
14
<PAGE>
Results of Operations
Three Months Ended September 30, 1999 Compared to the Three Months Ended
September 30, 1998
The Company's revenues from the sale of oil and gas (excluding the effects
of hedging) were $10.5 million and $11.6 million in 1999 and $7.2 million and
$8.9 million in 1998, respectively. Realized oil prices increased $7.62 per
Bbl and gas prices increased $.55 per Mcf between comparable quarters. Assuming
1998 prices in 1999 (excluding the effects of hedging), the Company's revenues
would have decreased by approximately $7.4 million. Oil and gas production
decreased 75,000 barrels and 433 MMcf, respectively, between comparable
quarters. Excluding the production from the two significant dispositions
previously discussed, oil production decreased 61,000 barrels and gas production
increased 386 MMcf, respectively, between comparable quarters. The decrease in
the oil production is principally due to normal production declines and the
Company deferring some of its 1998 projects due to the then uncertainties over
future commodity price levels. The increase in gas production is due to
recently drilled wells offset by normal production declines and loss and/or
curtailment of production on wells due to mechanical and/or reservoir problems.
The Company's gas hedging activities in 1999 decreased gas revenues by
$587,000 ($.10 per Mcf), as compared to 1998 when the hedging activities
increased gas revenues by $496,000 ($.08 per Mcf). At September 30, 1999,
the Company has 6,855,000 MMBtu of gas hedged which will allow the Company to
realize an average minimum price of $2.30 per MMBtu on the hedged volumes. The
current gas hedges extend through September 2000, through commodity price
collars. A counterparty has the option to extend a gas commodity price collar
for the period from October 2000 through June 2001 on 15,000 MMBtu per day with
a floor and ceiling price of $2.60 and $3.08 per MMBtu, respectively.
The Company's oil hedging activities in 1999 decreased oil revenues by
$310,000 ($.57 per barrel) as compared to 1998 when the Company had no oil
hedges. At September 30, 1999, the Company has 1,325,000 barrels of oil hedged
which will allow the Company to realize an average minimum price of $17.22 per
barrel on the hedged volumes. The current oil hedges extend through September
2000. A counterparty has the option to extend an oil commodity price collar from
July 2000 through June 2001 on 2,500 barrels of oil per day with a floor and
ceiling price of $16.50 and $20.48 per barrel, respectively.
The Company's production costs were $4.4 million ($.48 per Mcfe) and $6.1
million ($.61 per Mcfe) in 1999 and 1998, respectively. Excluding the
production costs from the two significant dispositions previously discussed, the
Company's production costs would have been $4.4 million ($.48 per Mcfe) and $5.1
million ($.54 per Mcfe) in 1999 and 1998, respectively. The decrease is
primarily due to the sale of properties and the Company incurring some carryover
rework expenses in 1998 associated with its 1997 acquired properties.
Depletion, depreciation and amortization expense (DD&A) was $5.0 million
($.55 per Mcfe) and $6.5 million ($.64 per Mcfe) for the comparable quarters of
1999 and 1998, respectively. The decrease in the absolute and per unit amounts
is attributable to (a) the third quarter of 1999 not including DD&A for the
assets classified as assets held for sale and (b) increased proved reserves,
between comparable quarters, resulting from increased commodity prices and
recent drilling activities. The Company's DD&A per unit amount increase over
the second quarter of 1999 is due primarily to a significant increase in gas
volumes from high impact short lived gas properties which have a higher per unit
DD&A rate.
The Company recognized an impairment of $5.1 million in 1998. The
impairment was due to loss of proved reserves attributable to (a) downhole
mechanical problems with an offshore well and (b) lower than expected drilling
results on three onshore wells. The Company had no impairment in the comparable
quarter in 1999.
The Company's exploration and abandonment expense was $2.7 million and $1.9
million for the comparable quarters of 1999 and 1998, respectively. In the
third quarter of 1999, the Company incurred over $611,000 in seismic costs in
addition to approximately $1.6 million of costs associated with uneconomical
exploratory projects. The seismic costs are primarily attributable to the
Company's share of the Phase I 3-D seismic acquisition in the Paragon Joint
Venture.
15
<PAGE>
The Company's general and administrative expense (G&A) was $1.8 million
($.20 per Mcfe) and $2.3 million ($.23 per Mcfe) for the comparable quarters of
1999 and 1998, respectively. Excluding the G&A from the two significant
dispositions previously discussed, the Company's G&A would have been $1.8
million ($.20 per Mcfe) and $1.9 million ($.20 per Mcfe) in 1999 and 1998,
respectively. The decrease in G&A is due to the integration in 1998 of the 1997
acquisitions and the Company's previously announced cost cutting measures.
The Company's interest expense was $1.3 million and $2.3 million for the
1999 and 1998 comparable quarters, respectively. In 1998, the Company incurred
increased levels of debt as a result of its 1997 acquisitions and 1998 capital
spending. In 1999, the higher initial debt levels as compared to the 1998
period were reduced by the paydown of debt as a result of the two previously
discussed dispositions. The Company's debt at September 30, 1999 was at its
lowest level since September 30, 1997.
In 1999, the Company did not record a deferred income tax expense related
to the income from operations. No deferred tax expense was recorded due to the
significant valuation allowance the Company has related to its net deferred tax
asset. In 1999, the Company expects to pay federal alternative minimum tax of
approximately $500,000, primarily as a result of the 1999 asset dispositions.
Nine Months Ended September 30, 1999 Compared to the Nine Months Ended
September 30, 1998
The Company's revenues from the sale of oil and gas (excluding the effects
of hedging) were $25.7 million and $27.9 million in 1999 and $23.1 million and
$31.2 million in 1998, respectively. Realized oil and gas prices increased
$2.62 per Bbl and $.06 per Mcf, respectively, between comparable periods.
Assuming 1998 prices in 1999 (excluding the effects of hedging), the Company's
revenues would have decreased by approximately $5.6 million. Oil and gas
production decreased 158,000 barrels and 2,836 MMcf, respectively, between
comparable periods. Excluding the production from the two significant
dispositions previously discussed, oil and gas production decreased 188,000
barrels and 1,163 MMcf, respectively, between comparable periods. The decrease
in the oil production is principally due to normal production declines and the
Company deferring some of its 1998 projects due to the then uncertainties over
future commodity price levels. The decrease in gas production is partially due
to normal production declines and loss and/or curtailment of production on wells
due to mechanical and/or reservoir problems, offset by increased gas production
from the Company's recent drilling activities, as previously discussed.
The Company's gas hedging activities in 1999 increased gas revenues by
$186,000 ($.01 per Mcf) as compared to 1998 when the hedging activities
increased gas revenues by $2.6 million ($.13 per Mcf). Oil hedging activities
in 1999 decreased oil revenues by $310,000 ($.18 per barrel) as compared to
increasing oil revenues in 1998 by $206,000 ($.11 per barrel).
The Company's production costs were $14.2 million ($.51 per Mcfe) and $21.3
million ($.67 per Mcfe) in 1999 and 1998, respectively. Excluding the
production costs from the two significant dispositions previously discussed, the
Company's production costs would have been $12.9 million ($.49 per Mcfe) and
$17.8 million ($.62 per Mcfe) in 1999 and 1998, respectively. A portion of the
decrease is due to the first half of 1998 rework expenses (over $.08 per Mcfe)
associated with the 1997 acquired properties. Initially, acquired properties
generally incur significant rework expenses, which are costs incurred to perform
required maintenance, workovers and other remedial activities. Also, the
decrease is due to the sale of properties and the Company performing only
routine and necessary expenditures in certain fields due to depressed commodity
prices.
Depletion, depreciation and amortization expense (DD&A) was $14.2 million
($.51 per Mcfe) and $19.5 million ($.61 per Mcfe) for the comparable periods of
1999 and 1998, respectively. The decrease in the absolute and per unit amounts
is attributable to (a) the first three quarters of 1999 not including DD&A for
the assets classified as assets held for sale and (b) increased proved reserves,
between comparable periods, resulting from increased commodity prices and recent
drilling activities.
16
<PAGE>
The Company recognized an impairment of $25.9 million and $13.1 million in
1999 and 1998, respectively. The 1999 impairment relates to the write-down of
the net cost of the assets held for sale based on the expected net proceeds from
the sale of these assets. The 1998 impairment was due to loss of proved
reserves attributable to (a) downhole mechanical problems with an offshore well
and (b) lower than expected drilling results on three onshore wells.
The Company's exploration and abandonment expense was $8.2 million and $6.1
million for the comparable periods of 1999 and 1998, respectively. In 1999, the
Company incurred over $2.4 million in seismic costs in addition to approximately
$4.3 million of costs associated with uneconomical exploratory projects. The
seismic costs are primarily attributable to the Company's share of the Phase I
3-D seismic acquisition in the Paragon Joint Venture.
The Company's general and administrative expense (G&A) was $5.9 million
($.21 per Mcfe) and $7.7 million ($.24 per Mcfe) for the comparable periods of
1999 and 1998, respectively. Excluding the G&A from the two significant
dispositions previously discussed the Company's G&A would have been $5.2 million
($.20 per Mcfe) and $5.9 million ($.20 per Mcfe) in 1999 and 1998, respectively.
The decrease in G&A is due to the integration in 1998 of the 1997 acquisitions
and the Company's previously announced cost cutting measures.
The Company's interest expense was $5.9 million and $6.0 million in the
1999 and 1998 comparable periods, respectively. Between the periods, the
Company had comparable average debt levels. As previously discussed, the
Company has significantly reduced its debt levels in the second quarter of 1999.
In 1999, the Company did not record a deferred income tax benefit related
to the loss from operations. No deferred tax benefit was recorded due to it
being more likely than not that the Company may not be able to utilize all of
its available loss carryforwards prior to their ultimate expiration.
17
<PAGE>
Liquidity and Capital Resources
The Company's primary sources of capital have been its initial
capitalization, private equity sales, bank financing, cash flow from operations
and the Company's initial public offering. 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.
Net Cash Provided by Operating Activities. Net cash provided by operating
activities, before changes in operating assets and liabilities, was $11.9 and
$22.7 million for the three and nine months ended September 30, 1999 compared to
$3.9 and $16.1 million for the three and nine months ended September 30, 1998.
The increase is due to increased overall commodity prices and decreased cash
operating expenses, partially offset by lower production.
Capital Expenditures. For 1999, the Company originally budgeted $49.5 million
for capital expenditures and incurred actual expenditures of $20.7 million
through September 30, 1999. Approximately $8.0 million of the annual budget
related to assets in the Gulf of Mexico which the Company sold in May 1999.
Through September 30, 1999, the Company had spent approximately $1.6 million of
capital expenditures associated with the Gulf of Mexico assets.
For 1999, after giving effect to assets sold and other adjustments, the
Company originally expected to spend approximately $46.2 million on oil and gas
projects as follows: (i) approximately $15.5 million on developmental projects,
(ii) approximately $7.8 million on exploratory projects, (iii) approximately
$17.2 million on probable and possible projects and (iv) approximately $5.7
million to acquire additional acreage and seismic data. The final determination
with respect to the drilling of any well, including those currently budgeted,
will depend on a number of factors, including (i) the results of exploration
efforts and the review and analysis of the seismic data, (ii) the availability
of sufficient capital resources of the Company and other participants for
drilling prospects, (iii) economic and industry conditions at the time of
drilling, including prevailing and anticipated prices for natural gas and oil
and the availability and costs of drilling rigs, related contract support
services and crews, (iv) the financial resources and results of the Company, and
(v) the availability of leases on reasonable terms and permitting for the
potential drilling locations. There can be no assurance that the budgeted wells
will encounter, if drilled, recompleted or worked over, reservoirs of commercial
quantities of natural gas or oil. The Company is, currently, 60 to 90 days
behind its planned drilling and workover program primarily due to the lack of
availability of qualified drilling rigs and crews and other equipment used by
the Company's field service providers. Accordingly, the Company anticipates
spending less than $46.2 million of originally planned expenditures.
Cash expenditures for investing in oil and gas properties were $19.8
million for the nine months ended September 30, 1999. This includes $3.8 million
for the acquisition of oil and gas leases and proved properties and $16.0
million for development, probable and possible and exploratory projects.
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.
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 material 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 which may be required in the future to fund
the Company's acquisition and drilling programs.
Capital Resources. The Company's primary capital resources are net cash
provided by operating activities and the availability under the Credit
Agreement, of which approximately $100 million was available at September 30,
1999.
Credit Agreement. In June 1999, the Company entered into an amended and
restated credit agreement (the "Credit Agreement") with Chase Bank of Texas,
N.A. (the "Bank"), which established a revolving credit facility of $250 million
subject to a borrowing base. The borrowing base, which is $175 million at
September 30, 1999, is subject to redetermination annually each April by the
lenders based on certain proved oil and gas reserves and other assets
18
<PAGE>
of the Company. To the extent 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 Agreement is available for the issuance of up to $15.0 million of letters
of credit, of which $144,000 was outstanding at September 30, 1999. All amounts
outstanding are due and payable in full on January 1, 2001. At September 30,
1999, the outstanding principal was $75 million and the available capacity was
approximately $100 million.
At the Company's option, borrowings under the Credit Agreement bear
interest at either the "Base Rate" (i.e., the higher of the applicable prime
commercial lending rate, or the federal funds rate plus .5% per annum) or the
Eurodollar rate, plus 1% to 1.50% per annum, depending on the level of the
Company's aggregate outstanding borrowings. In addition, the Company is
committed to pay quarterly in arrears a fee of .300% to .375% of the unused
borrowing base.
The Credit Agreement contains certain covenants and restrictions that are
customary in the oil and gas industry. In addition, the line of credit is
secured by substantially all of the Company's oil and gas properties.
Liquidity and Working Capital. At September 30, 1999, the Company had $1.8
million of cash and cash equivalents as compared to $610,000 at December 31,
1998. The Company's ratio of current assets to current liabilities was 1.91 at
September 30, 1999, compared to 6.23 at December 31, 1998. The positive working
capital is due to the assets held for sale. Excluding the assets held for
sale, the Company would have a working capital deficit of $1.8 million and $3.8
million at September 30, 1999 and December 31, 1998, respectively. The working
capital is due to the Company's efforts to maintain low cash levels for cash
management purposes. The working capital deficit at September 30, 1999 is
adequately covered by the Company's ability to borrow under its Credit
Agreement.
Unsecured Credit Agreement. In April 1997, the Company entered into a credit
agreement, as amended (the "Unsecured Credit Agreement"), with the Bank which
establishes a revolving credit facility, up to the maximum of $5.0 million.
Individual borrowings may be made for up to a three week period. The Unsecured
Credit Agreement has no maturity date and is cancellable at anytime by the Bank.
Proceeds of the Unsecured Credit Agreement are utilized to fund short-term needs
(less than thirty days). The Company had no outstanding principal under the
Unsecured Credit Agreement at September 30, 1999.
The interest rate of amounts outstanding under the Unsecured Credit
Agreement is at a rate determined by agreement between the Company and the Bank.
The rate shall not exceed the maximum interest rate permitted under applicable
law. Interest rates generally are the Bank's cost of funds plus 1% per annum.
19
<PAGE>
OTHER MATTERS
Hedging Activities
The Company uses swap agreements and other financial instruments in an
attempt to reduce the risk of fluctuating oil and gas prices and interest rates.
The Company is party to various agreements with numerous counterparties for
purposes of utilizing financial instruments, of which the Company assesses the
creditworthiness of its counterparties. Among other counterparties, the Company
has utilized Enron Capital & Trade Resources Corp. (an affiliate of a
significant stockholder of the Company) as a counterparty. Settlement of gains
or losses on the hedging transactions are generally based on the difference
between the contract price and a formula using New York Mercantile Exchange
("NYMEX") or other major indices related prices and is reported as a component
of oil and gas revenues as the associated production occurs. At September 30,
1999, the Company had entered into hedging transactions with respect to
approximately 1,380,000 and 5,475,000 MMBtu of its future 1999 and 2000,
respectively, estimated natural gas production and 322,000 and 1,003,000 barrels
of its future 1999 and 2000, respectively, estimated crude oil production. For
additional information, see note 5 of Notes to Consolidated Financial
Statements.
Recently Issued Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" which establishes standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. It establishes conditions
under which a derivative may be designated as a hedge, and establishes standards
for reporting changes in the fair value of a derivative. SFAS No. 133 is
required to be implemented for the first quarter of the fiscal year ended 2000.
Early adoption is permitted. Recently, the FASB deferred the implementation
requirements of SFAS No. 133 for one year. The Company has not evaluated the
effects of implementing SFAS No. 133.
20
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following quantitative and qualitative information is provided about
financial instruments to which the Company is a party as of September 30, 1999,
and from which the Company may incur future earnings gains or losses from
changes in market interest rates and commodity prices. The Company does not
enter into derivative or other financial instruments for trading purposes.
Quantitative Disclosures
Commodity Price Sensitivity:
The following table provides information about the Company's derivative
financial instruments that are sensitive to changes in natural gas and crude oil
commodity prices. See note 5 of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements" for specific information regarding
the terms of the Company's commodity derivative financial instruments that are
sensitive to natural gas and crude oil commodity prices.
<TABLE>
<CAPTION>
Fair
1999 2000 2001 Total Value
---------- ---------- ---------- ---------- -----------
(dollars in thousands, except volumes and prices)
<S> <C> <C> <C> <C> <C>
Natural Gas Hedge Derivatives (a):
Collar option contracts (b):
Notional volumes (MMBtu) 1,380,000 6,855,000 2,715,000 10,950,000 $ (768,718)
Weighted average short call MMBtu strike price (c) $ 2.20 $ 2.52 $ 2.60
Weighted average long put MMBtu strike price (c) $ 2.55 $ 2.97 $ 3.08
Basis differential contracts (d):
Notional volumes (MMBtu) 3,680,000 8,215,000 - 11,895,000 $ (154,000)
Weighted average MMBtu strike price $ .153 $ .132 $ -
Crude Oil Hedge Derivatives (a):
Collar option contracts (e):
Notional volume (Bbls) 322,000 1,463,000 452,500 2,237,500 $(3,264,000)
Weighted average short call strike price per Bbl (c) $ 16.93 $ 17.06 $ 16.50
Weighted average long put strike price per Bbl (c) $ 21.16 $ 21.47 $ 20.48
</TABLE>
___________________________________
(a) See note 5 of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for additional information related to hedging
activities.
(b) A counterparty has the option to extend a collar option from October 1, 2000
to June 30, 2001 on volumes of 15,000 MMBtu per day at a floor and ceiling
price of $2.60 and $3.08 per MMBtu, respectively. The fair value assumes
the extension is exercised by the counterparty.
(c) The strike prices are based on the prices traded on the New York Mercantile
("NYMEX").
(d) The basis differential relates to the spread between the NYMEX price and a
El Paso/Permian price or a Waha West Texas price.
(e) A counterparty has the option to extend a collar option from July 1, 2000 to
June 30, 2001 on volumes of 2,500 barrels per day at a floor and ceiling
price of $16.50 and $20.48 per barrel, respectively. The fair value assumes
the extension is exercised by the counterparty.
21
<PAGE>
Interest Rate Sensitivity:
The following table provides information about the Company's financial
instruments that are sensitive to interest rates. The debt obligations are
presented in the table at their contractual maturity dates together with the
weighted average interest rates expected to be paid on the debt. The weighted
average interest rates for the variable debt represents the weighted average
interest paid and/or accrued in September 1999. See note 2 of Notes to
Consolidated Financial Statements included in "Item 1. Financial Statements"
for specific information regarding the terms of the Company's debt obligations
that are sensitive to interest rates.
<TABLE>
<CAPTION>
Fair
1999 2000 2001 Total Value
----- ----- ------- -------- --------
(in thousands, except interest rates)
<S> <C> <C> <C> <C> <C>
Debt (a)
Variable rate debt:
Chase Bank of Texas, N.A. (Secured) $ - $ - $75,000 $75,000 $75,000
Average interest rate 6.34% 6.34% 6.34%
Chase Bank of Texas, N.A. (Unsecured) $ - $ - $ - $ - $ -
Average interest rate N/A N/A N/A
</TABLE>
__________________________
(a) See note 2 of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for additional information related to debt.
Qualitative Disclosures
The Company, from time to time, enters into interest rate and commodity
price derivative contracts as hedges against interest rate and commodity price
risk. See note 5 of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for discussions relative to the Company's objectives
and general strategies associated with it hedging instruments. The Company is a
borrower under variable rate debt instruments that give rise to interest rate
risk. See note 2 of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for specific information regarding the terms of the
Company's debt obligations. The Company's policy and strategy, as of September
30, 1999, is to only enter into interest rate and commodity price derivative
instruments that qualify as hedges of its existing interest rate or commodity
price risks.
As of September 30, 1999, the Company's primary risk exposures associated
with financial instruments to which it is a party include natural gas price
volatility and interest rate volatility. The Company's primary risk exposures
associated with financial instruments have not changed significantly since
December 31, 1998.
22
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
The two lawsuits related to OEDC, disclosed in note 3 of Notes to
Consolidated Financial Statements, have reached a settlement that has received
preliminary approval by the court. See note 3 of Notes to Consolidated
Financial Statements for additional discussion.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
--------
27 Financial Data Schedule
(b) Reports Submitted on Form 8-K:
None
23
<PAGE>
SIGNATURE
---------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
TITAN EXPLORATION, INC.
By: /s /Jack Hightower
-------------------------------
Jack Hightower
President and Chief Executive Officer
By: /s/ William K. White
-------------------------------
William K. White
Vice President and Chief Financial
Officer
Date: November 13, 1999
24
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSOLIDATED
FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JUL-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,754
<SECURITIES> 0
<RECEIVABLES> 10,389
<ALLOWANCES> 0
<INVENTORY> 699
<CURRENT-ASSETS> 28,098
<PP&E> 319,387
<DEPRECIATION> (111,878)
<TOTAL-ASSETS> 235,918
<CURRENT-LIABILITIES> 14,717
<BONDS> 0
0
0
<COMMON> 405
<OTHER-SE> 144,612
<TOTAL-LIABILITY-AND-EQUITY> 235,918
<SALES> 21,225
<TOTAL-REVENUES> 21,225
<CGS> 0
<TOTAL-COSTS> 16,876
<OTHER-EXPENSES> (1,361)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,296
<INCOME-PRETAX> 4,414
<INCOME-TAX> 540
<INCOME-CONTINUING> 3,874
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,874
<EPS-BASIC> .10
<EPS-DILUTED> .10
</TABLE>
