U.S. 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 March 31, 2002
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 No. 001-14745
3TEC ENERGY CORPORATION
(Exact name of small business issuer as specified in its charter)
DELAWARE 63-1081013
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
700 MILAM, SUITE 1100
HOUSTON, TX 77002
(Address of principal executive offices)
(713) 821-7100
(Issuer's telephone number)
N/A
(Former Name, Former Address and Former Fiscal Year,
If Changed Since Last Report)
Indicate by check mark whether the registrant (1) filed all reports
required to be filed by Section 13 or 15(d) of 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 [ ]
Number of shares outstanding of each of the Registrant's classes of common
stock, as of the latest practicable date:
Common stock, $0.02 par value
16,538,973 shares as of April 24, 2002
3TEC ENERGY CORPORATION AND SUBSIDIARIES
INDEX
PAGE
NO.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets-
March 31, 2002 (Unaudited) and December 31, 2001 (Audited)...... 1
Consolidated Statements of Operations (Unaudited)-
Three months ended March 31, 2002 and 2001...................... 2
Consolidated Statements of Cash Flows (Unaudited)-
Three months ended March 31, 2002 and 2001...................... 3
Notes to Consolidated Financial Statements (Unaudited)............ 4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................. 7
Item 3. Quantitative and Qualitative Disclosures About Market Risk..... 13
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders............ 14
Item 6. Exhibits and Reports on Form 8-K............................... 14
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
MARCH 31, DECEMBER 31,
2002 2001
--------- ------------
(Unaudited) (Audited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents.................................................. $ 3,218 $ 17,762
Accounts receivable........................................................ 12,058 16,835
Income taxes receivable.................................................... 164 4,464
Other current assets....................................................... 1,688 4,473
--------- ---------
Total current assets................................................. 17,128 43,534
PROPERTYAND EQUIPMENT (AT COST)
Oil and gas-successful efforts method...................................... 396,487 385,264
Other property and equipment............................................... 3,725 3,549
--------- ---------
400,212 388,813
Accumulated depreciation, depletion and amortization............................ (78,949) (71,039)
---------- ----------
Net Properties and Equipment.................................................... 321,263 317,774
OTHER ASSETS.................................................................... 1,572 1,730
--------- ---------
TOTAL ASSETS.................................................................... $ 339,963 $ 363,038
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable........................................................... $ 7,992 $ 25,052
Accrued liabilities........................................................ 1,149 1,322
Series C Preferred stock redemption payable................................ 1,297 1,349
Derivative fair value liability............................................ 18,329 --
Other current liabilities.................................................. 778 1,468
--------- ---------
Total current liabilities....................................................... 29,545 29,191
LONG-TERM DEBT.................................................................. 99,000 108,000
DEFERRED INCOME TAXES........................................................... 39,280 45,135
STOCKHOLDERS' EQUITY
Preferred stock, $0.02 par, 20,000,000 shares authorized, 266,667 designated
Series B, 2,300,000 shares designated Series C and
725,167 shares designated Series D, none other designated.................. -- --
Convertible preferred stock Series B, $7.50 stated value, 266,667 and 207,905
shares issued and outstanding at March 31,2002 and
December 31, 2001, respectfully. $1,559 aggregate liquidation preference... 2,828 3,627
Convertible preferred stock Series D, $24.00 stated value, 614,776 shares issued
and outstanding at March 31, 2002 and December 31, 2001,
respectively. $14,755 aggregate liquidation preference................... 7,485 7,485
Common stock, $.02 par value, 60,000,000 shares authorized, 16,608,780 and
16,547,595 shares issued at March 31, 2002
and December 31, 2001, respectively........................................ 332 331
Additional paid-in capital................................................. 152,469 151,412
Retained earnings.......................................................... 10,073 18,906
Treasury stock; 69,807 shares at March 31, 2002 and December 31, 2001,
respectively.............................................................. (1,049) (1,049)
--------- ---------
TOTAL STOCKHOLDERS' EQUITY...................................................... 172,138 180,712
--------- ---------
COMMITMENTS AND CONTINGENCIES................................................... - -
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................................... $ 339,963 $ 363,038
========= =========
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
THREE MONTHS ENDED
MARCH 31
-------------------------
(Unaudited) (Unaudited)
2002 2001
------ ------
REVENUES
Oil, natural gas and plant income............... $ 18,306 $ 44,519
Gain on sale of properties...................... 77 87
Loss on derivative fair value................... (21,410) --
Gain on derivatives settlements................. 6,883 --
Other........................................... 188 125
----------- -----------
TOTAL REVENUES....................................... 4,044 44,731
----------- -----------
EXPENSES
Production -
Lease operations............................. 3,723 4,357
Production, severance and ad valorem taxes... 1,248 2,989
Gathering, transportation and other.......... 1,033 815
Geological and geophysical...................... 180 215
Dry hole........................................ 54 --
General and administrative...................... 2,207 1,542
Interest........................................ 1,023 2,181
Depreciation, depletion and amortization........ 8,755 6,338
----------- -----------
TOTAL EXPENSES....................................... 18,223 18,437
INCOME (LOSS) BEFORE INCOME TAX EXPENSE,
MINORITY INTEREST AND DIVIDENDS
TO PREFERRED STOCKHOLDERS.......................... (14,179) 26,294
Minority Interest.................................... -- 182
Income tax (benefit) expense......................... (5,531) 9,935
------------ -----------
NET INCOME (LOSS).................................... (8,648) 16,177
Dividends to preferred stockholders.................. 185 191
----------- -----------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS................................ $ (8,833) $ 15,986
============ ===========
NET INCOME (LOSS) PER COMMON SHARE
BASIC........................................... $ (0.54) $ 1.10
=========== ===========
DILUTED......................................... $ (0.54) $ 0.87
=========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC........................................... 16,488,579 14,597,465
=========== ===========
DILUTED......................................... 16,488,579 19,049,503
=========== ===========
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
2
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
THREE MONTHS ENDED
MARCH 31
---------------------------
(Unaudited) (Unaudited)
2002 2001
------ ------
OPERATING ACTIVITIES
Net income (loss)................................................................... $ (8,648) $ 16,177
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization....................................... 8,590 6,176
Amortization of debt issue costs............................................... 165 162
Dry hole costs................................................................. 54 -
Loss on derivative fair value.................................................. 21,410 -
Gain on sale of properties..................................................... (77) (87)
Deferred income taxes.......................................................... (5,530) 4,723
Minority interest.............................................................. - 182
Common stock issued in lieu of directors fees.................................. 8 -
Changes in current assets and liabilities net of acquisition effects:
Accounts receivable and other current assets................................. 8,773 4,153
Accounts payable, accrued liabilities and other current liabilities.......... (17,975) 6,859
--------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES........................................... 6,770 38,345
INVESTING ACTIVITIES
Proceeds from sales of properties.............................................. 674 -
Acquisition of Classic Resources, Inc., net of cash acquired................... - (57,199)
Acquisition of oil and gas properties.......................................... - (383)
Development of oil and gas properties.......................................... (12,878) (14,657)
Additions to other assets...................................................... (176) (587)
--------- ---------
NET CASH USED IN INVESTING ACTIVITIES............................................... (12,380) (72,826)
FINANCING ACTIVITIES
Proceeds from long term debt................................................... 17,000 62,000
Principal payments on long-term debt........................................... (26,000) (26,000)
Proceeds from exercise of stock options and warrants........................... 251 47
Preferred stock dividends...................................................... (185) -
--------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................................. (8,934) 36,047
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.................................... (14,544) 1,566
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.................................... 17,762 4,436
-------- --------
CASH AND CASH EQUIVALENTS AT ENDING OF PERIOD....................................... $ 3,218 $ 6,002
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest....................................................................... $ 957 $ 1,190
======== ========
Income taxes................................................................... $ - $ 4,408
======== ========
Non-cash investing and financing activities:
Preferred dividends incurred but not paid...................................... $ - $ 191
======== ========
Deferred taxes recorded in acquisition of Classic.............................. $ 325 $ 27,566
======== ========
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
3
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) BASIS OF PRESENTATION
In management's opinion, the accompanying unaudited consolidated financial
statements contain all adjustments (consisting primarily of normal recurring
adjustments) necessary to present fairly the consolidated financial position of
the Company as of March 31, 2002 and December 31, 2001 consolidated results of
operations and consolidated cash flows for the periods ended March 31, 2002 and
2001.
These consolidated financial statements should be read in conjunction with
the Company's financial statements and notes thereto included in the Company's
Annual Report on Form 10-KSB for the year ended December 31, 2001. The results
of operations for the three months ended March 31, 2002, are not necessarily
indicative of the results which may be expected for any other interim period or
for the entire fiscal year ending December 31, 2002.
The Company has restated its financial results for the first two quarters
of 2001. The changes reflect adjustments to oil and natural gas production and
revenues as a result of the Company's over accrual of revenue related to these
quarters. The impact of the adjustments decreased the previously reported
amounts as follows for the three months ended March 31, 2001:
Total Revenues $ 4,345
Costs and operating expenses 693
Operating income 3,652
Net Income 2,272
Net Income per share, (fully-diluted) 0.12
(2) RECLASSIFICATIONS
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
(3) EARNINGS PER SHARE
Basic earnings and loss per common share are based on the weighted average
shares outstanding without any dilutive effects considered. Diluted earnings and
loss per share reflect dilution from all potential common shares, including
options, warrants and convertible preferred stock and convertible notes. Diluted
loss per share does not include the effect of any potential common shares if the
effect would be anti-dilutive.
At March 31, 2002, the Company had a weighted average of 2,557,775 stock
options, warrants and convertible preferred stock outstanding which were not
included in the computation of diluted earnings per share, because the effect of
the assumed exercise of these stock options, warrants and convertible securities
would have an antidilutive effect on the computation of diluted loss per share.
Basic and diluted earnings per share for the three-month period ended March
31, 2001 was determined as follows (in thousands):
Three Months
Ended
March 31, 2001
--------------
Basic net income attributable to common stockholders....................... 16,177
Plus preferred stock dividends............................................. 191
Plus interest expense (net of tax) on subordinated convertible notes....... 182
-------
Fully diluted net income attributable to common stockholders............... $16,550
=======
4
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(Unaudited)
Outstanding
Shares
-----------
Basic shares outstanding (weighted average shares).............. 14,597
Plus potentially dilutive securities:
Dilutive options and warrants applying treasury stock method.... 2,230
Shares from conversion of subordinated convertible notes........ 1,469
Shares from conversion of Series B preferred stock.............. 132
Shares from conversion of Series D preferred stock.............. 622
------
Fully diluted shares outstanding (weighted average shares)...... 19,050
======
(4) ACQUISITIONS
On January 30, 2001, the Company acquired 100% of the issued and
outstanding stock of Classic Resources Inc. (the "Classic Acquisition") for cash
consideration of approximately $53.5 million plus other acquisition costs. The
operating results of the Classic Acquisition have been included in the
consolidated financial statements since that date. Classic was a privately held
exploration and production company with properties located in East Texas. The
Company estimate of total net proved reserves at the time of the acquisition was
47 Bcfe and net daily production of approximately 11 Mmcfe, as of January 31,
2001. The Classic Acquisition was financed under the Company's existing Credit
Facility. The purchase price of the Classic Acquisition was allocated
principally to proved properties, with additional amounts allocated to working
capital related to amounts recorded for production related receivables and
payables in existence and accrued for at January 31, 2001. In connection with
the Classic Acquisition, approximately $29 million in deferred income taxes were
recorded as a result of the difference between the allocated purchase price and
the historical tax basis of the properties.
The following pro forma data presents the results of the Company for the
three months ended March 31, 2001, as if the Classic Acquisition had occurred on
January 1, 2001. The pro forma data assumes the acquisition of the respective
properties and the debt financing transactions related to these acquisitions.
The pro forma results are presented for comparative purposes only and are not
necessarily indicative of the results which would have been obtained had the
acquisitions been consummated as presented. (in thousands, except per share
amounts):
Pro Forma
Three Months Ended
March 31, 2001
(Unaudited)
-----------------
Total revenues................................................. $ 46,801
Net income attributable to common stockholders................. 13,796
Net income per basic share attributable to common stockholders. 0.95
(5) STOCKHOLDERS' EQUITY
During March, 2002, a holder of the Company's Series B Preferred Stock
("Series B") elected to convert 58,762 Series B shares into 34,065 shares of the
Company's Common Stock ("Common"). The conversion ratio was determined using the
convertible shares at December 31, 2001 whereby 266,667 Series B shares were
convertible into 154,591 shares of Common. At March 31, 2002, 207,905 Series B
shares were outstanding.
(6) DERIVATIVE ACTIVITIES
During February 2002, the Company unwound the floor portion of the April
through October 2002 collar for net proceeds of approximately $5.8 million
($0.48/Mmbtu), and then re-swapped the 56,000 Mmbtu of daily natural gas
production at $2.56/Mmbtu. Also during February 2002, the Company put in place a
collar on 20,000 Mmbtu of daily gas production from November 2002 to March 2003
with a floor of $3.20/Mmbtu and a weighted average ceiling of $3.53/Mmbtu.
5
The following table details the Company's derivative contract positions
which were in place at March 31, 2002.
Natural Gas Derivatives
Period MCF Per Day Total MCF Type NYMEX Price
------ ----------- --------- ---- -----------
April 2002 - October 2002 56,000 11,984,000 Call $3.50
April 2002 - October 2002 28,000 5,992,000 Call $3.15
April 2002 - October 2002 56,000 11,984,000 Swap $2.56
November 2002 - March 2003 20,000 3,020,000 Put $3.20
November 2002 - March 2003 10,000 1,510,000 Call $3.40
November 2002 - March 2003 20,000 3,020,000 Call $3.60
For the period from April 1, 2002 to October 30, 2002 the Company has
notional volumes of 84,000 MCF per day under written call derivatives. These
notional volumes exceed actual production volumes at April 1, 2002 of
approximately 70,000 MCF per day. To the extent that the NYMEX price exceeds the
written call strike prices of $3.15/MCF and $3.50/MCF there would be an
additional negative impact to the Company's cash flow and results of operations.
During the first quarter 2002, the Company received cash of approximately
$1.1 million in settlements from its derivative activities. The $5.8 million
gain from the sale of the floor and the $1.1 million of cash receipts on monthly
settlements of the derivative activities have been included in the statement of
operations in gain on derivative settlements.
(7) ACCOUNTING PRONOUNCEMENTS
In October, 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, which addresses financial
accounting and reporting for the impairment or disposal of long-lived assets.
While SFAS 144 supersedes SFAS 121, Accounting for the Impairment of Long-Lived
Assets and for Long Lived Assets to Be Disposed Of, it retains many of the
fundamental provisions of that Statement.
SFAS 144 also supersedes the accounting and reporting provisions of APB
Opinion No. 30, Reporting the Results of Operations - Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions, for the disposal of a segment of business.
However, it retains the requirement in Opinion 30 to report separately
discontinued operations and extends that reporting to a component of an entity
that either has been disposed of (by sale, abandonment, or in a distribution to
owners) or is classified as held for sale. By broadening the presentation of
discontinued operations to include more disposal transactions, the FASB has
enhanced management's ability to provide information that helps financial
statement users to assess the effects of a disposal transaction on the ongoing
operations of an entity.
Statement No. 144 is effective for fiscal years beginning after December
15, 2001 and interim periods within those fiscal years. The Company adopted SFAS
144 effective January 1, 2002. The Company expects that adoption of SFAS 144
will result in increased disclosure of material oil and gas property sales as
discontinued operations.
In August, 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. The standard applies to legal obligations
associated with the retirement of long-lived assets that result from the
acquisition, construction, development and (or) normal use of the asset. SFAS
143 requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. The fair value of the liability is added to
the carrying amount of the associated asset and this additional carrying amount
is depreciated over the life of the asset. The liability is accreted at the end
of each period through charges to operating expense. If the obligation is
settled for other than the carrying amount of the liability, the Company will
recognize a gain or loss on settlement.
Implementation of SFAS 143 is required for fiscal year 2003. To accomplish
this, the Company must identify all legal obligations for asset retirement
obligations, if any, and determine the fair value of these obligations on the
date of adoption. The determination of fair value is complex and will require
the Company to gather market information and develop cash flow models.
Additionally, the Company will be required to develop processes to track and
monitor these obligations. Due to the effort necessary to comply with the
adoption of SFAS 143, it is not practicable for management to estimate precisely
the impact of adopting SFAS 143 at the date of this report but
6
adoption is likely to increase the Company's oil and gas assets, liabilities,
DD&A expense and general and administrative expense due to the accretion of the
associated liability.
In July 2001, the FASB issued SFAS 141, Business Combinations and SFAS 142,
Goodwill and Other Intangible Assets. SFAS 141 requires that all business
combinations be accounted for under the purchase method and that certain
intangible assets in a business combination be recognized as assets apart from
goodwill. The company is required to implement SFAS 141 for all business
combinations for which the date of acquisition is July 1, 2001 or later. SFAS
142 requires that ratable amortization of goodwill be replaced with periodic
tests of the impairment of goodwill and that intangible assets other than
goodwill should be amortized over their useful lives. Implementation of SFAS 142
is required for fiscal year 2002. Adoption of SFAS 142 did not have a material
adverse impact on its financial position or results of operations.
(8) SUBSEQUENT EVENT
During May, 2002, the Company's borrowing base under its Credit Facility
was redetermined and increased to $155 million. The increase was effective
May 1, 2002.
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Cautionary Statement About Forward-Looking Statements
Some of the information in this Quarterly Report on Form 10-Q, including
information incorporated by reference, contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities and Exchange Act of 1934. The forward-looking statements speak
only as of the date made and the Company undertakes no obligation to update such
forward-looking statements. These forward-looking statements may be identified
by the use of the words "believe," "expect," "anticipate," "will,"
"contemplate," "would" and similar expressions that contemplate future events.
These future events include the following matters:
. financial position;
. business strategy;
. budgets;
. amount, nature and timing of capital expenditures;
. drilling of wells;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. cash flow and anticipated liquidity;
. prospect development and property acquisitions; and
. marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the Company's
operating results, including:
. the risks associated with exploration;
. the ability to find, acquire, market, develop and produce new
properties;
. natural gas and oil price volatility;
. uncertainties in the estimation of proved reserves and in the
projection;
. future rates of production and timing of development expenditures;
. operating hazards attendant to the natural gas and oil business;
. downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
. potential mechanical failure or under-performance of significant wells;
. climactic conditions;
. availability and cost of material and equipment;
. delays in anticipated start-up dates;
. actions or inactions of third-party operators of the Company's
properties;
. the ability to find and retain skilled personnel;
. availability of capital;
. the strength and financial resources of competitors;
. regulatory developments;
. environmental risks; and
. general economic conditions.
8
Any of the factors listed above and other factors contained in this Form
10-Q could cause the Company's actual results to differ materially from the
results implied by these or any other forward-looking statements made by the
Company or on its behalf. The Company cannot assure you that future results will
meet its expectations.
OVERVIEW
We are engaged in the acquisition, development, production and exploration
of oil and natural gas reserves. Our properties are concentrated in East Texas
and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of
Mexico. Our management and technical staff have substantial experience in each
of these areas. As of December 31, 2001, we had at that date estimated total net
proved reserves of 263 Bcfe, of which approximately 88% were natural gas and
approximately 77% were proved developed, with an estimated PV-10 value of $212
million (using SEC pricing parameters at December 31, 2001 of $2.57/Mcf and
$19.84/Bbl).
We have increased our reserves and production principally through
acquisitions. We focus on properties that have a substantial proved reserve
component and which management believes to have additional exploitation
opportunities. Recently, we have also acquired a number of drilling prospects
covered by an extensive 3-D seismic database that we believe have exploration
potential. We have assembled an experienced management team and technical staff
with expertise in property acquisitions and development, reservoir engineering,
exploration and financial management.
DESCRIPTION OF CRITICAL ACCOUNTING POLICIES
Oil and Natural Gas Properties. We utilize the successful efforts method of
accounting for our oil and natural gas properties. Under this method, all
development and acquisition costs of proved properties are capitalized and
amortized on a unit-of-production basis over the remaining life of proved
developed reserves or proved reserves, as applicable. Exploration expenses,
including geological and geophysical expenses and delay rentals, are charged to
expense as incurred. Costs of drilling exploratory wells are initially
capitalized, but charged to expense if and when the well is determined to be
unsuccessful. Expenditures for repairs and maintenance to sustain or increase
production from the existing producing reservoir are charged to expense as
incurred. Expenditures to recomplete a current well in a different or additional
proven or unproven reservoir are capitalized pending determination that economic
reserves have been added. If the recompletion to an unproven reservoir is not
successful, the expenditures are charged to expense. Expenditures for redrilling
or directional drilling in a previously abandoned well are classified as
drilling costs to a proven or unproven reservoir for determination of capital or
expense. Significant tangible equipment added or replaced is capitalized.
Expenditures to construct facilities or increase the productive capacity from
existing reserves are capitalized. Internal costs directly associated with the
development and exploitation of properties are capitalized as a cost of the
property and are classified accordingly in the Company's financial statements.
Crude oil volumes are converted to equivalent Mcfe's at the rate of one barrel
to six Mcfe.
The Company is required to assess the need for an impairment of capitalized
costs of oil and natural gas properties and other long-lived assets whenever
events or circumstances indicate that the carrying value of those assets may not
be recoverable. If impairment is indicated based on a comparison of the asset's
carrying value to its undiscounted expected future net cash flows, then it is
recognized to the extent that the carrying value exceeds fair value. Any
impairment charge incurred is recorded in accumulated depletion, depreciation,
and amortization ("DD&A") to reduce our recorded basis in the asset. Each part
of this calculation is subject to a large degree of management judgment,
including the determination of property's reserves, future cash flows, and fair
value.
Management's assumptions used in calculating oil and natural gas reserves
or regarding the future cash flows or fair value of our properties are subject
to change in the future. Any change could cause impairment expense to be
recorded, reducing our net income and our basis in the related asset. Future
prices received for production and future production costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of calculating
reserve estimates. There can be no assurance that the proved reserves will be
developed within the periods estimated or that prices and costs will remain
constant. Actual production may not equal the estimated amounts used in the
preparation of reserve projections. As these estimates change, the amount of
calculated reserves change. Any change in reserves directly impacts our estimate
of future cash flows from the property, as well as the property's fair value.
Additionally, as management's views related to future prices change, this
changes the calculation of future net cash
9
flows and also affects fair value estimates. Changes in either of these amounts
will directly impact the calculation of impairment.
DD&A expense is also directly affected by the Company's reserve estimates.
Any change in reserves directly impacts the amount of DD&A expense the Company
recognizes in a given period. Assuming no other changes, such as an increase in
depreciable base, as the Company's reserves increase, the amount of DD&A expense
in a given period decreases and vice versa. Changes in future commodity prices
would likely result in increases or decreases in estimated recoverable reserves.
The Company also uses estimates to record its accrual for oil and natural
gas revenues. The volume portion of the accrual of revenue for a given period is
based upon field production reports (both operated and non-operated), estimates
of production added via drilling or acquisitions, historical production averages
and natural production declines of the Company's properties. The price component
of the Company's accrual for revenue incorporates historical averages of the
Company's sales as compared to the monthly closing NYMEX price for natural gas
and the West Texas Intermediate index price for crude oil.
Several factors can impact the Company's ability to estimate its production
volume such as the fact that a significant portion of the Company's production
is operated by third parties. Reliance on accurate and timely data from the
operators of these properties can change the actual amounts of production for
which the Company receives payment. Additionally, production meters that are
manually read can be different than the volume metered at the Company's sales
points.
Both the Company's estimate of sold volumes and the estimate of the price
received for these sales is adjusted on an on-going basis as the Company
receives payment for the accrued volumes. Changes in the estimates of the
accrual are adjusted for in the subsequent periods as payment is received or
additional supporting data is obtained.
Bad Debt Expense. The Company routinely assesses the recoverability of all
material trade and other receivables to determine their collectibility. The
Company historically has not required collateral or other performance guarantees
from creditworthy counterparties. Many of our receivables are from joint
interest owners on property of which we are the operator. Thus, we may have the
ability to withhold future revenue disbursements to cover any non-payment of
joint interest billings. Our oil and natural gas receivables typically turnover
quickly, usually one month for oil and two months for gas; thus, signaling any
problem accounts in a timely manner. Counterparties to our derivative commodity
contracts are routinely reviewed for creditworthiness to determine the
realizability of any related derivative assets we might carry on our books. This
review of receivables and counterparties is heavily dependent on the judgment of
management. If it is determined that the carrying value of a receivable or
financial instrument might not be recoverable, we record an allowance to the
extent we believe the receivable or asset is not recoverable. The determination
as to what extent a receivable or asset might be impaired is also heavily
dependent on the judgment of management. As more information becomes known
related to a particular counterparty or customer, management will continually
reassess previous judgments and any resulting change in the related allowance
could have a material positive or negative effect on our financial position and
results of operations in the period of the change.
Derivative Activities. We use various financial instruments in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our crude oil and natural gas production. This activity is
referred to as risk management. These arrangements are structured to reduce our
exposure to commodity price decreases, but they can also limit the benefit we
might otherwise receive from commodity price increases. Our risk management
activity is generally accomplished through over-the-counter forward derivative
contracts executed with large financial institutions.
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities". This standard requires us to recognize all
of our derivative and hedging instruments in our consolidated balance sheets as
either assets or liabilities and measure them at fair value. If a derivative
does not qualify for hedge accounting, it must be adjusted to fair value through
earnings. However, if a derivative does qualify for hedge accounting, depending
on the nature of the hedge, changes in fair value can be offset against the
change in fair value of the hedged item through earnings or recognized in other
comprehensive income until such time as the hedged item is recognized in
earnings.
10
To qualify for cash flow hedge accounting, the cash flows from the hedging
instrument must be highly effective in offsetting changes in cash flows due to
changes in the underlying items being hedged. In addition, all hedging
relationships must be designated, documented, and reassesed periodically. The
Company's natural gas derivative financial instruments were not designated as
hedges at the time the instruments were executed. According to the provisions of
SFAS 133, these instruments are marked-to-market through earnings each period.
LIQUIDITY AND CAPITAL RESOURCES
We believe that our cash flows from operations are adequate to meet the
requirements of operating our business. However, future cash flows are subject
to a number of variables, including our level of production and prices, and we
cannot assure that operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures. Our
principal operating sources of cash include sales of natural gas and oil
production.
For the year 2002, we have budgeted approximately $45-65 million for
capital expenditures depending on the price of natural gas and drilling costs in
2002. The low-end of the range is based on an average natural gas price of
$2.50/Mmbtu. Pricing increases to $3.00/Mmbtu and above will move the Company's
capital expenditures into the higher end of the range. We are obligated to pay
dividends of approximately $740,000 per year on the Series D Preferred Stock
which we may pay in either cash or in additional shares of Series D Preferred
Stock during the three years ending February 1, 2003.
Our activities in 2001 have been financed through operating cash flow and
bank borrowings. Our primary source of financing for acquisitions has been
borrowing under our Credit Facility described below.
Credit Facility. The Company has in place a $250 million credit facility
(the "Credit Facility") with Bank One, NA as agent and seven other banks. The
Credit Facility, as amended, matures May 31, 2003. On March 31, 2002, the
Company's borrowing base under its Credit Facility was set at $145 million. The
borrowing base is to be redetermined semi-annually on May 1 and November 1 and
provides for interest as revised under the Credit Facility to accrue at a rate
calculated at the Company's option as either the bank's prime rate plus a low of
zero to a high of 50 basis points or LIBOR plus basis points increasing from a
low of 150 to a high of 212.5 as loans outstanding increase as a percentage of
the borrowing base. As of March 31, 2002, the borrowing base was set at $145
million. and the Company was paying an average of 3.88% per annum interest on
the principal balance of $99 million under the Credit Facility. Prior to
maturity, no payments of principal are required so long as the borrowing base
exceeds the loan balance. The borrowings under the Credit Facility are secured
by substantially all of the Company's oil and natural gas properties. At March
31, 2002, the amount available to be borrowed under the Credit Facility was
approximately $46 million.
In connection with the Credit Facility we are required to adhere to certain
affirmative and negative covenants. The loan agreement contains a number of
dividend restrictions and restrictive covenants which, among other things,
require the maintenance of minimum current and interest coverage ratios as of
March 31, 2002 we were in compliance with the covenants contained in the Credit
Facility and expect to be in compliance during the balance of 2002.
Market Risk. We generally sell our oil at local field prices paid by the
principal purchasers of oil. The majority of our natural gas production is sold
at spot prices. Accordingly, we are generally subject to the commodity prices
for these resources as they vary from time to time.
Inflation and Changes in Prices. Our revenues and the value of our oil and
gas properties have been and will be affected by changes in natural gas and
crude oil prices. Our ability to maintain current borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent on
natural gas and crude oil prices. These prices are subject to significant
seasonal and other fluctuations that are beyond our ability to control or
predict. Costs and expenses are affected by the level of inflation, which has
had a significant effect in 2001. Should current conditions in the industry be
sustained, increased competition resulting in a relative shortage of oilfield
supplies and/or services, inflationary cost pressures may continue.
Derivative Activities. Our derivative contracts in effect at March 31, 2002
will impact our liquidity for the periods covered by these contracts. NYMEX
futures prices for natural gas currently exceed our swap and call prices for the
period April 2002 to October 2002 and are outside of our collar established for
the period November 2002 to
11
March 2003. Cash prices received by the Company for its natural gas production
have historically been highly correlated with NYMEX prices. Also, currently the
notional call volumes exceed our current actual production volumes and this can
be expected to have an additional negative impact to the Company's cash flows
and results of operations. Increases in the NYMEX price above the call price
would have a negative impact on cash flow and results of operations, as the
Company will be required to pay the amount the NYMEX price exceeds the swap
price and the written call prices. The Company anticipates that the cash flow
from its physical production will provide sufficient liquidity to settle any
obligation generated by the monthly settlement terms of the Company's derivative
contract activities.
You should read the following discussion and analysis together with our
audited consolidated financial statements and the related notes for the fiscal
year ended December 31, 2001, filed in our 2001 Form 10-KSB. Our revenue,
profitability, and future rate of growth are dependent upon prevailing prices
for oil and gas, which, in turn, depend upon numerous factors such as economic,
political, and regulatory developments as well as competition from other sources
of energy. The energy markets historically have been highly volatile, and future
decreases in prices could have an adverse effect on our financial position,
results of operations, quantities of reserves that may be economically produced,
and access to capital.
The following table reflects certain summary operating data for the periods
presented:
Three Months Ended
March 31
------------------
2002 2001
------ ------
Net Production Data :
Oil and Liquids (MBbls)..................... 183 316
Natural Gas (MMcf).......................... 6,287 5,036
Equivalent Production (MMcfe)............... 7,385 6,932
Average Sales Price: (1)
Oil and Liquids (per Bbl)................... $ 18.55 $ 26.89
Natural Gas (per Mcf)....................... 2.29 7.05
Equivalent price (per Mcfe)................. 2.41 6.35
Expenses ($ per Mcfe):
Lease operations............................ $ 0.50 $ 0.63
Production, severance and ad valorem........ 0.17 0.43
Gathering, transportation and other......... 0.14 0.12
General and administrative.................. 0.30 0.22
Depreciation and depletion (2).............. 1.19 0.91
(1) Mark-to-market and derivative settlements in 2002 have been excluded.
(2) Represents depreciation, depletion and amortization, excluding impairments.
Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2001
Oil and Gas Revenues. Revenues from oil and gas operations decreased by 59%
to $18.3 million for the three months ended March 31, 2002, compared to $44.5
million for the same period during 2001. The decrease is attributable to lower
commodity prices received by the Company during the period ($18.55/Bbl and
$2.29/Mcf in 2002 versus $26.89/Bbl and $7.05/Mcf in 2001), offset by higher
daily production volumes due to drilling successes and volumes acquired in the
Classic Acquisition.
Derivatives fair value and settlements. The loss on derivatives fair value
of $21.4 million for the three months ended March 31, 2002 represents the fair
value mark-to-market adjustment made related to the April 2002 through October
2002 and November 2002 through March 2003 derivative contracts that the Company
has in place at March 31, 2002. During the first quarter the Company unwound the
floor portion of the April 2002 through October 2002 contract for a gain of
approximately $5.8 million. Additionally, approximately $1.1 million in cash
settlements were received by the Company for a derivative contract that covered
the contract period of November 2001 through March 2002, and has expired during
the first quarter of 2002. The $5.8 million gain from the sale of the floor and
the $1.1 million of cash receipts on monthly settlements of the derivative
activities have been included in the statement of operations in gain on
derivative settlements. There were no derivative contracts in place at March 31,
2001.
12
Production Expense. Production expense for the three months ended March 31,
2002, decreased by 15% to $3.7 million compared to $4.4 million during the same
period of 2001. Lease operating expenses on an $/Mcfe basis decreased to
$0.50/Mcfe from $0.63/Mcfe, while production, severance and ad valorem taxes
decreased to $0.17/Mcfe from $0.43/Mcfe. Lower per unit operating costs
associated with the Company's acquired properties and higher per unit operating
costs of properties sold by the Company during the 2nd and 3rd quarters of 2001
are attributed to the current period decreases. Lower realized commodity prices
during the three months ended March 31, 2002 of $2.41/Mcfe vs. $6.35/Mcfe in
2001 is the principal reason for the decrease in taxes.
General and Administrative Expense. General and administrative expense for
the three months ended March 31, 2002 increased by $0.7 million compared to the
same period in 2001. The increase is attributable to continued increased
staffing levels as a result of the Company's significant growth from
acquisitions.
Interest. Interest expense during the three month period ended March 31,
2002 decreased to $1.0 million compared to $2.2 million for the same period
ending March 31, 2001. The decrease is attributable to lower average debt levels
in 2002 combined with lower interest rates quarter over quarter (approximately
3.69% in 2002 versus 7.83% in 2001).
Depreciation, Depletion and Amortization Expense. Depreciation, depletion
and amortization expense ("DD&A") for the three months ended March 31, 2002 was
$8.8 million compared to $6.3 million for the same period of 2001. The increase
in DD&A recorded is attributed to the Company's production growth and the impact
of its developmental drilling activities whereby the Company converts proved
undeveloped reserves into proved developed producing reserves. Additionally, the
deferred tax write-up related to the Classic Acquisition impacted the full
quarter 2002 DD&A expense compared to only two months of the first quarter 2001.
Income Taxes. For the three months ended March 31, 2002, the Company
recorded a tax benefit of $5.5 million compared to a tax provision of $9.9
million during the same period in 2001. The benefit recorded in 2002 represents
the Company's net income for the three months ended at its expected effective
tax rate for 2002 of approximately 39%.
Dividends to Preferred Stockholders. Dividends to preferred stockholders of
approximately $0.2 million in the three months ended March 31, 2002 are
comparable to the $0.2 million for the three months ended March 31, 2001. The
Company currently has only the Series D Dividend to pay which is paid
semi-annually on March 31 and September 30.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following market risk disclosures should be read in conjunction with
the quantitative and qualitative disclosures about market risk contained in the
Company's 2001 Annual Report on Form 10KSB, as well as with the consolidated
financial statements and notes thereto included in this quarterly report on Form
10-Q.
Interest Rate Risk
The Company is exposed to interest rate risk on short-term and long-term
debt carrying variable interest rates. At March 31, 2002, the Company's variable
rate debt had a carrying value of $99 million, which approximated its fair
value.
Commodity Price Risk
The Company manages through the use of derivative contracts a portion of
the market risks associated with its natural gas sales. As of March 31, 2002,
outstanding natural gas option contracts and swap agreements had a fair value
loss of $18.3 million. The aggregate effect of an approximately 13% change
(NYMEX prices at April 30, 2002) in gas prices would result in a change of
approximately $6.9 million in the fair value of these financial instruments at
March 31, 2002. Because these natural gas option contracts and swap agreements
were not designated hedge derivatives, changes in their fair value is recognized
in the consolidated income statements.
13
PART II. OTHER INFORMATION
ITEMS 1. THROUGH 5.
Not Applicable.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits: The following documents are filed as exhibits to this report:
2.1 Agreement and Plan of Merger, dated December 21, 1999, by and between
3TEC Energy Corporation, 3TM Acquisition L.L.C., Magellan Exploration,
LLC and ECIC Corporation, EnCap Energy Capital Fund III, L.P., EnCap
Energy Acquisition III-B, Inc., BOCP Energy Partners, L.P., and
Pel-Tex Partners, L.L.C. (Incorporated by reference to Exhibit C to
Form DEF14A, filed January 11, 2000.)
2.2 Agreement and Plan of Merger, dated November 24, 1999, by and between
3TEC Energy Corporation, a Delaware corporation, and Middle Bay Oil
Company, Inc., an Alabama corporation. (Incorporated by reference to
Exhibit A to Form DEF14A, filed October 25, 1999.)
2.3 First Amendment to Agreement and Plan of Merger, effective as of
January 14, 2000, by and among 3TEC Energy Corporation, 3TM
Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation, EnCap
Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc.,
BOCP Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated
by reference to Exhibit 2.1 to Form 8-K filed February 4, 2000.)
2.4 Second Amendment to Agreement and Plan of Merger, effective as of
February 2, 2000, by and among 3TEC Energy Corporation, 3TM
Acquisition L.L.C., Magellan Exploration, LLC, ECIC Corporation, EnCap
Energy Capital Fund III, L.P., EnCap Energy Acquisition III-B, Inc.,
BOCP Energy Partners, L.P., and Pel-Tex Partners, L.L.C. (Incorporated
by reference to Exhibit 2.2 to Form 8-K filed February 4, 2000.)
2.5 Form of Agreement of Sale and Purchase by and between C.W. Resources,
Inc., Westerman Royalty, Inc., and Carl A. Westerman and 3TEC Energy
Corporation. (Incorporated by Reference to Exhibit 10.32 to Form S-2
filed April 28, 2000.)
2.6 Form of Stock Purchase Agreement by and between 3TEC Energy
Corporation and Classic Resources, Inc., Natural Gas Partners IV,
L.P., Natural Gas Partners V, L.P., and certain individual
signatories. (Incorporated by reference to Exhibit 2.1 to Form 8-K
filed February 13, 2001.)
2.7 Merger Agreement, dated October 25, 2001, by and among 3TEC Energy
Corporation, 3NEX Acquisition Corporation and Enex Resources
Corporation. (Incorporated by reference to Exhibit 2.7 to Form 10-KSB
filed April 1, 2002.)
2.8 Certificate of Ownership and Merger Merging Enex Resources Corporation
into 3TEC Energy Corporation filed with the Delaware Secretary of
State January 31, 2002. (Incorporated by reference to Exhibit 2.8 to
Form 10-KSB filed April 1, 2002.)
3.1 Certificate of Incorporation of 3TEC Energy Corporation. (Incorporated
by reference to Exhibit 3.1 of Form 8-K filed December 6, 1999.)
3.2 Certificate of Amendment to the Certificate of Incorporation of 3TEC
Energy Corporation. (Incorporated by reference to Exhibit 3.3 of Form
10-KSB filed March 30, 2000.)
3.3 Certificate of Amendment of the Certificate of Incorporation of 3TEC
Energy Corporation, dated June 14, 2001 (Incorporated by reference to
Exhibit 3.5 Form 10-QSB filed August 8, 2001.)
3.4 Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy
Corporation. (Incorporated by reference to Exhibit 3.3 of Form 8-K/A
filed December 16, 1999.)
3.5 Bylaws of the Company. (Incorporated by reference to Exhibit C to Form
DEF14A filed October 25, 1999.)
3.6 Amendment No. 1 to Bylaws of the Company. (Incorporated by reference
to Exhibit 4.5 Form S-8 filed October 26, 2001.)
14
3.7 Amendment No. 2 to Bylaws of 3TEC Energy Corporation. (Incorporated by
reference to Exhibit 3.6 to Form 10-QSB filed August 8, 2001.)
4.1 Certificate of Designation of Series B Preferred Stock of 3TEC Energy
Corporation. (Incorporated by reference to Exhibit 3.1 to Form 8-K/A
filed December 16, 1999.)
4.2 Certificate of Designation of Series D Preferred Stock of 3TEC Energy
Corporation. (Incorporated by reference to Exhibit 4.3 to Form 10-QSB
filed May 15, 2000.)
10.1 Securities Purchase Agreement, dated July 1, 1999 by and between the
Company and 3TEC Energy Corporation. (Incorporated by reference to
Exhibit C Form DEF14A filed July 19, 1999.)
10.2 Securities Purchase Agreement, dated August 27, 1999 by and between
the Company and Shoemaker Family Partners, LP. (Incorporated by
reference to Exhibit 10.2 to Form 10-QSB filed November 15, 1999.)
10.3 Securities Purchase Agreement, dated August 27, 1999 by and between
the Company and Shoeinvest II, LP. (Incorporated by reference to
Exhibits to Exhibit 10.3 to Form 10-QSB filed November 15, 1999.)
10.4 Securities Purchase Agreement, dated October 19, 1999 between The
Prudential Insurance Company of America and the Company. (Incorporated
by reference to Exhibit 10.1 to Form 8-K filed November 2, 1999.)
10.5 Shareholders Agreement, dated August 27, 1999 by and among the
Company, 3TEC Energy Corporation and the Major Shareholders.
(Incorporated by reference to Exhibit 10.5 to Form 10-QSB filed
November 15, 1999.)
10.6 Agreement to Terminate Shareholders' Agreement, dated April 30, 2001,
by and among the Company and the Major Shareholders. (Incorporated by
reference to Exhibit 10.6 to Form 10-QSB filed November 8, 2001.)
10.7 Registration Rights Agreement, dated August 27, 1999 by and among the
Company, 3TEC Energy Corporation, the Major Shareholders, Shoemaker
Family Partners, LP and Shoeinvest II, LP. (Incorporated by reference
to Exhibit 10.6 to Form 10-QSB filed November 15, 1999.)
10.8 Amendment to Registration Rights Agreement, dated October 19, 1999 by
and among the Company, W/E Energy Company, L.L.C. f/k/a 3TEC Energy
Company L.L.C., f/k/a 3TEC Energy Corporation, Shoemaker Family
Partners, LP, Shoeinvest II, LP, and The Prudential Insurance Company
of America. (Incorporated by reference to Exhibit 10.2 to Form 8-K
filed November 2, 1999.)
10.9 Participation Rights Agreement, dated October 19, 1999 by and among
the Company, The Prudential Insurance Company of America and W/E
Energy Company L.L.C. (Incorporated by reference to Exhibit 10.3 to
Form 8-K filed November 2, 1999.)
10.10 Employment Agreement, dated April 15, 2000 by and between Floyd C.
Wilson and the Company. (Incorporated by reference to Exhibit 10.9 to
Form S-2 filed April 28, 2000.)
10.11 Employment Agreement, dated May 1, 2000, by and between R.A. Walker
and the Company. (Incorporated by reference to Exhibit 10.9 to Form
S-2 filed April 28, 2000.)
10.12 Restated Credit Agreement by and among Middle Bay Oil Company, Inc.,
Enex Resources Corporation and Middle Bay Production Company, Inc. as
borrowers, and Bank One, Texas, N.A. and other institutions as
lenders. (Incorporated by reference to Exhibit 10.1 to Form 8-K/A
filed December 17, 1999.)
10.13 Subordination Agreement, dated August 27, 1999 by and among
Shoeinvest II, LP, Compass Bank, and Bank of Oklahoma, National
Association. (Incorporated by reference to Exhibit 10.16 to Form
10-QSB filed November 15, 1999.)
10.14 Subordination Agreement, dated August 27, 1999 by and among
Shoeinvest II, LP, Compass Bank, and Bank of Oklahoma, National
Association. (Incorporated by reference to Exhibit 10.16 to Form
10-QSB filed November 15, 1999.)
15
10.15 Letter Amendment No. 1 to Middle Bay Oil Company, Inc. Securities
Purchase Agreement, dated November 23, 1999, by and between Middle Bay
Oil Company, Inc. (n/k/a 3TEC Energy Corporation) and The Prudential
Insurance Company of America (Incorporated by reference to Exhibit
10.21 to Form S-2 filed April 28, 2000 and replacing the unexecuted
Exhibit 10.17 of Form 10-QSB filed November 15, 1999.)
10.16 Intercreditor Agreement, dated as of November 23, 1999, among Middle
Bay Oil Company, Inc., Bank One Texas, N.A. and 3TEC Energy Company
L.L.C. (Incorporated by reference to Exhibit 10.18 to Form S-2 filed
April 28, 2000.)
10.17 Intercreditor Agreement, dated as of November 23, 1999, among Middle
Bay Oil Company, Inc., Bank One Texas, N.A. and Shoemaker Family
Partners, LP. (Incorporated by reference to Exhibit 10.19 to Form S-2
filed April 28, 2000.)
10.18 Intercreditor Agreement, dated as of November 23, 1999, among Middle
Bay Oil Company, Inc., Bank One Texas, N.A. and Shoeinvest II, LP.
(Incorporated by reference to Exhibit 10.20 to Form S-2 filed April
28, 2000.)
10.19 Amendment to Securities Purchase Agreement, dated as of November 23,
1999, among Middle Bay Oil Company, Inc. and 3TEC Energy Company
L.L.C. (Incorporated by reference to Exhibit 10.22 to Form S-2 filed
April 28, 2000.)
10.20 Amendment to Securities Purchase Agreement, dated as of November 23,
1999, among Middle Bay Oil Company, Inc. and Shoemaker Family
Partners, LP. (Incorporated by reference to Exhibit 10.23 to Form S-2
filed April 28, 2000.)
10.21 Amendment to Securities Purchase Agreement, dated as of November 23,
1999, among Middle Bay Oil Company, Inc. and Shoeinvest II, LP.
(Incorporated by reference to Exhibit 10.24 to Form S-2 filed April
28, 2000.)
10.22 Amended and Restated 1995 Stock Option and Stock Appreciation Rights
Plan. (Incorporated by reference to Exhibit B to Form DEF 14A filed
May 5, 1997.)
10.23 Amendment No. 1 to the Amended and Restated 1995 Stock Option and
Stock Appreciation Rights Plan. (Incorporated by reference to Exhibit
B to Form DEF 14A filed May 5, 1998.)
10.24 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock
Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.7
Form S-8 filed November 6, 2000.)
10.25 Amendment No. 3 to Amended and Restated 1995 Stock Option and Stock
Appreciation Rights Plan. (Incorporated by reference to Exhibit 99.8
Form S-8 filed November 6, 2000.)
10.26 1999 Stock Option Plan. (Incorporated by reference to Exhibit E to
Form DEF 14A filed October 25, 1999.)
10.27 Amendment No. 1 to 3TEC Energy Corporation 1999 Stock Option Plan.
(Incorporated by reference to Exhibit 99.4 Form S-8 filed November 6,
2000.)
10.28 2000 Stock Option Plan (Incorporated by reference to Exhibit A to
Form DEF 14A filed on May 1, 2000.)
10.29 Amendment No. 1 to 3TEC Energy Corporation 2000 Stock Option Plan.
(Incorporated by reference to Exhibit 99.2 Form S-8 filed November 6,
2000.)
10.30 3TEC Energy Corporation 2001 Stock Option Plan. (Incorporated by
reference to Exhibit 99.1 Form S-8 filed October 26, 2001.)
10.31 3TEC Energy Corporation 2000 Non-Employee Directors Stock Option
Plan. (Incorporated by reference to Exhibit 99.2 Form S-8 filed
October 26, 2001.)
10.32 Amendment No. 1 to 3TEC Energy Corporation 2000 Non-Employee
Directors' Stock Option Plan.*
16
10.33 Second Restated Credit Agreement among 3TEC Energy Corporation, Enex
Resources Corporation, Middle Bay Production Company, Inc., and
Magellan Exploration, LLC, as Borrowers, and Bank One, Texas, N.A. and
the Institutions named therein, as Lenders, Bank One, Texas, N.A., as
Administrative Agent, Bank of Montreal as Syndication Agent and Banc
One Capital Markets, Inc., as Arranger, dated May 31, 2000.
(Incorporated by reference to Exhibit 10.28 to Form S-2/A filed June
6, 2000.)
10.34 First Amendment to Shareholders' Agreement by and among 3TEC Energy
Corporation, the W/E Shareholders and the Major Shareholders, dated
May 30, 2000. (Incorporated by reference to Exhibit 10.29 to Form
S-2/A filed June 6, 2000.)
10.35 Third Restated Credit Agreement among 3TEC Energy Corporation, Enex
Resources Corporation and 3TEC/CRI Corporation, as Borrowers, and Bank
One, N.A. and the Institutions named therein, as Lenders, Bank One,
N.A., as Administrative Agent, Bank of Montreal as Syndication Agent
and Banc One Capital Markets, Inc., as Arranger, dated March 12, 2001.
(Incorporated by reference to Exhibit 10.27 to Form 10-QSB filed May
14, 2001.)
* Filed herewith.
(b) The following reports were filed on Form 8-K during the first quarter of
2002:
On January 4, 2002, the Company filed a Form 8-K under item 5 describing the
announcement of the completed merger of a wholly-owned subsidiary of the Company
with Enex Resources and the announcement of certain Board of Directors changes
effective January 1, 2002.
17
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed by
the undersigned, thereunto duly authorized, as of May 10, 2002.
3TEC ENERGY CORPORATION
(Registrant)
By: /s/ Floyd C. Wilson
------------------------------
Floyd C. Wilson
Chairman and Chief Executive Officer
By: /s/ R.A. Walker
------------------------------
R.A. Walker
President, Chief Financial Officer, Director
By: /s/ Shane M. Bayless
------------------------------
Shane M. Bayless
Vice President-Controller, Treasurer and
Principal Accounting Officer
18