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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 June 30, 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
16,624,194 shares as of July 19, 2002
3TEC ENERGY CORPORATION AND SUBSIDIARIES
INDEX
PAGE
NO.
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets-
June 30, 2002 (Unaudited) and December 31, 2001 (Audited) .......... 1
Consolidated Statements of Operations (Unaudited)-
Three and six months ended June 30, 2002 and 2001 .................. 2
Consolidated Statements of Cash Flows (Unaudited)-
Six months ended June 30, 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 ........................ 8
Item 3. Quantitative and Qualitative Disclosures About Market Risk ........ 15
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders ............... 15
Item 6. Exhibits and Reports on Form 8-K ................................. 16
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
JUNE 30, DECEMBER 31,
2002 2001
------------- ----------------
(Unaudited) (Audited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents .............................................. $ 3,707 $ 17,762
Accounts receivable .................................................... 13,555 16,835
Income taxes receivable ................................................ 164 4,464
Other current assets ................................................... 2,163 4,473
-------- --------
Total current assets ............................................. 19,589 43,534
PROPERTY AND EQUIPMENT (AT COST)
Oil and gas-successful efforts method .................................. 407,450 385,264
Other property and equipment ........................................... 3,833 3,549
-------- --------
411,283 388,813
Accumulated depreciation, depletion and amortization ........................ (89,751) (71,039)
-------- --------
Net Property and Equipment .................................................. 321,532 317,774
OTHER ASSETS ................................................................ 1,333 1,730
-------- --------
TOTAL ASSETS ................................................................ $342,454 $363,038
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable ....................................................... $ 11,676 $ 25,052
Accrued liabilities .................................................... 638 1,322
Series C Preferred stock redemption payable ............................ 1,284 1,349
Derivative fair value liability ........................................ 9,318 --
Other current liabilities .............................................. 939 1,468
-------- --------
Total current liabilities ................................................... 23,855 29,191
LONG-TERM DEBT .............................................................. 99,000 108,000
DEFERRED INCOME TAXES ....................................................... 41,581 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, 207,905 and 266,667
shares issued and outstanding at June 30,2002 and
December 31, 2001, respectfully. $1,559 aggregate liquidation preference 2,828 3,627
Convertible preferred stock Series D, 5% $24.00 stated value, 614,776 shares
issued and outstanding at June 30, 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, 16,694,001 and
16,547,595 shares issued at June 30, 2002
and December 31, 2001, respectively .................................... 334 331
Additional paid-in capital ............................................. 154,377 151,412
Retained earnings ...................................................... 15,165 18,906
Treasury stock; 69,796 shares at June 30, 2002 and December 31, 2001,
respectively .......................................................... (1,049) (1,049)
Deferred compensation .................................................. (1,122) --
-------- --------
TOTAL STOCKHOLDERS' EQUITY .................................................. 178,018 180,712
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .................................. $342,454 $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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
2002 2001 2002 2001
-------------- ------------- ----------- --------------
REVENUES
Oil, natural gas and plant income ........... $ 28,171 $ 33,256 $ 46,478 $ 77,775
Gain (loss) on sale of properties ........... (222) 6,749 (145) 6,836
Gain (loss) on derivative fair value ........ 9,011 -- (12,400) --
Gain (loss) on derivatives settlements ...... (4,716) -- 2,168 --
Other ....................................... 12 327 199 452
----------- ----------- ---------- -----------
TOTAL REVENUES ................................... 32,256 40,332 36,300 85,063
----------- ----------- ---------- -----------
EXPENSES
Production -
Lease operations ......................... 3,708 4,786 7,431 9,143
Production, severance and ad valorem taxes 2,255 2,176 3,502 5,165
Gathering, transportation and other ...... 1,066 1,013 2,099 1,828
Geological and geophysical .................. 648 154 828 369
Dry hole and impairments .................... 1,562 -- 1,616 --
Surrendered and expired acreage ............. 589 -- 589 --
General and administrative .................. 2,506 1,807 4,713 3,349
Restricted stock compensation ............... 432 -- 432 --
Interest .................................... 1,019 1,893 2,043 4,074
Depreciation, depletion and amortization .... 9,629 7,007 18,384 13,346
Other ....................................... 191 -- 191 --
----------- ----------- ---------- -----------
TOTAL EXPENSES ................................... 23,605 18,836 41,828 37,274
INCOME (LOSS) BEFORE INCOME TAX EXPENSE,
MINORITY INTEREST AND DIVIDENDS
TO PREFERRED STOCKHOLDERS ...................... 8,651 21,496 (5,528) 47,789
Minority Interest ................................ -- 118 -- 301
Income tax (benefit) expense ..................... 3,374 8,168 (2,157) 18,103
----------- ----------- ---------- -----------
NET INCOME (LOSS) ................................ 5,277 13,210 (3,371) 29,385
Dividends to preferred stockholders .............. 185 184 370 375
----------- ----------- ---------- -----------
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS $ 5,092 $ 13,026 $ (3,741) $ 29,010
=========== =========== =========== ===========
NET INCOME (LOSS) PER COMMON SHARE
BASIC $ 0.31 $ 0.89 $ (0.23) $ 1.99
=========== =========== =========== ===========
DILUTED $ 0.27 $ 0.70 $ (0.23) $ 1.56
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC 16,560,905 14,627,066 16,525,827 14,612,342
=========== =========== =========== ===========
DILUTED 19,241,113 19,171,852 16,525,827 19,123,258
=========== =========== =========== ===========
SEE ACCOMPANYING NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
2
3TEC ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
SIX MONTHS ENDED
JUNE 30
(Unaudited) (Unaudited)
2002 2001
------------- --------------
OPERATING ACTIVITIES
Net income (loss) ................................................................ $ (3,371) $ 29,385
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization .................................... 18,054 12,994
Amortization of debt issue costs ............................................ 330 352
Dry hole and impairments .................................................... 1,616 --
Surrendered and expired acreage ............................................. 589 --
Loss on derivative fair value ............................................... 12,400 --
(Gain) Loss on sale of properties ........................................... 145 (6,836)
Deferred income taxes ....................................................... (3,228) 11,159
Restricted stock compensation ............................................... 432 --
Minority interest ........................................................... -- 301
Common stock issued in lieu of directors fees ............................... 13 --
Changes in current assets and liabilities net, of acquisition effects:
Accounts receivable and other current assets .............................. 6,875 13,815
Accounts payable, accrued liabilities and other current liabilities ....... (14,842) (1,011)
-------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES ........................................ 19,013 60,159
INVESTING ACTIVITIES
Proceeds from sales of properties ........................................... 959 11,654
Acquisition of Classic Resources, Inc., net of cash acquired ................ -- (58,584)
Acquisition of oil and gas properties ....................................... -- (4,477)
Development of oil and gas properties ....................................... (25,157) (29,675)
Additions to other assets ................................................... (287) (755)
-------- --------
NET CASH USED IN INVESTING ACTIVITIES ............................................ (24,485) (81,837)
FINANCING ACTIVITIES
Proceeds from long-term debt ................................................ 18,500 82,000
Principal payments on long-term debt ........................................ (27,500) (56,000)
Proceeds from exercise of stock options and warrants ........................ 600 248
Preferred stock dividends ................................................... (183) (188)
-------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES .............................. (8,583) 26,060
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ................................. (14,055) 4,382
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD ................................. 17,762 4,436
-------- --------
CASH AND CASH EQUIVALENTS AT ENDING OF PERIOD .................................... $ 3,707 $ 8,818
======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest .................................................................... $ 2,003 $ 3,707
======== ========
Income taxes ................................................................ $ 963 $ 6,208
======== ========
Non-cash investing and financing activities:
Preferred dividends incurred but not paid ................................... $ 187 $ 186
======== ========
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 June 30, 2002 and December 31, 2001, consolidated results of
operations and consolidated cash flows for the periods ended June 30, 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 six months ended June 30, 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 restated its financial results for the first two quarters of
2001. The changes reflected 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 and six month periods ended June 30, 2001:
Three Months Ended Six Months Ended
June 30, 2001 June 30, 2001
------------------ -----------------
Total Revenues ...................... $3,494 $7,839
Costs and operating expenses ........ 961 1,654
Operating income .................... 2,533 6,185
Net Income .......................... 1,571 3,843
Net Income per share (fully diluted). 0.08 0.20
(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 June 30, 2002, the Company had a weighted average of 2,623,463 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 and six-month periods
ended June 30, 2002 and 2001 was determined as follows (in thousands):
4
3TEC ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
---- ---- ---- ----
Basic net income (loss) attributable
to common shareholders ..................................... 5,092 13,026 (3,741) 29,010
Plus preferred stock dividends .................................... 185 184 - 375
Plus interest expense (net of tax) on
subordinated convertible notes ............................. - 184 - 365
------- ------- ------- -------
Fully diluted net income (loss) attributable
to common shareholders ..................................... 5,277 13,394 (3,741) 29,750
======= ======= ======= =======
Basic shares outstanding (weighted average shares) ................ 16,561 14,627 16,526 14,612
Plus potentially dilutive securities:
o Dilutive options and warrants applying
treasury stock method .................................. 1,932 2,326 - 2,290
o Shares from conversion of subordinated
convertible notes ...................................... - 1,466 - 1,468
o Shares from conversion of Series B
preferred stock ........................................ 121 131 - 131
o Shares from conversion of Series D
preferred stock ........................................ 615 622 - 622
o Non-vested restricted stock .............................. 12 - -
------- ------- ------- -------
Fully diluted shares outstanding (weighted average shares) ........ 19,241 19,172 16,526 19,123
======= ======= ======= =======
(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's 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
six months ended June 30, 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
Six Months Ended
June 30, 2001
(Unaudited)
-----------------
Total revenues .................................................. $ 87,133
Net income attributable to common stockholders .................. 26,187
Net income per basic share attributable to common stockholders .. 1.84
5
(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 June 30, 2002, 207,905 Series B
shares were outstanding.
During May 2002, the Company issued 95,000 shares of restricted stock to
certain members of the Company's management valued at $1.6 million. At June,
30, 2002, the Company has recognized approximately $0.4 million as restricted
stock compensation expense and will recognize the remaining $1.2 million over
the remaining service and vesting periods of two years.
(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.
The following table details the Company's derivative contract positions
which were in place at June 30, 2002.
Natural Gas Derivatives
- -----------------------
Period Mmbtu Per Day Total Mmbtu Type NYMEX Price
------ ------------- ----------- ---- -----------
July 2002 - October 2002 56,000 6,888,000 Call $3.50
July 2002 - October 2002 28,000 3,444,000 Call $3.15
July 2002 - October 2002 56,000 6,888,000 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 July 1, 2002 to October 30, 2002 the Company has
notional volumes of 84,000 Mmbtu per day under written call derivatives in
addition to 56,000 Mmbtu related to the swap contract in place for the same
period. These notional volumes exceed actual production volumes at July 1, 2002
of approximately 70,000 MCF per day. To the extent that the actual 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 2002, the Company has paid net cash settlements of approximately
$3.6 million related to its derivative activities. The $5.8 million gain from
the sale of the put floor and the $3.6 million of net cash paid for settlements
on the derivative activities have been included in the statement of operations
as gain on derivative settlements. At July 31, 2002 the fair value of the
Company's open derivative positions was a $3.0 million mark-to-market loss, with
the closed contract months for July and August having settled for total cash
payments of $2.3 million. A 10% increase to the July 31 NYMEX prices would
result in settlements of the open contract months for the Company's derivatives
to increase by $1.2 million while a 10% decrease would result in $2.8 million
decrease to these contract 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
6
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 adoption is
likely to increase the Company's oil and gas assets, liabilities, depreciation,
depletion, and amortization ("DD&A) (hereafter defined) expense and acretion
expense due to the accretion of the associated liability.
(8) CREDIT FACILITY
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.
During August, 2002, the Company extended the maturity date of its Credit
Facility with its existing bank group until July 2, 2003 under the same terms
and conditions. The Company anticipates entering into an extension of the
maturity date for the Credit Facility during the third quarter of 2002 which is
expected to move the maturity date to August 31, 2004.
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:
o financial position;
o business strategy;
o budgets;
o amount, nature and timing of capital expenditures;
o drilling of wells;
o natural gas and oil reserves;
o timing and amount of future production of natural gas and oil;
o operating costs and other expenses;
o cash flow and anticipated liquidity;
o prospect development and property acquisitions; and
o marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the Company's
operating results, including:
o the risks associated with exploration;
o the ability to find, acquire, market, develop and produce new
properties;
o natural gas and oil price volatility;
o uncertainties in the estimation of proved reserves and in the
projection;
o future rates of production and timing of development expenditures;
o operating hazards attendant to the natural gas and oil business;
o downhole drilling and completion risks that are generally not
recoverable from third parties or insurance;
o potential mechanical failure or under-performance of significant wells;
o climactic conditions;
o availability and cost of material and equipment;
o delays in anticipated start-up dates;
o actions or inactions of third-party operators of the Company's
properties;
o the ability to find and retain skilled personnel;
o availability of capital;
o the strength and financial resources of competitors;
o regulatory developments;
o environmental risks; and
o general economic conditions.
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.
8
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 Securities and Exchange Commission pricing) pricing parameters at
December 31, 2001 $2.57/Mcf and $19.84/Bbl).
Historically, 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 a 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 flows and also affects fair value
estimates. Changes in either of these amounts will directly impact the
calculation of impairment.
9
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 reassessed periodically. The
Company's natural gas derivative financial instruments were not designated as
hedges at the time the instruments were executed and, as such, 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 2002 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 June 30, 2002, the
Company's borrowing base under its Credit Facility was set at $155 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 June 30, 2002, the borrowing base was set at $155
million. and the Company was paying an average of 3.55% 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 June
30, 2002, the amount available to be borrowed under the Credit Facility was
approximately $56 million.
During August, 2002, the Company extended the maturity date of its Credit
Facility with its existing bank group until July 2, 2003 under the same terms
and conditions. The Company anticipates entering into an extension of the
maturity date for the Credit Facility during the third quarter of 2002 which is
expected to move the maturity date to August 31, 2004.
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
June 30, 2002 we were in compliance with the covenants contained in the Credit
Facility.
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. Should
current conditions in the industry be sustained, increased
11
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 June 30, 2002
will impact our liquidity for the periods covered by these contracts. NYMEX
futures prices for natural gas at July 31, 2002 currently exceed our swap and
call prices for the period July 2002 to October 2002 and are outside of our
collar established for the period November 2002 to 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. Realized NYMEX prices 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. At
July 31, the fair value of the Company's open derivative positions was a $3.0
million mark-to-market loss, with the closed contract months for July and August
having settled for cash payments of $2.3 million. A 10% increase to the July 31
NYMEX prices would result in settlements of the open contract months for the
Company's derivatives to increase by $1.2 million while a 10% decrease would
result in a $2.8 million decrease to these contract settlements.
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 Six Months Ended
June 30, June 30,
--------------------- --------------------
2002 2001 2002 2001
--------- --------- ------- ---------
Net Production Data:
Oil and Liquids (MBbls) ............ 212 262 395 577
Natural Gas (MMcf) ................. 6,480 5,617 12,767 10,654
Equivalent Production (MMcfe) ...... 7,752 7,187 15,137 14,117
Average Sales Price: (1)
Oil and Liquids (per Bbl) .......... $23.44 $24.99 $21.17 $26.03
Natural Gas (per Mcf) .............. 3.47 4.66 2.89 5.79
Equivalent price (per Mcfe) ........ 3.54 4.55 2.99 5.43
Expenses ($ per Mcfe):
Lease operations ................... $0.48 $0.67 $0.49 $0.65
Production, severance and ad valorem 0.29 0.30 0.23 0.37
Gathering, transportation and other. 0.14 0.14 0.14 0.13
General and administrative ......... 0.32 0.25 0.31 0.24
Depreciation and depletion (2) ..... 1.24 0.98 1.21 0.95
(1) Mark-to-market and derivative settlements in 2002 have been excluded.
(2) Represents depreciation, depletion and amortization, excluding impairments.
Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2001
Oil and Gas Revenues. Revenues from oil and gas operations decreased by 15%
to $28.2 million for the three months ended June 30, 2002, compared to $33.3
million for the same period during 2001. The decrease is attributable to lower
commodity prices received by the Company during the period ($23.44/Bbl and
$3.47/Mcf in
12
2002 versus $24.99/Bbl and $4.66/Mcf in 2001), offset somewhat by higher daily
production volumes due to recent drilling successes.
Gain (loss) on Sale of Properties. The loss on sale of properties for the
three months ended June 30, 2002 decreased to $0.2 million compared to a gain of
$6.7 million during the same period of 2001. The decrease is a result of the
Company's divestment of non-strategic oil and gas properties in 2001 vs. minimal
divestiture activity in 2002.
Derivatives Fair Value and Settlements. The gain on derivatives fair value
of $9.0 million for the three months ended June 30, 2002 represents the fair
value mark-to-market adjustment made related to the July 2002 through October
2002 and November 2002 through March 2003 derivative contracts that the Company
has in place at June 30, 2002. During the second quarter of 2002, approximately
$4.7 million in cash settlements were paid by the Company for derivative
contracts that covered the contract period of April 2002 through October 2002.
There were no derivative contracts in place at June 30, 2001.
Production Expense. Production expense for the three months ended June 30,
2002, decreased by 13% to $7.0 million compared to $8.0 million during the same
period of 2001. Lease operating expenses on an $/Mcfe basis decreased to
$0.48/Mcfe from $0.67/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.
Geological and Geophysical. Geological and Geophysical expense for the
three months ended June 30, 2002 increased to $0.6 million compared to $0.2
million in 2001. The increase is attributed primarily to the Company's
exploratory activities and related costs incurred for acquisition and
reprocessing of seismic data.
Dry Hole and Impairments. Dry hole and impairments increased in the three
months ended June 30, 2002 as a result of the drilling of one exploratory dry
hole in the period and the impairment charge recognized as a result of changes
in the economics of two minor fields due to an increase in lease operating
expenses and a well shut in within one of these two fields.
Surrendered and Expired Acreage. The increase in surrendered and expired
acreage is attributed to acreage related to the exploratory dry hole which was
drilled in the period whereby the Company determined that no further activity
would be initiated on the prospect.
General and Administrative Expense. General and administrative expense for
the three months ended June 30, 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.
Restricted Stock Expense. During the three months ended June 30, 2002, the
Company recognized restricted stock compensation expense of $0.4 million which
is attributed to the share grants made to certain officers of the Company that
were approved at the Company's annual meeting in May, 2002.
Interest. Interest expense during the three month period ended June 30,
2002 decreased to $1.0 million compared to $1.9 million for the same period
ending June 30, 2001. The decrease is attributable to lower interest rates
quarter over quarter (approximately 3.9% in 2002 versus 6.5% in 2001) offset
somewhat by slightly higher average debt levels.
Depreciation, Depletion and Amortization Expense. DD&A for the three months
ended June 30, 2002 was $9.6 million compared to $7.0 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.
Income Taxes. For the three months ended June 30, 2002, the Company
recorded a tax provision of $3.4 million compared to a tax provision of $8.2
million during the same period in 2001. The provision 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%.
13
Dividends to Preferred Stockholders. Dividends to preferred stockholders of
approximately $0.2 million in the three months ended June 30, 2002 are
comparable to the $0.2 million for the three months ended June 30, 2001. The
Company currently has only the Series D dividend to pay which is paid
semi-annually on March 31 and September 30.
Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2001
Oil and Gas Revenues. Revenues from oil and gas operations decreased by 40%
to $46.5 million for the six months ended June 30, 2002, compared to $77.8
million for the same period during 2001. The decrease is attributable to lower
commodity prices received by the Company during the period ($21.17/Bbl and
$2.89/Mcf in 2002 versus $26.03/Bbl and $5.79/Mcf in 2001), partially offset by
higher daily production volumes due to recent drilling successes.
Gain (loss) on Sale of Properties. The loss on sale of properties for the
six months ended June 30, 2002 decreased to $0.1 million compared to a gain of
$6.7 million during the same period of 2001. The decrease is a result of the
Company's divestment of non-strategic oil and gas properties in 2001 vs. minimal
divestiture activity in 2002.
Derivatives Fair Value and Settlements. The loss on derivatives fair value
of $12.4 million for the six months ended June 30, 2002 represents the fair
value mark-to-market adjustment made related to the July 2002 through October
2002 and November 2002 through March 2003 derivative contracts that the Company
has in place at June 30, 2002. During the first quarter of 2002 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, which expired
during the first quarter of 2002. During the second quarter of 2002, the Company
had derivatives settlement payments of approximately 4.7 million. The $5.8
million gain from the sale of the floor and the $3.6 million net monthly
settlement payments 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 June 30, 2001.
Production Expense. Production expense for the six months ended June 30,
2002, decreased by 19% to $13.0 million compared to $16.1 million during the
same period of 2001. Lease operating expenses on an $/Mcfe basis decreased to
$0.49/Mcfe from $0.65/Mcfe, while production, severance and ad valorem taxes
decreased to $0.23/Mcfe from $0.37/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 six months ended June 30, 2002 of $2.99/Mcfe vs. $5.43/Mcfe in 2001
is the principal reason for the decrease in taxes.
Geological and Geophysical. The increase in Geological and Geophysical
expense for the six months ended June 30, 2002 increased to $0.8 million
compared to $0.4 million in 2001. The increase is attributed primarily to the
Company's exploratory activities and related costs incurred for acquisition and
reprocessing of seismic data.
Dry Hole and Impairments. Dry hole and impairments increased in the six
months ended June 30, 2002 as a result of the drilling of one exploratory dry
hole in the period and the impairment charge recognized as a result of changes
in the economics of two minor fields due to an increase in lease operating
expenses and a well shut in within one of these two fields.
Surrendered and Expired Acreage. The increase in surrendered and expired
acreage is attributed to acreage related to the exploratory dry hole which was
drilled in the period whereby the Company determined that no further activity
would be initiated on the prospect.
General and Administrative Expense. General and administrative expense for
the six months ended June 30, 2002 increased by $1.4 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.
Restricted Stock Expense. During the six months ended June 30, 2002, the
Company recognized restricted stock compensation expense of $0.4 million which
is attributed to the share grants made to certain officers of the Company that
were approved at the Company's annual meeting in May, 2002.
14
Interest. Interest expense during the six month period ended June 30, 2002
decreased to $2.0 million compared to $4.1 million for the same period ending
June 30, 2001. The decrease is attributable to lower interest rates quarter over
quarter (approximately 3.8% in 2002 versus 7.2% in 2001).
Depreciation, Depletion and Amortization Expense. DD&A for the six months
ended June 30, 2002 was $18.4 million compared to $13.3 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.
Income Taxes. For the six months ended June 30, 2002, the Company recorded
a tax benefit of $2.2 million compared to a tax provision of $18.1 million
during the same period in 2001. The benefit recorded in 2002 represents the
Company's net income for the six months ended at its expected effective tax rate
for 2002 of approximately 39%.
Dividends to Preferred Stockholders. Dividends to preferred stockholders of
approximately $0.4 million in the six months ended June 30, 2002 are comparable
to the $0.4 million for the six months ended June 30, 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 June 30, 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 June 30, 2002,
outstanding natural gas option contracts and swap agreements had a fair value
loss of $9.3 million. 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. At July 31, 2002 the fair
value of the Company's open derivative positions was a $3.0 million
mark-to-market loss, with the closed contract months for July and August having
settled for total cash payments of $2.3 million . A 10% increase to the July 31
NYMEX prices would result in settlements of the open contract months for the
Company's derivatives to increase by $1.2 million while a 10% decrease would
result in a $2.8 million decrease to these contract settlements.
PART II. OTHER INFORMATION
ITEMS 1., 2., 3. AND 5.
Not Applicable.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Annual Meeting of Stockholders of the Company was held May 8, 2002, for
the purpose of voting on the following items:
1. To elect three (3) class I directors for three-year terms expiring in
2005.
2. The ratification of the appointment of KPMG, LLP as the independent
accountants of the Company for the current fiscal year ending December
31, 2002.
15
3. To approve an amendment authorizing the issuance of restricted stock
and restatement of the 3TEC Energy Corporation 2001 Stock Option Plan.
The following table summarizes the tabulation of votes with respect to the
foregoing matters:
For Withheld
---------------------------
Proposal 1:
Election of three (3) Class I directors for three (3) year terms as follows:
Floyd C. Wilson three (3) year 14,886,065 180,049
R.A. Walker three (3) year 14,886,051 180,063
Larry J. Bump three (3) year 14,886,042 180,072
For Against Abstain
----------------------------------------
Proposal 2:
Ratification of the appointment of KPMG, LLP 14,868,023 183,819 14,272
as the Company's independent auditors for the
fiscal year ending December 31, 2002
Proposal 3:
Approval of an amendment authorizing the issuance 7,712,004 5,263,464 19,999
of restricted stock and restatement of the 2001 Stock Option Plan
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.)
16
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.)
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 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.)
17
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.)
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.)
18
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. (Incorporated by reference to Exhibit
10.32 to Form 10-Q filed May 13, 2002).
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.)
10.36 3TEC Energy Corporation Amended and Restated 2001 Stock Option and
Restricted Stock Plan (Incorporated by reference to Exhibit B to Form
DEF 14A filed April 4, 2002).
99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.*
99.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.*
* Filed herewith
(b) The following reports were filed on Form 8-K during the second quarter of
2002:
None.
19
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 August 13, 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
20