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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
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WASHINGTON, D.C. 20549
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FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
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SECURITIES EXCHANGE ACT OF 1934
For the Quarter 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 Number: 000-25717
[GRAPHIC OMITTED][GRAPHIC OMITTED]
BETA OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
Nevada 86-0876964
(State of Incorporation) (I.R.S. Employer Identification No.)
6120 S. Yale, Suite 813, Tulsa, OK 74136
(Address of principal executive offices) (Zip Code)
(918) 495-1011
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No ____
As of August 1, 2002, the Registrant had 12,440,057 shares of Common Stock,
$.001 par value, outstanding.
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INDEX
PAGE
NO.
PART 1 - FINANCIAL INFORMATION
ITEM 1. Financial Statements...............................................................................3
Condensed Consolidated Balance Sheets as of June 30, 2002 (unaudited) and
December 31, 2001........................................................................3
Condensed Consolidated Statements of Operations for the three months ending
June 30, 2002 and June 30, 2001 and for the six months ending June 30, 2002
and June 30, 2001 (unaudited)........................................................... 4
Condensed Consolidated Statements of Cash Flows for the six months ending June 30, 2002
and June 30, 2001 (unaudited)............................................................5
Notes to Condensed Consolidated Financial Statements.......................................6
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of
Operations...............................................................................11
Disclosure Regarding Forward-Looking Statements............................................11
General....................................................................................11
Liquidity and Capital Resources............................................................12
Plan of Operation for 2002.................................................................15
Comparison of Results of Operations for the three months ended June 30, 2002
and 2001 (unaudited).....................................................................17
Comparison of Results of Operations for the six months ended June 30, 2002
and 2001 (unaudited).....................................................................19
Income Taxes...............................................................................21
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk........................................21
PART II. - OTHER INFORMATION
ITEM 1. Legal Proceedings...............................................................................22
ITEM 2. Changes in Securities...........................................................................22
ITEM 4. Submission of Matters to a Vote of Security Holders.............................................22
ITEM 5. Other Information...............................................................................22
ITEM 6. Exhibits and Reports on Form 8-K................................................................23
Signatures...................................................................................................23
PART I
ITEM 1. FINANCIAL STATEMENTS
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
JUNE 30, DECEMBER 31,
2002 2001
------------ ------------
CURRENT ASSETS: ............................................................... (Unaudited)
Cash ...................................................................... $ 545,959 $ 556,199
Accounts receivable
Oil and gas sales ..................................................... 1,767,227 1,397,532
Other ................................................................. 500,837 754,390
Income tax prepaid ........................................................ 79,284 38,503
Futures transaction hedge asset ........................................... -- 114,182
Prepaid expenses .......................................................... 200,483 187,495
------------ ------------
Total current assets .................................................. 3,093,790 3,048,301
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties ...................................................... 64,301,848 58,708,444
Unevaluated properties .................................................... 10,653,027 13,001,443
Less - accumulated amortization of full cost pool ......................... (27,250,696) (25,058,725)
------------ ------------
Net oil and gas properties ............................................ 47,704,179 46,651,162
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system ...................................................... 1,501,477 1,491,516
Support equipment ......................................................... 221,413 221,413
Other ..................................................................... 215,017 198,520
Less - accumulated depreciation ........................................... (521,124) (408,430)
------------ ------------
Net other operating property and equipment ............................ 1,416,783 1,503,019
OTHER ASSETS ................................................................... 90,098 1,472,570
------------ ------------
TOTAL ASSETS ................................................................... $ 52,304,850 $ 52,675,052
============ ============
CURRENT LIABILITIES:
Current portion of long-term debt ......................................... $ 103,182 $ 57,407
Accounts payable, trade ................................................... 2,642,390 2,472,203
Dividends payable ......................................................... 111,482 112,708
Futures transaction hedge liability ...................................... 921,307 --
Other accrued liabilities ................................................ 308,794 463,859
------------ ------------
Total current liabilities ............................................. 4,087,155 3,106,177
LONG-TERM DEBT, less current portion ........................................... 13,641,845 13,648,727
COMMITMENTS AND CONTINGENCIES (NOTE 5)
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,271
issued and outstanding at June 30, 2002 and December 31, 2001
Liquidation value at June 30, 2002 is $5,694,964 ........................ 604 604
Common stock, $.001 par value; 50,000,000 shares authorized; 12,446,072 and
12,398,572 shares issued and 12,440,057 and 12,356,072 shares outstanding
at June 30, 2002 and December 31, 2001, respectively .................... 12,447 12,399
Additional paid-in capital ................................................ 51,923,433 51,814,699
Treasury stock, at cost; 6,015 shares and 42,500 shares reacquired at
June 30, 2002 and December 31, 2001, respectively ....................... (28,153) (198,920)
Accumulated other comprehensive income (loss) ............................. (921,307) 114,182
Accumulated deficit ....................................................... (16,411,174) (15,822,816)
------------ ------------
Total stockholders' equity .............................................. 34,575,850 35,920,148
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..................................... $ 52,304,850 $ 52,675,052
============ ============
The accompanying notes are an integral part of these condensed consolidated
financial statements
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
For three months ended June 30, For six months ended June 30,
2002 2001 2002 2001
----------- ----------- ----------- -----------
REVENUES:
Oil and gas sales ..................................... $ 2,434,926 $ 3,528,536 $ 4,694,439 $ 7,864,324
Field services ........................................ 112,692 281,031 196,431 641,336
----------- ----------- ----------- -----------
Total revenue ..................................... 2,547,618 3,809,567 4,890,870 8,505,660
----------- ----------- ----------- -----------
COSTS AND EXPENSES:
Lease operating expense ............................... 926,915 763,747 1,665,698 1,592,463
Field services ........................................ 49,892 102,176 91,215 238,217
General and administrative ............................ 457,614 682,773 932,958 1,253,022
Depreciation and amortization expense ................. 1,149,056 1,401,994 2,304,666 2,816,197
----------- ----------- ----------- -----------
Total costs and expenses ............................ 2,583,477 2,950,690 4,994,537 5,899,899
----------- ----------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS .............................. (35,859) 858,877 (103,667) 2,605,761
OTHER INCOME (EXPENSE):
Interest expense ...................................... (142,618) (229,645) (283,229) (502,607)
Interest income ....................................... 18,089 6,977 20,277 17,886
----------- ----------- ----------- -----------
Total other income (expense) ........................ (124,529) (222,668) (262,952) (484,721)
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE TAX PROVISION ......................... (160,388) 636,209 (366,619) 2,121,040
INCOME TAXES PROVISION ..................................... -- (248,122) -- (827,206)
----------- ----------- ----------- -----------
NET INCOME (LOSS) .......................................... (160,388) 388,087 (366,619) 1,293,834
PREFERRED DIVIDENDS ........................................ (111,482) (6,373) (221,738) (6,373)
----------- ----------- ----------- -----------
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS ........................................... $ (271,870) $ 381,714 $ (588,357) $ 1,287,461
=========== =========== =========== ===========
BASIC NET INCOME (LOSS) PER COMMON SHARE ................... $ (.02) $ .03 $ (.05) $ .10
=========== =========== =========== ===========
DILUTED NET INCOME (LOSS) PER COMMON SHARE ................. $ (.02) $ .03 $ (.05) $ .10
=========== =========== =========== ===========
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS) ......................................... $ (160,388) $ 388,087 $ (366,619) $ 1,293,834
OTHER COMPREHENSIVE INCOME:
Transition adjustment related to change in accounting for
derivative instruments and hedging activities (net of
income taxes) ........................................ -- -- -- (953,488)
Reclassification of realized loss on qualifying cash flow
hedges (net of income taxes, where applicable) ....... 250,036 161,373 52,789 591,352
Unrealized gain (loss) on qualifying cash flow hedges
(net of income taxes, where applicable) (103,232) 121,692 (1,088,278) 476,318
----------- ----------- ----------- -----------
TOTAL COMPREHENSIVE INCOME (LOSS) .......................... $ (13,584) $ 671,152 $(1,402,108) $ 1,408,016
=========== =========== =========== ===========
The accompanying notes are an integral part of these condensed consolidated
financial statements
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
FOR THE SIX MONTHS ENDED JUNE 30,
2002 2001
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ........................................ $ (366,619) $ 1,293,834
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation and amortization ........................ 2,304,666 2,816,197
Deferred income tax .................................. -- 464,256
Loss on sale of asset ................................ -- 6,865
Change in operating assets and liabilities:
Accounts receivable .................................. (55,601) 474,641
Income tax receivable ................................ 560 --
Prepaid expenses ..................................... (12,988) (259,312)
Income taxes payable ................................. -- 62,650
Other accrued expenses ............................... (239,106) 512,356
----------- -----------
Net cash provided by operating activities ................ 1,783,257 5,804,161
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures .................... (4,525,080) (6,951,385)
Proceeds received from sale of oil and gas properties 1,425,467 726,535
Gas gathering and equipment expenditures ............. (26,458) (287,997)
Change in other assets ............................... 1,407,863 635,067
----------- -----------
Net cash used in investing activities .................... (1,718,208) (5,877,780)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of warrants and options 95,000 156,857
Proceeds from premiums payable ........................... 107,999 46,957
Repayment of premiums payable ............................ (62,805) (60,250)
Repayment of notes payable ............................... (6,301) (5,770)
Proceeds from preferred private placement ............... -- 5,589,390
Commissions payable for preferred private placement ..... -- 238,527
(Increase) decrease in offering costs 13,782 (529,543)
Dividends paid ........................................... (222,964) (6,373)
----------- -----------
Net cash provided by (used in) financing activities ...... (75,289) 5,429,795
----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .......... (10,240) 5,356,176
CASH AND CASH EQUIVALENTS, at beginning of period ............. 556,199 1,536,186
----------- -----------
CASH AND CASH EQUIVALENTS, at end of period ................... $ 545,959 $ 6,892,362
=========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest ............................................. $ 237,283 $ 435,334
=========== ===========
Income taxes ......................................... $ 41,341 $ 300,300
=========== ===========
SUPPLEMENTAL DISCLOSURE OF NON-CASH
INVESTING AND FINANCING ACTIVITIES
Fair value of treasury stock issued for:
Oil and gas properties ................................... $ 170,767 $ --
=========== ===========
Fair value of warrants issued for:
Oil and gas properties .................................. $ -- $ 143,147
=========== ===========
The accompanying notes are an integral part to these condensed consolidated
financial statements
PART I - ITEM 1 (CONTINUED)
FINANCIAL STATEMENTS
BETA OIL & GAS, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1.
The accompanying condensed consolidated financial statements of
Beta Oil & Gas, Inc. and subsidiaries ("Beta") have been prepared in accordance
with generally accepted accounting principles in the United States for interim
financial information and with the instructions of Form 10-Q and Article 10 of
Regulation S-X. In the opinion of management, the accompanying unaudited
financial statements contain all adjustments necessary to present fairly the
Company's financial position as of June 30, 2002 and the results of its
operations and cash flows for the three and six months ended June 30, 2002 and
2001. Management believes all such adjustments are of a normal recurring nature.
The results of operations for interim periods are not necessarily indicative of
results to be expected for a full year. Although we believe that the disclosures
in these financial statements are adequate to make the information presented not
misleading, certain information normally included in financial statements and
related footnotes prepared in accordance with generally accepted accounting
principles in the United States have been condensed or omitted pursuant to the
rules and regulations of the Securities and Exchange Commission. The December
31, 2001 consolidated balance sheet was derived from audited financial
statements, but does not include all disclosures required by generally accepted
accounting principles in the United States. The accompanying financial
statements should be read in conjunction with the audited financial statements
as contained in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2001 that was filed April 1, 2002.
Note 2. OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas
properties. Under this method, all productive and nonproductive costs incurred
in connection with the exploration for and development of oil and gas reserves
are capitalized. Such capitalized costs include lease acquisition, geological
and geophysical work, delay rentals, drilling, completing and equipping oil and
gas wells. Costs associated with production and general corporate activities are
expensed in the period incurred. Interest costs related to unproved properties
and properties under development are also capitalized to oil and gas properties.
Normal dispositions of oil and gas properties are accounted for as adjustments
of capitalized costs, with no gain or loss recognized. Depreciation, depletion,
and amortization of proved oil and gas properties is computed on the
units-of-production method based upon estimates of proved reserves with oil and
gas being converted to a common unit of measure based on the relative energy
content. Capitalized costs of evaluated properties, less accumulated
amortization and related deferred income taxes, shall not exceed an amount ("the
cost ceiling") equal to the sum of the present value of future net cash flows
from estimated production of proved oil and gas reserves, based on current
economic and operating conditions discounted at 10%, less any income tax effects
related to differences between the book and tax basis of the properties
involved. If capitalized costs exceed this cost ceiling, the excess is charged
to earnings. Unproved or unevaluated properties, including any related
capitalized interest costs, are not amortized, but are assessed for impairment
either individually or on an aggregated basis on an annual basis. Unevaluated
leasehold costs, including brokerage costs, are individually assessed quarterly
based on the remaining term of the primary leasehold.
Due to the volatility of commodity prices and/or exploration expenditures with
no significant proved reserve additions or reduction of interests in evaluated
properties, it is possible that future impairments of oil and gas properties
could occur. The price measurement date is on the last day of the quarter or
year end and is required by SEC rules.
6
For the six-month period ended June 30, 2002, the Company sold interests in
various internally generated prospects and unevaluated acreage for approximately
$1,425,467 and certain drilling promotes. The prospects were ready for sale as
the Company had completed the leasing activity in late 2001 and are ready for
drilling. The prospects were as follows:
1.) Lake Boeuf prospect, Lafourche Parish, Louisiana - 87.5% of the Company's
100% interest was sold with the Company retaining a 12.5% working interest. The
Company received cash and a drilling promote on the interest sold. This acreage
is 100% unevaluated and has no proved reserves.
2.) North Mexican Sweetheart prospect, Jackson County, Texas - Approximately 90%
of the Company's working interest in the acreage was sold in this deep Yegua
prospect and the Company has a 12.5% working interest after payout of the
initial test well. This acreage is 100% unevaluated and has no proved reserves.
3.) West Broussard prospect and surrounding acreage - An approximate 3.5%
working interest was sold in the Company's West Broussard East and West Units
and the surrounding unevaluated acreage. The interest in the units represented
approximately 4.5% of the Company's total proved reserves while no reserves are
associated with the surrounding acreage.
4.) Brookshire Dome, Waller County, Texas - The Company reduced its working
interest in its unevaluated Brookshire Dome leasehold from 40% to 25%. There are
no proved reserves associated with this acreage.
Note 3. STOCKHOLDERS' EQUITY
Treasury Stock
On September 19, 2001 the Company's Board of Directors authorized
a stock repurchase program for up to an aggregate of $1,000,000 of the Company's
common stock over the next four months. The repurchase program became effective
on September 19, 2001. At December 31, 2001, the Company had reacquired 42,500
shares for a total cost of $198,920 or $4.68 per share. In January 2002, the
Company reissued 36,485 shares with a fair market value of approximately
$170,767 for geological and geophysical services associated with certain of its
unevaluated properties. At June 30, 2002, the Company held 6,015 treasury shares
with a fair market value of $13,233. The authorization to repurchase shares was
facilitated in part by an Order issued by the Securities and Exchange Commission
on September 14, 2001. The Order temporarily increased the flexibility with
respect to certain SEC rules pertaining to issuer stock repurchases.
Warrants and Options
1. On February 6, 2002, 25,000 non-callable common stock purchase
warrants were issued to an outside director with an exercise price of
$5.22 and expiring in 2006.
2. On May 9, 2002, 35,000 options to purchase common stock pursuant to
the 1999 Incentive and Nonstatutory Stock Option Plan were issued to
three employees with an exercise price of $3.30 and expiring on May 8,
2007.
3. During the month of June, 2002 the Company received $95,000 in gross
proceeds from the exercise of non-callable common stock purchase
warrants with an exercise price of $2.00 per share. These common stock
purchase warrants were originally issued in 1997 and had an expiration
date of June 23, 2002. The remaining 16,500 outstanding common stock
purchase warrants expired.
7
Note 4. NET INCOME (LOSS) PER COMMON SHARE:
FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED
JUNE 30, JUNE 30,
2002 2001 2002 2001
----------- ----------- ------------ --------------
Basic
Net income (loss) ..................... $ (160,388) $ 388,087 $ (366,619) $ 1,293,834
Less: Preferred dividends ............ (111,482) (6,373) (221,738) (6,373)
----------- ----------- ------------ --------------
Net income (loss) available to
common shareholders ................ $ (271,870) $ 381,714 $ (588,357) $ 1,287,461
=========== =========== ============ ==============
Weighted average number of
common shares ...................... 12,393,236 12,368,576 12,395,492 12,361,049
=========== =========== ============ ==============
Basic earnings (loss) per share ....... $ (.02) $ .03 $ (.05) $ .10
=========== =========== ============ ==============
Diluted
Net income (loss) available to
common shareholders ................ $ (271,870) $ 381,714 $ (588,357) $ 1,287,461
Add: Preferred dividends ............. -- 6,373 -- 6,373
----------- ----------- ------------ --------------
Net income (loss) for diluted
earnings (loss) per share ............. $ (271,870) $ 388,087 $ (588,357) $ 1,293,834
=========== =========== ============ ==============
Weighted average number of
Common shares ...................... 12,393,236 12,368,576 12,395,492 12,361,049
Common stock equivalent shares
representing shares issuable
upon exercise of stock options ..... Antidilutive 16,893 Antidilutive 20,382
Common stock equivalent shares
representing shares issuable
upon exercise of warrants .......... Antidilutive 363,086 Antidilutive 397,731
Common stock equivalent shares
representing shares "as-if"
conversion of preferred shares ..... Antidilutive 28,035 Antidilutive 14,096
------------ ---------- ------------ --------------
Weighted average number of ............
shares used in calculation of
diluted income (loss) per share 12,393,236 12,776,590 12,395,492 12,793,258
=========== =========== ============ ==============
Diluted earnings (loss) per share ..... $ (.02) $ .03 $ (.05) $ .10
=========== =========== ============ ==============
Note 5. CONTINGENCIES
On November 29, 2000 in the District Court of Tulsa County, State of Oklahoma, a
Petition was filed by ONEOK Energy Marketing and Trading Company, L.P.
("ONEOK"), plaintiffs, naming the Company and two wholly-owned subsidiaries, Red
River Field Services, L.L.C. and Red River Energy, L.L.C. ("Beta"), as
defendants. In the lawsuit, plaintiff alleges that Beta discontinued selling gas
to plaintiff in breach of a fixed price agreement and sold the gas instead to
other suppliers. Beta counterclaimed on January 24, 2001, alleging that the
contract had been terminated pursuant to its terms for nonpayment by plaintiff
for gas supplied prior to termination, and seeking damages for the unpaid
charges of $282,096.
In the quarter ended March 31, 2002, the Company settled the above claim and
counterclaim with ONEOK through independent mediation. It was mutually agreed to
release all claims and Beta paid ONEOK $43,000 in addition to the $282,096 of
funds held by ONEOK. Each party was responsible for their legal fees and costs
associated with this matter of which the Company's total legal fees were
approximately $85,600. Net of amounts due from joint interest partners, a
non-recurring charge of $205,415 was recorded to income in the year ended
December 31, 2001. However, the total net impact, including the impact of the
non-recurring charge, was a favorable $60,000 in additional net gas revenues due
to the Company's counterclaim. The Company has notified all joint interest
partners of the recoupment and is discussing a proposed recoupment plan with
certain owners. There have been some owners who do not agree with the
recoupment. At this time, the Company has not established a reserve for any
potential non-collection.
8
In September 2001, the Company participated with a 62.5% interest in the
drilling of the Dore #1, Live Oak Prospect located in Vermilion Parish,
Louisiana. The well, which was drilled by a third-party contract drilling
company, was deemed non-commercial and plugged and abandoned. During plugging
operations, drilling fluid was discovered surfacing away from the well location
indicating an integrity issue with the well bore. All regulatory agencies were
notified and the Company, as operator of the well, is to conduct a groundwater
investigation to determine the extent of groundwater contamination, if any. The
cost for the investigation is estimated to be approximately $270,000 and will be
covered by the Company's pollution insurance coverage. If contamination is
present, groundwater remediation would be necessary. No cost estimates for such
remediation have been prepared at this time.
Note 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, in connection with Beta's hedging activities, the Company recorded as
cumulative effect adjustments a loss of $953,488 (net of $635,488 income tax) in
accumulated other comprehensive loss and a corresponding liability. Subsequent
to January 1, 2001, the Company realized a loss of $591,352 (net of $374,235
income tax) in the six-month period ended June 30, 2001.
Natural Gas - At June 30, 2002, the Company had entered into commodity price
hedging contracts as set forth below with respect to our 2001 through 2003
natural gas production. The hedging transactions are settled based upon the
average of the reported settlement prices on the NYMEX for the last three
trading days of a particular contract month.
NYMEX Contract Price per MMBtu
--------------------------------
Collars
Volume in -------
Period MMBtus Floor Ceiling
------ --------- ----- -------
Sept 01 - Feb 02 362,000 $3.50 $3.85
March 02 - Feb 03 1,460,000 $2.30 $2.91
At June 30, 2002, the outstanding contracts had a negative fair market value of
$681,848 and accordingly the Company recorded a derivative liability for such
amount. The fair market value is based on the NYMEX futures contract price for
the outstanding contract months at June 30, 2002. The Company has realized a
loss on the contracts settled of ($167,531) and ($38,410) for the three and
six-month periods ended June 30, 2002, respectively. These contracts are
costless and no net premium is received in cash or as a favorable rate.
Crude Oil - At June 30, 2002, the Company had entered into commodity price
hedging contracts as set forth below with respect to our 2001 through 2003 crude
oil production. The hedging transactions are settled based upon the average of
the reported daily settlement prices per barrel for West Texas Intermediate
Light Sweet Crude Oil on the NYMEX for each trading day of a particular contract
month.
NYMEX Contract Price per Barrel
-------------------------------
Collars
Volume in -------
Period Barrels Floor Ceiling
------ --------- ----- -------
Oct 01- Mar 02 30,000 $25.00 $27.90
Apr 02 - Mar 03 60,000 $20.50 $21.75
9
At June 30, 2002, the outstanding contracts had a negative fair market value of
$239,459. The fair market value is based on the NYMEX-West Texas Intermediate
futures contract price for the outstanding contract months at June 30, 2002 and
accordingly the Company recorded a derivative liability for such amount. The
Company has realized a loss on the contracts settled of ($82,505) and ($14,379)
for the three and six-month periods ended June 30, 2002, respectively. These
contracts are costless and no net premium is received in cash or as a favorable
rate.
10
Part I - Continued
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion is to inform you about our financial position,
liquidity and capital resources as of June 30, 2002 and December 31, 2001 and
the results of operations for the three and six-month periods ended June 30,
2002 and 2001.
Disclosure Regarding Forward-Looking Statements
Included in this report are forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-Q that address
activities, events or developments that the Company expects or anticipates will
or may occur in the future are forward-looking statements. The words "believes,"
"intends," "expects," "anticipates," "projects," "estimates," "predicts" and
similar expressions are also intended to identify forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable, we can give no assurance that such expectations
reflected in such forward-looking statements will prove to have been correct.
All forward-looking statements contained in this report are based on
assumptions believed to be reasonable.
These forward-looking statements include statements regarding:
o Estimates of proved reserve quantities and net present values of those
reserves
o Reserve potential
o Business strategy
o Capital expenditures - amount and types
o Expansion and growth of our business and operations
o Expansion and development trends of the oil and gas industry
o Production of oil and gas reserves
o Exploration prospects
o Wells to be drilled, and drilling results
o Operating results and working capital
o Plan of operation for 2002
We can give no assurance that such expectations and assumptions will prove
to be correct. Reserve estimates of oil and gas properties are generally
different from the quantities of oil and natural gas that are ultimately
recovered or found. This is particularly true for estimates applied to
exploratory prospects and new production. Additionally, any statements contained
in this report regarding forward-looking statements are subject to various known
and unknown risks, uncertainties and contingencies, many of which are beyond our
control. These and other risks and uncertainties, which are described in more
detail in our Annual Report on Form 10-K filed with the Securities and Exchange
Commission, could cause actual results and developments to be materially
different from those expressed or implied by any of these forward-looking
statements. Such things may cause actual results, performance, achievements or
expectations to differ materially from the anticipated results, performance,
achievements or expectations.
General
During the last twelve months, our economy slipped into a moderate recession
impacting most sectors of business. The energy sector has experienced
substantial decreases in the price received for its commodities while inventory
levels of natural gas and crude oil have risen. Due to global events and signs
of an improving economy, commodity prices improved in the last part of the first
quarter to the present. However, the present inventory level of natural gas is
significantly higher than a year ago and historical averages, so much will
depend on the economic rebound. Volatility will continue to be present in
commodity prices in the near term, which may curb any substantial increase in
drilling activity.
11
Liquidity and Capital Resources
A company's liquidity is the amount of time expected to elapse until an
asset can be converted to cash or conversely until a liability has to be paid.
Liquidity is one indication of a company's ability to meet its obligations or
commitment. Historically, our major sources of liquidity have come from
internally generated cash flow from operations, funds generated from the
exercise of warrants/options and proceeds from public and private stock
offerings.
The following table represents the sources and uses of cash for the periods
indicated.
For the six months ended June 31,
2002 2001
------------ ------------
Beginning cash balance .......................................... $ 556,199 $ 1,536,186
Sources of cash:
Cash provided by operations ................................ 1,783,257 5,804,161
Cash provided by financing activities ...................... 216,781 5,429,795
Cash provided by sales of oil & gas properties and
equipment ............................................ 1,425,467 --
------------ ------------
Total sources of cash including cash on hand 3,981,704 12,770,142
Uses of cash:
Oil and gas expenditures ................................... (3,143,675) (5,877,780)
Cash used by financing activities .......................... (292,070) --
------------ ------------
Total uses of cash (3,435,745) (5,877,780)
------------ ------------
Ending cash balance ............................................. $ 545,959 $ 6,892,362
============ ============
Our working capital, excluding the futures transaction hedge liability, was
a deficit of ($72,058) at June 30, 2002 compared to a surplus of $7,501,821 at
June 30, 2001 and a deficit of ($57,876) at December 31, 2001. The significant
decrease in our working capital and liquidity at June 30, 2002, when compared to
June 30, 2001, was due to higher capital expenditures associated with our
intensified drilling and lease acquisition activity principally occurring in the
last half of 2001. Approximately $15.1 million was expended in our 2001 capital
program and was funded from: 1.) Cash flow from operations, 2.) Funds received
from our preferred stock private placement, and 3.) Proceeds from the sale of
certain evaluated and unevaluated oil and gas properties. Factors contributing
to our lower-than-expected working capital and liquidity in 2002 are: 1.) Lower
than anticipated production rates from our WC Block 39 and 49 offshore
properties and our Brookshire Dome project, 2.) A significant cost overrun,
approximately $1.0 million net to our 32% working interest, associated with
Rubel #1, Sara White prospect located in Galveston County, Texas, 3.) Higher
operating expense of approximately $130,000 associated with unplanned
weather-related repairs on certain Mid-Continent properties and 4.) The futures
derivative liability associated with that portion of our future production
volume currently hedged. The futures transaction hedge liability represents the
estimated unrealized reduction in our future oil and gas revenue based on the
current outstanding derivative contracts. The estimate is based on the NYMEX
natural gas and crude oil futures prices in effect at June 30, 2002 and may vary
materially with the fluctuations in natural gas and crude oil. At July 31, 2002
the future transaction hedge liability was approximately $595,000.
Our principal source of short-term liquidity is from operating cash flow.
Should natural gas and crude oil prices decrease materially, our current
operating cash flow would decrease and further reduce our liquidity. During the
six months ended June 30, 2002, our cash flow from operations has been
supplemented by the receipt of approximately $1,425,500 from the sale of certain
drill-ready prospects. We project approximately $3.2 million in proceeds from
such sales will be received in 2002 which will be necessary to fully fund our
projected 2002 capital expenditures and possible debt reduction. To further
improve our operating cash flow and liquidity, we have targeted for divestment
certain non-core marginal properties. The divestment of such properties will
favorably impact our operating margins. Total expected proceeds from such sales
will be less than $300,000 and will have no significant impact on our proved
reserves. Additionally, we will continue to reduce general and administrative
expenses in the last half of 2002. Should we not receive the remaining projected
$1.8 million from prospect sales, we would reduce our capital expenditures in
the last half of 2002.
12
With the decline of commodity prices and a reduction in our proved developed
reserves, our borrowing base capacity under the current credit facility, which
was acquired through the Red River Energy acquisition, has slightly increased
but is not a material source of capital. However, historically we have not used
credit facilities for a source of funds in our drilling or leasing activity.
Should proved developed reserves not materially increase and/or pricing further
decline, our borrowing base may be reduced below the amount currently borrowed
and outstanding under this facility. If this event occurs we would be obligated
to pay down the outstanding amount to the re-determined borrowing capacity. We
would rely on cash flow from operations and funds generated from the sale of
unevaluated or proved undeveloped prospects to make this pay down. It is
possible that we would have to sell some non-core assets as well in order to
meet this obligation. In the second quarter of 2002, our borrowing base was
re-determined and the current borrowing capacity is $14,500,000. Currently, a
balance of $13,634,652 is outstanding against the borrowing base. The current
credit agreement was extended by one year and has a maturity date of March 15,
2004.
Long Term Liquidity and Capital Resources
We have no material long-term commitments associated with our capital
expenditure plans or operating agreements. Consequently, we have a significant
degree of flexibility to adjust the level of such expenditures as circumstances
warrant. The level of capital expenditures will vary in future periods depending
on the success we have with our exploratory drilling activities in future
periods, gas and oil price conditions and other related economic factors. The
following tables show our contractual obligations and commitments.
Payments Due by Period
----------------------------------------------------------------------------------
Total Less than 1 1-3 years 4-5 years After 5 years
Contractual Obligations year
---------------- --------------- ---------------- ---------------- ---------------
Long - Term Debt (1) $13,745,027 $103,182 $13,641,845 $ - $ -
Operating Leases (2) 301,518 193,535 107,983 - -
---------------- --------------- ---------------- ---------------- ---------------
Total cash obligations $14,046,545 $ 296,717 $13,749,828 $ - $ -
================ =============== ================ ================ ===============
(1) $13,634,652 is related to our current credit agreement with a
commercial bank.
(2) Represents amounts due under current operating lease agreements
including the office rental agreement.
Amount of Commitment Expiration per Period
-----------------------------------------------------------------------------------
Other Commercial Total Less than 1 1-3 years 4-5 years After 5 years
Commitments year
----------------- --------------- ----------------- --------------- ---------------
Standby letters of
credit $ 108,500 $108,500 - - -
We currently have no sources of liquidity or financing that are provided by
off-balance sheet arrangements or transactions with unconsolidated, limited
purpose entities.
Accounting Policies
We rely on certain accounting policies in the preparation of our financial
statements. Certain judgments and uncertainties affect the application of such
policies. The "critical accounting policies" which we use are as follows:
o Use of estimates
o Oil and gas properties
o Derivative instruments and hedging activity
o Concentration of credit risk
Certain accounting principals are employed in the adherence and
implementation of these policies along with management judgments. We will
address each policy and how certain judgments and/or uncertainties could
materially impact these policies.
13
Use of Estimates - The preparation of our consolidated financial
statements in conformity with generally accepted accounting principles requires
our management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities, if any, at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. The estimates
include oil and gas reserve quantities, which form the basis for the calculation
of amortization and impairment of oil and gas properties. We emphasize that
reserve estimates are inherently imprecise and that estimates of more recent
discoveries are more imprecise than those for properties with long production
histories. Actual results could materially differ from these estimates.
Volatility in commodity prices also impacts reserve estimates since future
revenues from production may decline significantly if there is a material
decrease in natural gas and/or crude oil prices from the previous reserve
estimation date, which is at each quarter end.
Oil and gas properties - We account for our oil and gas producing
activities using the full cost method of accounting as prescribed by the United
States Securities and Exchange Commission ("SEC"). Accordingly, all costs
incurred in the acquisition, exploration, and development of proved oil and gas
properties, including the costs of abandoned properties, dry holes, geophysical
costs, and annual lease rentals are capitalized. All production and general
corporate costs are expensed as incurred. In general, sales or other
dispositions of oil and gas properties are accounted for as adjustments to
capitalized costs, with no gain or loss recorded. Amortization of evaluated oil
and gas properties is computed on the units of production method based on all
proved reserve quantities, on a country-by-country basis. The net capitalized
costs of evaluated oil and gas properties (full cost ceiling limitation) are not
to exceed their related estimated future net revenues discounted at 10% per
annum, net of tax considerations. Unevaluated oil and gas properties are
assessed at least annually for impairment either individually or on an aggregate
basis. Unevaluated leasehold costs, including brokerage costs, are individually
assessed quarterly based on the remaining term of the primary leasehold. For the
remaining costs, which includes seismic and geological and geophysical, we
estimate reserve potential for the unevaluated properties using comparable
producing areas or wells and risk adjust that estimate by 50-75%. As mentioned
previously in Use of Estimates, reserve estimations are more imprecise for new
or unevaluated areas. Consequently, should certain geological conditions or
factors exist, such as reservoir depletion, reservoir faulting, reservoir
quality etc., but unknown to us at the time of our assessment, a materially
different result could occur.
Derivative instruments and hedging activity - We use derivatives in a
limited manner to protect against commodity price volatility. Effectively, we
sell a portion of our natural gas and crude oil based on a NYMEX based price
with a set floor (bottom) and ceiling (top) price or a range. Our derivatives
are recorded on the balance sheet at fair value and changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, depending on the type of transaction. Our derivative
contracts consist of cash flow hedge transactions which hedge the variability of
cash flow related to a forecasted transaction. Changes in the fair value of
these derivative instruments are recorded in other comprehensive income and
reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The fair value of these
contracts may vary materially with the fluctuations of future natural gas and
crude oil prices. However, the fluctuation in fair value will be offset by the
future actual value received from the hedged volume.
Concentration of credit risks - Credit risk represents the accounting loss
that would be recognized at the reporting date if counter parties failed
completely to perform as contracted. Concentrations of credit risk (whether on
or off balance sheet) that arise from financial instruments exist for groups of
customers or counter parties when they have similar economic characteristics
that would cause their ability to meet contractual obligations to be similarly
affected by changes in economic or other conditions. We operate in one segment,
the oil and gas industry. A geographic concentration exists because Beta's
customers are generally located within the Central United States. Financial
instruments that subject us to credit risk consist principally of oil and gas
sales, which are based solely on short-term purchase contracts from various
customers with related accounts receivable subject to credit risk. However, we
do have certain properties, such as WEHLU, that are "captive" to one purchaser
due to the location of the production and lack of alternate sources of
purchasers. In this particular instance, Duke Energy is the purchaser.
Effects of Transactions With Related and Certain Other Parties
During the first six months ended June 30, 2002, Waveland Drilling Partners
2002A, L.P. acquired a 10% working interest in our West Broussard, Lafayette
Parish, Louisiana prospect, a 12.5% working interest in our Lake Boeuf,
Lafourche Parish, Louisiana prospect and a 10% working interest in our
unevaluated shallow Brookshire Dome prospect area in Waller County, Texas on
standard industry terms for both the acreage and participation in the subsequent
drilling of the prospects. We received approximately $706,550 for the acreage
and promote on the future drilling of the prospects' wells. We may sell
interests in other prospects should Waveland Partners agree to our terms.
14
Plan of Operation for 2002
For the first six months of 2002, we expended approximately $3.0 million,
comprised of: 1) Approximately $.9 million related to our Jackson County
drilling, seismic and leasing activity, 2.) $1.1 million expended on the Rubel
#1, Sara White prospect located in Galveston County, Texas, 3.) $.6 million in
the drilling, completion and land activity associated with our Brookshire Dome
project located in Waller County Texas, 4.) $.3 million on additional activity
in our West Broussard prospect.
To date, we have participated in the drilling 14 gross wells, (3.03 net
wells) of which nine gross wells (2.12 net wells) were completed successfully as
producers, four gross wells (.665 net wells) were dry holes and one gross well
(.25 net well) is currently being completed.
In Jackson County, we have participated in the drilling of three gross wells
(.415 net wells) in 2002. The Long Beach #1, an 18,000 foot Wilcox test well
which we participated with a 2% carried interest reached the objective depth and
encountered the Wilcox sand but was deemed uneconomical. The well was plugged
and abandoned. Additionally, the Elk Hills #1 Wilcox test, which commenced
drilling in late 2001 was evaluated for considerable time before temporarily
abandoning the well in the second quarter. Lastly, we participated with a 25%
working interest in the drilling of the Yaussi #1, a Yegua test well, which was
unsuccessful and plugged. Total cost incurred to date for Jackson County area is
approximately $.9 million. The Truckstop #1, a Yegua test well located in the
same fault block tested by the Elk Hills #1, was spudded subsequent to June 30,
2002 and is currently drilling. We have a 6.25% interest in this well.
The Rubel #1 (Sara White Prospect) located in Galveston County, Texas and
operated by Ocean Energy was successfully completed in the "S" sand in the
second quarter of 2002. A production test was performed and the well flowed 2.1
Mmcf per day of natural gas and 30 barrels per day of condensate. The well is
expected to commence sales in August 2002 after a considerable delay due to
right-of-way issues regarding the sales line. We have a 32% working interest in
the well and currently have a total cost in the well of approximately $2.7
million, which is approximately $1.0 million net to us over the originally
authorized budget.
In the Brookshire Dome project, for the first six months of 2002 we have
participated in the drilling of eight gross wells (2.0 net wells), of which six
gross wells (1.5 net wells) were successfully completed, one gross well (.25 net
well) was a dry hole and one gross well (.25 net well) is currently in the
completion stage. The wells are currently producing approximately 52 gross
barrels (11.5 net barrels) of oil per day and 1354 gross Mfe (204 net Mcf) of
natural gas per day. We are in the process of evaluating the ultimate reserve
potential and decline rate associated with the shallow wells drilled since our
activity began in the last half of 2001. We have experienced steeper than
expected declines with the production and will farm out our interest or
selectively participate in the immediate drilling activity until our evaluation
is complete.
In the second quarter of 2002, we participated in the drilling of two gross
wells (.30 net wells) in McIntosh County, OK, both of which were successful. The
LaCour #3-15, a Wilcox development well, is currently producing approximately
300 gross Mcf (28 net Mcf) of natural gas per day. The Tiger #2-10, an Arbuckle
test well, is waiting on connection to the sales line and has tested at
approximately 700 gross Mcf (93 net Mcf) per day.
Currently, we estimate our capital expenditures for the last half of 2002
not to exceed $3 million for a total of $6 million for the year versus our
original forecast of $7 million. Due to the results of our various exploration
projects, which were in progress at the end of 2001 and the first quarter 2002,
we will reduce and shift our remaining 2002 budget to lower risk profile
projects, which we are currently evaluating.
The following events or results have occurred that change the allocation,
timing and amount of our originally forecasted second half 2002 capital
expenditures:
15
o Due to the disappointing results of our lower Wilcox test wells, we
will only participate in any additional lower Wilcox drilling through
farmouts, selling a portion of our interest and retaining a carried
interest, reversionary (back-in) arrangements or other types of cost
free interests. We will continue to selectively participate in
additional Yegua/Frio drilling.
o In Galveston County, Texas, the deep Vicksburg test well, the
Northeast Hitchcock prospect, which was originally forecast to drill
in the fourth quarter of 2002 has been indefinitely postponed by the
operator due to the results and cost overrun related to the Rubel #1,
Sara White prospect.
o The Detroit prospect, located in Red River and Lamar Counties, Texas
has not sold at this time. We had originally scheduled drilling in
the last half of 2002. This prospect will not be drilled until it is
sold and most likely will not drill until 2003.
o The Toko Syncline prospect located in Australia was originally
forecast to drill in the first half of 2002 but the operator has not
sold the remaining interests in this prospect. We will participate in
the drilling of this prospect with a 6% carried interest.
o The estimated cost of the rework and recompletion on the West Cameron
Block #49 properties, which began early in the 3rd quarter of 2002,
will be approximately $500,000 - $600,000 net to our interest. The
recompletion was not projected to occur until 2003 and 2004.
o The drilling of the Lake Boeuf prospect located in Lafayette Parish,
Louisiana which was originally scheduled to begin drilling early in
the second half of 2002, is expected to drill late in the second half
of 2002 or early 2003. The operator is working on the drilling
schedule at this time.
o The West Broussard prospect located in Lafayette Parish, Louisiana
was originally scheduled to begin drilling early in the second half
of 2002. Delays in selling the remaining portion of the prospect have
caused the delay in drilling. At this time we do expect to sell the
remaining portion of the prospect and anticipate a late 2002 or early
2003 date to commence drilling.
Our mid-year update for our cash flows from operations for the 2002 will be
approximately $4.3 million versus our original projection of $4.8 million. Our
current projection is based on an average natural gas price of $2.85 versus our
original projection of $2.37 per Mcf and $21.74 per barrel versus an original
projection of $18.88 per day per barrel. Additionally, we project our average
net daily production to be approximately 8.6 Mmcfe for 2002 versus an original
estimate of 10.0 Mmcfe per day. The downward production rate revision is due to
lower than forecast production rates in the first half of 2002 from our Gulf
production, a steeper natural decline rate with the Brookshire Dome project, a
hook up delay with the Rubel #1 and the probable delay of incremental production
from our West Broussard and Lake Boeuf prospects which were originally scheduled
to drill in the third quarter of 2002 and go on line in the fourth quarter. The
possibility remains that the timing for drilling these prospects may contribute
to our 2002 production rate. We do anticipate that our efforts from exploitation
and remedial projects associated with our Mid-Continent assets may partially
offset the shortfalls previously discussed.
For the remainder of 2002, we expect to fund our capital requirements from
net cash flow from operations (after general and administrative expense) and
proceeds received from the sale of certain drill-ready prospects and possibly
other non-core properties. The success and timing of our prospect sales effort
is critical to the funding and timing of our capital expenditure schedule for
the remainder of 2002. At this time we anticipate additional proceeds of
approximately $1.3 will be received in the last half of 2002 from the West
Broussard prospect and an additional $.3 million from the sale of other non-core
uneconomical properties. As with any projection, the timing and amounts can
vary. Generally, funds must be advanced within thirty days or less after our
election to participate in the drilling of a well.
Our planned capital expenditures and/or administrative expenses could
exceed those amounts budgeted and could exceed our cash from all sources. While
our projected cash expenditures may be as projected, cash flow from operations
could be unfavorably impacted by lower than projected commodity prices and/or
lower than projected production rates. Conversely, higher than projected
commodity prices would favorably impact our projected cash flow from operations.
Additionally, lower natural gas and crude oil prices could adversely impact our
ability to receive any proceeds from the sale of our prospects. If this happens,
it may be necessary for us to raise additional funds.
16
1.) We may seek alternative forms of financing, if available, on terms
acceptable to us. Such financing usually involves debt with a higher
cost of capital as compared to conventional bank financing. We would
seek financing in the range of $1,000,000 to $5,000,000. We would seek
to use this means of financing in the event that a particular
acquisition did not have sufficient proved producing reserve collateral
to support a conventional bank loan.
2.) We may realize additional cash flow from oil and gas wells to be
drilled, if found to be productive. We own working interests in wells
that are currently producing and in additional wells, which are
presently being completed and equipped for production. For 2002, we
currently estimate that the wells will generate approximately $6.4
million of net cash flow after deducting lease-operating expenses of
approximately $3.5 million.
3.) We have approximately 375,725 callable common stock purchase warrants
outstanding exercisable at a price of $7.50 per share. We are able to
call these warrants at any time after our common stock has traded on
Nasdaq at a market price equal to or exceeding $10.00 per share for 10
consecutive days which was achieved in July 2000. It is our intent to
call all of these warrants at such time, if and when, the cash is
needed to fund capital requirements. We will receive proceeds equal
to the exercise price times the number of shares which are issued from
the exercise of warrants net of commission to the broker of record, if
any. We could realize net proceeds of approximately $2,814,500 from
the exercise of all of these warrants. There is no assurance that any
warrants will be exercised or that we will ever realize any proceeds
from the $7.50 warrant calls. However, due to current market
conditions and the current price of our stock, it is not probable that
we will call these warrants in 2002.
If the above additional sources of cash are insufficient or are unavailable
on terms acceptable to us, we will be compelled to reduce the scope of our
business activities. If we are unable to fund planned expenditures within a
thirty to sixty-day period after a well is proposed for drilling, it may be
necessary to:
1) Forfeit our interest in wells that are proposed to be drilled;
2) Farm-out a portion or all of our interest in proposed wells;
3) Sell a portion of our interest in proposed wells and use the sale
proceeds to fund our participation at a lesser interest; or
4) Reduce general and administrative expenses.
Should our future projected capital expenditures be reduced by lower
sources of cash flow or additional cash is required for reduction of our credit
facility, our potential growth rate from our exploration activity could be
materially impacted. An alternative action to maintain our growth potential
would be the acquisition of existing reserves with the use of debt and equity
instruments.
Our long-term goal is to continue the pattern of growing the Company by
accumulating oil and gas reserves through acquisition and drilling. In the event
we cannot raise additional capital, or the industry market is unfavorable, we
may have to slow or alter our long-term goal accordingly. Should we achieve our
long-term goal and an acceptable value for our shareholders is recognized over
the next two to three years, selling a portion or all of the Company is a
possibility.
These are forward looking statements that are based on assumptions, which in
the future may not prove to be accurate. Although we believe that the
expectations reflected in such forward looking statements are based on
reasonable assumptions, we can give no assurance that our expectations will be
achieved.
17
Comparison of Results of Operations
Quarter ended June 30, 2002 and Compared to Quarter ended June 30, 2001
We had a reported net loss of ($160,388) for the quarter ended June 30,
2002 compared to net income of $388,087 for the same period ended 2001. Lower
natural gas and crude oil prices and higher operating expense contributed to the
lower net income for the period ended 2002 offset by lower general and
administrative, depletion and interest expenses.
The following table summarizes key items of comparison and their related
increase (decrease) for the periods indicated.
In Thousands ......................... Quarter Ended June 30 $-Increase %-Increase
--------------------- --------- ----------
2002 2001 (Decrease) (Decrease)
--------- --------- --------- ----------
Net income (loss) .................... $ (160.4) $ 388.1 $ (548.5)
Oil and gas sales .................... 2,434.9 3,528.5 (1,093.6) (31%)
Field service income ................. 112.7 281.0 (168.3) (60%)
Lease operating expense .............. 750.0 537.4 212.6 40%
Production tax ....................... 176.9 226.4 (49.5) (22%)
Field service expense ................ 49.9 102.2 (52.3) (51%)
G&A expense .......................... 457.6 682.8 (225.2) (33%)
Depletion - Full cost ................ 1,089.2 1,268.2 (179.0) (14%)
Depreciation - Field service and other 59.9 133.8 (73.9) (55%)
Interest expense ..................... 142.6 229.6 (87.0) (38%)
Income tax provision (benefit) ....... -- 248.1 (248.1) --
Production:
Natural Gas - Mcf .................... 561.6 637.3 (75.7) (12%)
Crude Oil - Bbl ...................... 32.3 29.0 3.3 11%
Natural Gas Equivalent - McfE ........ 755.5 811.1 (55.6) (7%)
$ per unit:
Ave. gas price - Mcf ................. $ 3.08 $ 4.35 $ (1.27) (29%)
Ave. oil price - Bbl ................. 21.83 26.11 (4.28) (16%)
Ave. operating expense - McfE ........ 1.23 .96 .27 28%
Ave. G&A - McfE ...................... .61 .82 (.21) (26%)
Ave. Depl. - Full cost - McfE ........ 1.44 1.56 (.12) (8%)
For the quarter ended June 30, 2002, oil and gas sales decreased
$1,093,610 or 31%, from the same quarter ended 2001, to $2,434,926. The decrease
resulted from lower natural gas and crude oil prices and lower natural gas
production in the quarter ended June 30, 2002. The lower commodity prices
resulted in 78% of the decrease in revenue, or approximately $851,821. Lower
natural gas prices comprised 84% of the decrease with lower crude oil prices
accounting for the remaining 16%. Our crude oil sales volumes increased for the
period ended 2002 when compared to the same period ended 2001 due to new
production associated with our exploration activity in the Brookshire Dome area
in Waller County, Texas and the T. Cenac #1, located in the Lapeyrouse field,
Terrebonne Parish, Louisiana, which went on production in the third quarter of
2001. Natural gas sales volumes were lower for the quarter ended June 30, 2002
compared to the same quarter ended 2001, primarily due to lower production in
our South Texas shallow Frio wells and West Cameron Block 49 wells partially
offset by new production from the T. Cenac #1 well, as previously mentioned. The
lower production was due to greater than expected decline in the South Texas
wells and water production in the West Cameron Block 49 wells, which are
currently being reworked.
Generally, we sell our natural gas to various purchasers on an
indexed-based price. These indices are generally affected by the NYMEX - Henry
Hub spot price. We use hedges on a limited basis to lessen the impact of price
volatility. Hedges covered approximately 60% of our production on an equivalent
Mcf basis for the quarter ended June 30, 2002. Based on our natural gas
production for the three months ended June 30, 2002, a decline in the average
natural gas price realized by Beta of $1.00 per Mcf would have resulted in an
approximate $.5 million reduction in net income before income taxes.
18
Operating expenses, excluding production and ad valorem taxes, increased
$212,628 or 40%, to $749,998 for the quarter ended June 30, 2002 compared to the
same period for 2001. The increase was primarily due to approximately $130,000
weather related repairs on our West Edmond Hunton Lime Unit in Oklahoma and the
Peace creek and R. E. Estey Units in Kansas. Additional operating expenses of
approximately $73,408 were related to our Brookshire Dome, Waller County, Texas
which came on line in the second half of 2001.
Production taxes for the quarter ended June 30, 2002 decreased by $49,461
when compared to the same quarter in 2001 due to lower oil and natural gas
revenues. Production taxes are primarily calculated based on a percentage of oil
and gas revenues in 2002.
General and administrative expense for the three months ended June 30, 2002
decreased approximately $225,159 or 33%, to $457,614 compared to $682,773 for
the same period in 2001. The decrease was due primarily to a reduction in
personnel costs, legal and insurance expense and an increase in overhead
reimbursement associated with our operations.
Depletion and depreciation expense decreased $252,938, or 18%, from the
same period in 2001 to $1,149,056 for the three months ended June 30, 2002.
Depletion expense associated with evaluated oil and gas properties comprised
$179,003 of the decrease. The decrease was due to a lower net evaluated cost
basis for our evaluated properties and lower production volumes for the
three-month period ended June 30, 2002 when compared to the same period for
2001. Depletion for oil and gas properties is calculated using the "unit of
production" method, which essentially amortizes the capitalized costs associated
with the evaluated properties based on the ratio of production volume for the
current period to total remaining reserve volume for the evaluated properties.
In the third and fourth quarters of 2001, our full cost pool exceeded the full
cost ceiling and accordingly we impaired, or wrote-down, our evaluated oil and
gas properties by approximately $13.8 million. Lower natural gas and crude oil
prices in the last half of 2001 contributed mainly to the lower ceiling.
Depletion expense per McfE for the three months ended June 30, 2002 was $1.44
per McfE compared to $1.56 per McfE for the same period in 2001. Depreciation
expense related to other assets decreased $73,295 from the same period in 2001
to $59,893 for the three months ended June 30, 2002. The decrease was related to
the depreciation expense associated with the gathering assets, which is
calculated on a "unit of revenue" method. The "unit of revenue" method amortizes
the capitalized costs associated with the gathering assets based on the ratio of
gross actual revenues for the current period to the total remaining gross
revenues for the gathering assets. Therefore, the lower gross gathering revenues
for the quarter ended June 30, 2002 resulted in lower depreciation expense for
the period.
Interest expense decreased for three months ended June 30, 2002, compared
to the same period 2001, as a result of lower interest rates.
19
Six Months ended June 30, 2002 and Compared to Six Months ended June 30, 2001
We had a reported net loss of ($366,619) for the six months ended June
30, 2002 compared to net income of $1,293,834 for the same period ended 2001.
Lower natural gas and crude oil prices and higher operating expense contributed
to the lower net income for the period ended 2002 partially offset by lower
general and administrative, depletion and interest expenses.
The following table summarizes key items of comparison and their related
increase (decrease) for the periods indicated.
In Thousands ......................... Six Months Ended June 30 $-Increase %-Increase
---------------------- --------- ---------
2002 2001 (Decrease) (Decrease)
--------- --------- --------- ---------
Net income (loss) .................... $ (366.6) $ 1,293.8 $ (1,660.4) --
Oil and gas sales .................... 4,694.4 7,864.3 (3,169.9) (40%)
Field service income ................. 196.4 641.3 (444.9) (69%)
Lease operating expense .............. 1,355.4 1,041.3 314.1 30%
Production tax ....................... 310.3 551.2 (240.9) (44%)
Field service expense ................ 91.2 238.2 (147.0) (62%)
G&A expense .......................... 933.0 1,253.0 (320.0) (26%)
Depletion - Full cost ................ 2,192.0 2,552.9 (360.9) (14%)
Depreciation - Field service and other 112.7 263.3 (150.6) (57%)
Interest expense ..................... 283.2 502.6 (219.4) (44%)
Income tax provision (benefit) ....... -- 827.2 (827.2) --
Production:
Natural Gas - Mcf .................... 1,136.4 1,248.4 (112.0) (9%)
Crude Oil - Bbl ...................... 72.2 54.3 17.9 33%
Natural Gas Equivalent - McfE ........ 1,569.5 1,574.5 (5.0) --
$ per unit:
Ave. gas price - Mcf ................. $ 2.79 $ 5.12 $ (2.33) (46%)
Ave. oil price - Bbl ................. 21.12 27.05 (5.93) (22%)
Ave. operating expense - McfE ........ 1.06 1.01 .05 5%
Ave. G&A - McfE ...................... .59 .80 (.21) (26%)
Ave. Depl. - Full cost - McfE ........ 1.40 1.62 (.22) (14%)
For the six months ended June 30, 2002, oil and gas sales decreased
$3,169,885 or 40%, from the same six-month period ended 2001, to $4,694,439. The
decrease was a result of lower natural gas and crude oil prices for the six
months ended June 30, 2002. Lower natural gas prices comprised 86% of the
decrease with lower crude oil prices accounting for the remaining 14%. Natural
gas sales volumes were lower for the six months ended June 30, 2002 compared to
the same period ended 2001, primarily due to lower production in our South Texas
shallow Frio wells and West Cameron Block 49 wells partially offset by new
production from the T. Cenac #1 well, as previously mentioned. The lower
production was due to greater than expected decline in the South Texas wells in
the last half of 2001 and water production in the West Cameron Block 49 wells,
which are currently being reworked and should be back on line late in the third
quarter. However, our crude oil sales volumes increased for the period ended
2002 when compared to the same period ended 2001 due to new production
associated with our exploration activity in the Brookshire Dome area in Waller
County, Texas and the T. Cenac #1, located in the Lapeyrouse field, Terrebonne
Parish, Louisiana, which went on production in the third quarter of 2001. The
increase in crude oil production offsets the decrease in natural gas production.
Operating expenses, excluding production taxes, increased $314,154 or 30%,
to $1,355,394 for the six months ended June 30, 2002 compared to the same period
for 2001. The increase was due to approximately $130,000 weather related repairs
on our WEHLU property located in Oklahoma and the Peace Creek and R. E. Estey
Units in Kansas. Additionally, we had operating expenses of approximately
$166,000 related to our Brookshire Dome, Waller County, Texas properties which
came on line in the last half of 2001.
20
Production taxes for the six months ended June 30, 2002 decreased $240,919
when compared to the same period ended in 2001 due to a lower oil and natural
gas revenues in 2002.
General and administrative expenses for the six months ended June 30, 2002
decreased approximately $320,064 or 26%, to $932,958 compared to $1,253,022 for
the same period in 2001. The decrease was due to lower outside services, legal,
audit, travel and reporting expenses and increased overhead reimbursement
associated with our operations in the Brookshire Dome area.
Depletion and depreciation expense decreased $511,531, or 18%, from the
same period in 2001 to $2,304,666 for the six months ended June 30, 2002.
Depletion expense associated with evaluated oil and gas properties comprised
$360,949 of the decrease. The decrease was due to a lower net evaluated cost
basis for our evaluated properties and a slightly lower production volumes for
the six-month period ended June 30, 2002 when compared to the same period for
2001. Depletion for oil and gas properties is calculated using the "unit of
production" method, which essentially amortizes the capitalized costs associated
with the evaluated properties based on the ratio of production volume for the
current period to total remaining reserve volume for the evaluated properties.
In the third and fourth quarters of 2001, our full-cost pool exceeded the
full-cost ceiling and accordingly we impaired, or wrote-down, our evaluated oil
and gas properties by approximately $13.8 million. Lower natural gas and crude
oil prices in the last half of 2001 contributed mainly to the lower ceiling.
Depletion expense per McfE for the six months ended June 30, 2002 was $1.40 per
McfE compared to $1.62 per McfE for the same period in 2001. Depreciation
expense related to other assets decreased $150,582 from the same period in 2001
to $112,695 for the six months ended June 30, 2002. The decrease was related to
the depreciation expense associated with the gathering assets, which is
calculated on a "unit of revenue" method. The "unit of revenue" method amortizes
the capitalized costs associated with the gathering assets based on the ratio of
gross actual revenues for the current period to the total remaining gross
revenues for the gathering assets. Therefore, the lower gross gathering revenues
for the quarter ended June 30, 2002 resulted in lower depreciation expense for
the period.
Interest expense decreased for six months ended June 30, 2002, compared to
the same period 2001, as a result of lower interest rates.
Income Taxes
As of June 30, 2002, we had Federal net operating loss carryforwards of
approximately $12,657,100, which expire in the years 2012 through 2021, and
California net operating loss carryforwards of $6,564,029, which begin to expire
in 2007. Utilization of the tax net operating loss carryforward may be limited
in the event a 50% or more change of ownership occurs within a three-year
period. Additionally, other factors may limit the tax net operating loss
carryforwards.
Item 3. Quantitative and Qualitative Disclosure About Market Risk
We are exposed to market risk related to adverse changes in oil and gas
prices. Our oil and gas revenues can be significantly affected by volatile oil
and gas prices. This volatility can be mitigated through the use of oil and gas
derivative financial hedging instruments. Based on the average production rate
for the six months ended June 30, 2002, we have approximately 64% of our future
natural gas production hedged through February 2003. We have approximately 42%
of our future crude oil production hedged through March 2003. We use costless
collars to hedge our production (For further information, please refer to PART
I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 6. DERIVATIVE
INSTRUMENTS AND HEDGING ACTIVITIES). The remainder of our production is not
hedged and we may continue to experience wide fluctuations in oil and gas
revenues as a result. We are also exposed to market risk related to adverse
changes in interest rates. This volatility could be mitigated through the use of
financial derivative instruments. Currently, we do not have any derivative
financial instruments in place to mitigate this potential risk.
21
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 5 to Consolidated Financial Statements.
Item 2. Changes in Securities
During the second quarter, we issued certain equity securities without
registration under the Securities Act of 1933, as amended, in reliance upon
the exemption from the registration requirements provided by Section 4(2) of
that act. In each case, the acquirors of the securities were sophisticated,
experienced investors who were able to evaluate the risks and merits of an
investment in our Company and who were able to bear the financial risks thereof.
The transactions are as follows:
1. On February 6, 2002, 25,000 non-callable common stock purchase warrants were
issued to an outside director with an exercise price of $5.22 and expiring in
2006.
2. On May 9, 2002, 35,000 options to purchase common stock pursuant to the 1999
Incentive and Nonstatutory Stock Option Plan were issued to three employees with
an exercise price of $3.30 and expiring on May 8, 2007.
3. During the month of June, 2002 the Company received $95,000 in gross proceeds
from the exercise of non-callable common stock purchase warrants with an
exercise price of $2.00 per share. These common stock purchase warrants were
originally issued in 1997 and had an expiration date of June 23, 2002. The
remaining 16,500 outstanding common stock purchase warrants expired. The
proceeds received from the exercised warrants were used for general working
capital purposes.
Item 4. Submission of Matters to a Vote of Security Holders
Our annual meeting of shareholders was held at Warren Place Two, 6120 South
Yale Avenue, Tulsa, Oklahoma on Saturday, June 1, 2002, at 10:00 A.M. Central
Daylight Time. The matters submitted to a vote of our shareholders as well as
the results of the votes cast are as follows:
Proposal No.1: Election of directors. A summary of the votes cast is
as follows:
% of out- Number % of out- Number % of out-
--------- ------- --------- ------- ---------
Number For standing shares Against standing shares Abstain standing shares
---------- --------------- ------- --------------- ------- ---------------
Steve Antry 9,641,061 77.759% 0 0.00% 86,395 0.697%
R. Thomas Fetters 9,636,419 77.722% 0 0.00% 86,395 0.697%
Joe C. Richardson, Jr. 9,648,961 77.823% 0 0.00% 86,395 0.697%
John P. Tatum 9,648,919 77.823% 0 0.00% 86,395 0.697%
Robert C. Stone, Jr. 9,641,019 77.759% 0 0.00% 91,895 0.741%
As a result of the voting, Steve Antry, R. Thomas Fetters, Joe C.
Richardson, Jr., John P. Tatum and Robert C. Stone, Jr. were elected as the
Company's directors to serve in that capacity until the Annual Shareholders
Meeting in 2003.
Proposal No. 2: Ratification of Appointment of Independent Auditors.
A summary of the votes cast is as follows:
% of out- % of out- Number % of out-
--------- --------- ------- ---------
Number For standing shares Number Against standing shares Abstaining standing shares
- ---------- --------------- -------------- --------------- ---------- ---------------
9,654,371 99.685% 38,965 0.314% 42,020 0.339%
As a result of the vote, Hein + Associates, LLP was appointed our
auditors for the year 2002.
23
Item 5. Other Information
On June 21, 2002, John P. Tatum, an outside director, elected to retire and
submitted his resignation to the Board of Directors. The Board of Directors met
on June 25, 2002 and unanimously accepted Mr. Tatum's resignation. At the same
meeting the Board elected Mr. Robert E. Davis, Jr. to fill the vacant seat.
As the newest member to be elected to our Board of Directors, Mr. Robert E.
Davis, Jr., age 51, was Executive Vice President and Chief Financial Officer of
Red River Energy, LLC. He was responsible for the Company's financing and
accounting activities as well as assisting in economic evaluations of potential
acquisition targets. Prior to co-founding Red River, Mr. Davis served as
Executive Vice President and Chief Financial Officer of Carlton Resources
Corporation, an oil and gas acquisition company, from 1996 to 1998. From 1994 to
1996, Mr. Davis served as Executive Vice President and Chief Financial Officer
of American Central Gas Company in Tulsa, a natural gas gathering and processing
company. In 1983, Mr. Davis co-founded and served as Executive Vice President
and Chief Financial Officer of Vesta Energy Company, a nationally recognized
natural gas marketing company. From 1986 through 1992, he also served as
President and Chief Executive Officer of Esco Energy, Inc., the holding company
of Vesta Energy Co., Omega Pipeline Co. and Esco Exploration Company. During his
25 years in the oil and gas industry, Mr. Davis also served as CPA with Arthur
Young & Company (now Ernst & Young LLP) in Tulsa, specializing in oil and gas
taxation and accounting, a commercial loan officer at United Oklahoma Bank in
Oklahoma City and manager of drilling program sales and administration with
Andover Oil Company of Tulsa. Mr. Davis has a B.S. degree in finance and
accounting from the University of Oklahoma. He is a licensed certified public
accountant in the state of Oklahoma.
On June 28, 2002, we filed a Registration Statement on Form S-3, File No.
333-91496 (the "Registration Statement") with the Securities and Exchange
Commission (the "Commission") relating to the resale of our common stock and
warrants issuable as it related to: 1.) the conversion of the outstanding
preferred stock to common stock and common stock purchase warrants issued in our
June 29, 2001 Series A Convertible Preferred Stock private placement, 2.) the
common stock and common stock purchase warrants issued September 19, 2000 as
partial consideration paid to Duke Field Services, L.L.C. ("Duke") for the
purchase of a note payable and Duke's interest in our TCM coal bed methane
properties, and 3.) common stock and common stock purchase warrants issued to
other qualified investors in past private placements for cash or services. On
July 17, 2002, the Commission declared the Registration Statement effective.
On August 9, 2002, our Audit Committee approved certain non-audit services
that will be provided by our independent auditors, Hein + Associates LLP. The
nature of such services relate to tax compliance and preparation of our 2001
federal and state income tax returns. The total fees associated with this
service will be approximately $10,000-15,000.
Item 6. Exhibits and Reports on Form 8-K
(a)
EXHIBIT NO. DESCRIPTION
10.36 Fourth Amendment to First Amended and Restated Revolving Credit
Agreement dated March 15, 2002 between Beta Oil & Gas, Inc. and
Bank of Oklahoma, N.A.
10.37 Promissory Note dated March 15, 2002 between Beta Oil & Gas, Inc.
and Bank of Oklahoma, N.A.
10.38 Revolving Credit Note dated March 15, 2002 between Beta Oil & Gas,
Inc. and Bank of Oklahoma, N.A.
99.1 Certification of the Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
99.2 Certification of the Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002
There were no reports filed on Form 8-K during the quarter ended June 30,
2002.
23
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned who is duly authorized.
BETA OIL & GAS, INC.
Date: August 14, 2002 By /s/ Joseph L. Burnett
------------------------
Joseph L. Burnett
Chief Financial Officer and
Principal Accounting Officer
24