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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
- ----------
SECURITIES EXCHANGE ACT OF 1934
For the Quarter Ended March 31, 2002
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ___________ to __________
Commission File 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 April 30, 2002, the Registrant had 12,392,557 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 March 31, 2002
(unaudited) and December 31, 2001..............................3
Condensed Consolidated Statements of Operations for the three
months ending March 31, 2002 and March 31, 2001 (unaudited)... 4
Condensed Consolidated Statements of Cash Flows for the three
months ending March 31, 2002 and March 31, 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.......................................14
Comparison of Results of Operations for the three months ended
March 31, 2002 and 2001 (unaudited)...........................16
Income Taxes.....................................................18
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.........18
PART II.- OTHER INFORMATION
ITEM 1. Legal Proceedings..................................................19
ITEM 2. Changes in Securities..............................................19
ITEM 6. Exhibits and Reports on Form 8-K...................................19
Signatures...................................................................19
-2-
PART I
ITEM 1. FINANCIAL STATEMENTS
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
MARCH 31, DECEMBER 31,
2002 2001
--------------- ---------------
CURRENT ASSETS: (Unaudited)
Cash $ 386,434 $ 556,199
Accounts receivable
Oil and gas sales 1,454,178 1,397,532
Other 811,138 754,390
Income tax receivable 37,943 38,503
Futures transaction hedge asset - 68,508
Prepaid expenses 181,964 187,495
--------------- ---------------
Total current assets 2,871,657 3,002,627
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties 58,447,433 58,708,444
Unevaluated properties 13,748,031 13,001,443
Less - accumulated amortization of full cost pool (26,161,533) (25,058,725)
--------------- ---------------
Net oil and gas properties 46,033,931 46,651,162
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system 1,491,516 1,491,516
Support equipment 221,413 221,413
Other 212,338 198,520
Less - accumulated depreciation (461,231) (408,430)
--------------- ---------------
Net other operating property and equipment 1,464,036 1,503,019
OTHER ASSETS 1,443,995 1,472,570
--------------- ---------------
TOTAL ASSETS $ 51,813,619 $ 52,629,378
=============== ===============
CURRENT LIABILITIES:
Current portion of long-term debt $ 71,583 $ 57,407
Accounts payable, trade 1,981,480 2,472,203
Dividends payable 110,256 112,708
Futures transaction hedge liability 640,867 -
Other accrued liabilities 330,025 463,859
--------------- ---------------
Total current liabilities 3,134,211 3,106,177
LONG-TERM DEBT, less current portion 13,645,324 13,648,727
COMMITMENTS AND CONTINGENCIES (NOTE 5)
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value, 5,000,000 shares
authorized; 604,272 issued and outstanding at
March 31, 2002 and December 31, 2001. Liquidation
value at March 31, 2002 is $5,804,719 604 604
Common stock, $.001 par value; 50,000,000 shares
authorized; 12,398,572 shares issued and 12,392,557
and 12,356,072 outstanding at March 31, 2002 and
December 31, 2001, respectively 12,399 12,399
Additional paid-in capital 51,829,405 51,814,699
Treasury stock, at cost; 6,015 shares and 42,500 shares
reacquired at March 31, 2002 and December 31, 2001,
respectively (28,153) (198,920)
Accumulated other comprehensive income (loss) (640,867) 68,508
Accumulated deficit (16,139,304) (15,822,816)
--------------- ---------------
Total stockholders' equity 35,034,084 35,874,474
--------------- ---------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 51,813,619 $ 52,629,378
=============== ==============
The accompanying notes are an integral part of these condensed consolidated
financial statements
-3-
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
FOR THE QUARTERS ENDED MARCH 31,
2002 2001
---------------- ----------------
REVENUES:
Oil and gas sales $ 2,259,513 $ 4,335,788
Field services 83,739 360,305
---------------- ----------------
Total revenue 2,343,252 4,696,093
---------------- ----------------
COSTS AND EXPENSES:
Lease operating expense 738,783 828,716
Field services 41,323 136,041
General and administrative 475,344 570,249
Depreciation and amortization expense 1,155,610 1,414,203
---------------- ----------------
Total costs and expenses 2,411,060 2,949,209
---------------- ----------------
INCOME (LOSS) FROM OPERATIONS (67,808) 1,746,884
---------------- ----------------
OTHER INCOME (EXPENSE):
Interest expense (140,611) (272,962)
Interest income and other 2,188 10,909
---------------- ----------------
Total other income (expense) (138,423) (262,053)
---------------- ----------------
INCOME (LOSS) BEFORE TAX PROVISION (206,231) 1,484,831
INCOME TAX PROVISION - (579,084)
---------------- ----------------
NET INCOME (LOSS) (206,231) 905,747
PREFERRED DIVIDENDS (110,256) -
---------------- ----------------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDER $ (316,487) $ 905,747
================ ================
BASIC NET INCOME (LOSS) PER COMMON SHARE $ (.03) $ .07
================ ================
DILUTED NET INCOME (LOSS) PER COMMON SHARE $ (.03) $ .07
================ ================
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS) $ (206,231) $ 905,747
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 (gain) loss on
qualifying cash flow hedges (net of income taxes) (118,348) 429,979
Unrealized gain (loss) on qualifying cash flow hedges
(net of income taxes) (591,028) 304,052
---------------- ----------------
TOTAL COMPREHENSIVE INCOME (LOSS) $ (915,607) $ 686,290
================ ================
The accompanying notes are an integral part of these condensed consolidated
financial statements
-4-
BETA OIL & GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
FOR THE QUARTERS ENDED MARCH 31,
2002 2001
---------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (206,231) $ 905,747
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation and amortization 1,155,610 1,414,203
Deferred income tax - 325,002
Change in operating assets and liabilities:
Accounts receivable (113,394) (190,534)
Income tax receivable 560 -
Prepaid expenses 5,531 (10,212)
Accounts payable, trade (490,723) (34,143)
Income taxes payable - 76,083
Other accrued expenses (133,833) 514,620
---------------- ----------------
Net cash provided by operating activities 217,520 3,000,766
---------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures (1,194,311) (3,094,716)
Proceeds received from sale of oil and gas
properties 879,501 -
Gas gathering and equipment expenditures (13,818) (126,622)
Change in other assets 28,575 139,580
---------------- ----------------
Net cash used in investing activities (300,053) (3,081,758)
---------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of warrants and options - 79,000
Proceeds from premiums payable 33,902 24,442
Repayment of premiums payable (20,015) (34,985)
Repayment of notes payable (3,116) (2,846)
Dividends paid (112,709) -
(Increase) decrease in deferred offering costs 14,706 (15,259)
---------------- ----------------
Net cash provided by (used in) financing activities (87,232) 50,352
---------------- ----------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (169,765) (30,640)
CASH AND CASH EQUIVALENTS, at beginning of period 556,199 1,536,186
---------------- ----------------
CASH AND CASH EQUIVALENTS, at end of period $ 386,434 $ 1,505,546
================ ================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest $ 92,781 $ 190,469
================ ================
Income taxes $ - $ 161,000
================ ================
SUPPLEMENTAL DISCLOSURE OF NON-CASH
INVESTING AND FINANCING ACTIVITIES
Cost of treasury stock issued for:
Oil and gas properties $ 170,767 $ -
================ ================
The accompanying notes are an integral part to these condensed consolidated
financial statements
-5-
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 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 March 31, 2002 and the results of its operations and cash flows for the three
months ended March 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 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 do not include all disclosures required by generally
accepted accounting principles. 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 March 31, 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.
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 three-month period ended March 31, 2002, the Company sold minority
interests in various internally generated prospects and unevaluated acreage for
approximately $879,500 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 - 10% of
the Company's 100% interest was sold. The Company plans to
reduce its interest further such that ultimately it has a 15%
working interest in the prospect when drilling. This acreage
is 100% unevaluated and has no proved reserves.
2.) North Mexican Sweetheart, 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 11% 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 2.5% 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 30%. 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 March 31, 2002, the Company held 6,015 treasury
shares with a fair market value of $28,153.
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.
Issuance of Warrants and Options
In February 2002, 25,000 non-callable common stock purchase warrants were
issued to a director with an exercise price of $5.22 and expiring in 2006. No
other warrants or options were issued during the first quarter 2002.
-7-
Note 4. NET INCOME (LOSS) PER COMMON SHARE:
The following represents the calculation of net income (loss)
per common share:
FOR THE THREE MONTHS ENDED
MARCH 31
----------------------------
2002 2001
------------ ------------
Basic
Net income (loss) ...................................... $ (206,231) $ 905,747
Less: preferred dividends .............................. 110,256 --
------------ ------------
Net income (loss) applicable to common
Shareholders ....................................... $ (316,487) $ 905,747
============ ============
Weighted average number of shares ...................... 12,390,935 12,353,439
============ ============
Basic earnings (loss) per share ........................ $ (.03) $ .07
============ ============
Diluted
Net income (loss) ...................................... $ (206,231) $ 905,747
Less: preferred dividends .............................. 110,256 --
------------ ------------
Net income (loss) applicable to common
Shareholders ....................................... $ (316,487) $ 905,747
============ ============
Weighted average number of shares ...................... 12,390,935 12,353,439
Common stock equivalent shares representing
shares issuable upon exercise of stock options ..... Antidilutive 24,872
Common stock equivalent shares representing
shares issuable upon exercise of warrants .......... Antidilutive 433,669
Common stock equivalent shares representing shares
"as-if" conversion of preferred shares ............. Antidilutive --
------------ ------------
Weighted average number of shares used in
calculation of diluted income (loss) per share ..... 12,390,935 12,811,980
============ ============
Diluted earnings (loss) per share ........................ $ (.03) $ .07
============ ============
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 will pay ONEOK $43,000 in addition to the
$282,096 of funds currently held by ONEOK. Each party will be 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.
-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 recorded a gain of $734,031 (net of $489,353
income tax) in the first quarter ended March 31, 2001.
Natural Gas - At March 31, 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
---------------------------------
Volume in Collars
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 March 31, 2002, the outstanding contracts had a negative fair market
value of $524,404 (net of $349,602 income tax) and accordingly the Company
recorded a derivative liability for such amount. The Company realized a gain on
the contracts settled in the quarter ended March 31, 2002 of $77,473 (net of
$51,648 income tax). These contracts are costless and no net premium is received
in cash or as a favorable rate.
Crude Oil - At March 31, 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
----------------------------------
Volume in Collars
Period Barrels Floor Ceiling
Oct 01- Mar 02 30,000 $25.00 $27.90
Apr 03 - Mar 03 60,000 $20.50 $21.75
At March 31, 2002, the outstanding contracts had a negative fair market
value of $116,463 (net of $77,642 income tax) and accordingly the Company
recorded a derivative liability for such amount. The Company realized a gain on
the contracts settled in quarter ended March 31, 2002 of $40,876 (net of $27,250
income tax). These contracts are costless and no net premium is received in cash
or as a favorable rate.
-9-
Note 7. SUBSEQUENT EVENTS
Subsequent to March 31, 2002, the Company's borrowing base was
re-determined and will remain at the current capacity of $14,400,000. The
Company currently has $13,634,652 outstanding against the borrowing base. The
maturity date of the current credit agreement has been extended to March 15,
2004.
-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 March 31, 2002 and December 31, 2001 and
the results of operations for the three-month periods ended March 31, 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
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 the level a year ago and 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
quarters indicated.
For the quarters ended March 31,
2002 2001
----------- -----------
Beginning cash balance ..................................... $ 556,199 $ 1,536,186
Sources of cash:
Cash provided by operations ........................... 217,520 3,000,766
Cash provided by financing activities ................. -- 50,352
Cash provided by sales of oil & gas properties and
equipment ....................................... 879,501 139,580
Other assets (including advance to industry partners) . 28,575 --
----------- -----------
Total sources of cash including cash on hand 1,681,795 4,726,884
Uses of cash:
Oil and gas expenditures .............................. (1,208,129) (3,094,716)
Cash used by financing activities ..................... (87,232) --
Other assets (including advance to industry partners) . -- (126,622)
----------- -----------
Total uses of cash ........................... (1,295,361) (3,221,338)
----------- -----------
Ending cash balance ........................................ $ 386,434 $ 1,505,546
=========== ===========
Our working capital was a deficit of ($262,554) at March 31, 2002 compared
to a surplus of $2,935,176 at March 31, 2001 and a deficit of ($103,550) at
December 31, 2001. The significant decrease in our working capital at March 31,
2002 from our working capital at March 31, 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. Our working capital deficit increased from December 31,
2001 mainly due to the futures derivative liability associated with our
production volume currently hedged.
Our liquidity has also been significantly reduced during the last twelve
months due to our intensive drilling and exploration program and a significant
decrease in natural gas and crude oil prices. Our principal source of short-term
liquidity is from operating cash flow. Should natural gas and crude oil prices
decrease further, our current operating cash flow would decrease and further
reduce our liquidity. Our short-term liquidity and working capital (excluding
impact of the futures derivative liability) did increase in the first quarter of
2002 due to a significant decrease in capital expenditures relating to our
drilling activity and reduction in current liabilities. During the quarter ended
March 31, 2002, we received approximately $879,500 from the reduction of our
working interests in certain unevaluated or proved undeveloped prospects which
are ready for drilling. We intend to further reduce our working interest in
certain prospects before drilling in order to recover a portion of our capital
spent on the land portion of the prospects and to enhance our risk profile. The
additional working capital raised will be used for our 2002 capital program and
debt reduction.
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 not increased and 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. Subsequent to
March 31, 2002, our borrowing base was re-determined and will remain at the
current capacity of $14,400,000. Currently, a balance of $13,634,652 is
outstanding against the borrowing base. Also the maturity date of the current
credit agreement was extended by one year to March 15, 2004.
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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
----------------------------------------------------------------------------------
Contractual Obligations Total Less than 1 1-3 years 4-5 years After 5 years
year
---------------- --------------- ---------------- ---------------- ---------------
Long - Term Debt (1) $13,716,907 $ 71,583 $13,645,324 $ - $ -
Operating Leases (2) 326,390 175,484 150,906 - -
---------------- --------------- ---------------- ---------------- ---------------
Total cash obligations $14,043,297 $ 247,067 $13,796,230 $ - $ -
================ =============== ================ ================ ===============
(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.
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.
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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 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
In the first quarter ended March 31, 2002, Waveland Drilling Partners
2002A, L.P. acquired an 8.5% working interest in our West Broussard, Lafayette
Parish, Louisiana prospect, a 10% 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 $648,500 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.
Plan of Operation for 2002
For the year 2002, we expect to fund our capital requirements from net cash
flow from operations (after general and administrative expense) and proceeds
received from the reduction or sale of our working interest in certain undrilled
prospects.
-14-
In the first quarter of 2002, we expended approximately $1.2 million, of
which approximately $.6 million related to our Jackson County drilling and
completion activity on the Signal Hill #1 and the Elk Hills #1 and approximately
$.4 million related to our drilling, seismic and land activity in the Brookshire
Dome area.
For the three-month period ended March 31, 2002, we participated in the
drilling of two gross (.7 net) exploratory wells and one gross (.3 net)
development well in the Brookshire Dome area, Waller County, Texas. The
development well was successfully completed during the three months ended March
31, 2002 and the two exploratory wells were discoveries and successfully
completed subsequent to March 31, 2002. We have a 30% working interest in the
development well and a 35% working interest in the exploratory wells.
In Jackson County, we participated with a 2% carried interest to casing
point in the drilling of Long Beach #1, an 18,000 foot Wilcox test well located
in Jackson County, Texas. Subsequent to March 31, 2002, the well reached the
objective depth and encountered the Wilcox sand but was deemed uneconomical. The
well was plugged and abandoned. Additionally, evaluation and testing continues
on the Elk Hills #1 Wilcox test which commenced drilling in late 2001.
The Rubel #1 (Sara White Prospect) located in Galveston County, Texas was
successfully completed in the "S" sand subsequent to March 31, 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
production in May 2002. We have a 31% working interest in the well.
We project our total 2002 capital expenditure to be approximately $7
million. The areas and amounts of concentration for the capital program will be:
o Jackson County, Texas - $1.2 million
o Red River and Lamar Counties, Texas - $.8 million
o Galveston County, Texas - $1.7 million
o Louisiana - $1.7 million
o Waller County, Texas - $1.0 million
o Other, including Australia - $.6 million
The allocation of the 2002 capital forecast may change materially pending
the actual results in our various areas of interest.
We are projecting our cash flows from operations to be approximately $4.8
million based on an average natural gas price of $2.37 per Mcf and $18.88 per
barrel and average net daily production of 10.0 MMcfE. Estimated proceeds from
sale and reduction of our working interests in certain evaluated and unevaluated
prospects are approximately $3.4 million. 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.
1) 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.
-15-
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 the first half of 2002.
2) We may seek mezzanine financing, if available, on terms
acceptable to us. Mezzanine financing usually involves debt with a
higher cost of capital as compared to conventional bank financing.
We would seek mezzanine 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.
3) 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 $7.5
million of net cash flow after deducting lease operating expenses of
approximately $3.0 million.
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 our interest in proposed wells;
3) Sell a portion of our interest in proposed wells and use the sale
proceeds to fund our participation for 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.
Comparison of Results of Operations
Quarter ended March 31, 2002 and Compared to Quarter ended March 31, 2001
We had a reported net loss of ($206,231) for the quarter ended March 31,
2002 compared to net income of $905,747 for the same period ended 2001. Lower
natural gas and crude oil prices contributed to the lower net income for the
period ended 2002 offset by lower operating, general and administrative,
depletion and interest expenses.
-16-
The following table summarizes key items of comparison and their related
increase (decrease) for the periods indicated.
In Thousands ......................... Quarters Ended March 31
----------------------- $-Increase %-Increase
2002 2001 (Decrease) (Decrease)
---------- ---------- ---------- ----------
Net income (loss) .................... $ (206.2) $ 905.7 $(1,111.9) --
Oil and gas sales .................... 2,259.5 4,335.8 (2,076.3) (48%)
Field service income ................. 83.7 360.3 (276.6) (77%)
Operating expense .................... 738.8 828.7 (89.9) (11%)
Field service expense ................ 41.3 136.0 (94.7) (70%)
G&A expense .......................... 475.3 570.2 (94.9) (17%)
Depletion - Full cost ................ 1,102.8 1,284.8 (182.0) (14%)
Depreciation - Field Service and Other 52.8 129.4 (76.6) (59%)
Interest expense ..................... 140.6 273.0 (132.4) (48%)
Income tax provision (benefit) ....... -- 579.1 (579.1) --
Production:
Natural Gas - Mcf .................... 574.8 611.4 (36.6) (6%)
Crude Oil - Bbl ...................... 39.9 25.3 14.6 58%
Natural Gas Equivalent - McfE ........ 814.2 763.4 50.8 7%
$ per unit:
Ave. gas price - Mcf ................. $ 2.51 $ 5.93 $ (3.42) (58%)
Ave. oil price - Bbl ................. 20.55 28.13 (7.58) (27%)
Ave. operating expense - McfE ........ .91 1.09 (.18) (17%)
Ave. G&A - McfE .75 .58 (.17) (23%)
Ave. Depl. - Full cost - McfE ........ 1.35 1.68 (.33) (20%)
For the quarter ended March 31, 2002, oil and gas sales decreased
$2,076,275 or 48%, from the same quarter ended 2001, to $2,259,513. The decrease
resulted from lower natural gas and crude oil prices in the quarter ended March
31, 2002, which was partially offset by increased sales volume for the period.
The lower commodity prices resulted in decreased revenue of approximately
$2,267,824. Lower natural gas prices comprised 87% of the decrease with lower
crude oil prices accounting for the remaining 13%. 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
March 31, 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. 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.
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 40% of our production on an equivalent
Mcf basis for the quarter ended March 31, 2002. Based on our natural gas
production for the three months ended March 31, 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.
Operating expenses, including production and ad valorem taxes, decreased
$89,933, or 11%, to $738,783 for the quarter ended March 31, 2002 compared to
the same period for 2001. The decrease was primarily due to lower production
taxes, which are based on natural gas and crude oil revenues.
-17-
Field service expense, which relates to the operation of our McIntosh
County gathering system, decreased $94,718, or 70%, to $41,323 for the quarter
ended March 31, 2002 compared to the same period for 2001. The decrease was due
to lower production taxes associated with the portion of gathering revenues,
which are based on a percentage of the gas price received by the producer. Since
the natural gas prices were substantially lower for the quarter ended March 31,
2002 when compared to the same quarter ended 2001, the corresponding production
taxes decreased.
General and administrative expenses for the three months ended March 31,
2002 decreased approximately $94,905, or 16%, to $475,344 compared to $570,249
for the same period in 2001. The decrease was due to lower outside services,
legal and audit expenses and increased overhead reimbursement associated with
our operations in the Brookshire Dome area.
Depletion and depreciation expense decreased $258,593, or 18%, from the
same period in 2001 to $1,155,610 for the three months ended March 31, 2002.
Depletion expense associated with evaluated oil and gas properties comprised
$217,050 of the decrease. The decrease was due to a lower net evaluated cost
basis for our evaluated properties at March 31, 2002 when compared to March 31,
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. The
decrease due to lower capitalized costs was partially offset by an increase in
depletion expense due to a higher production volume for the three months ended
March 31, 2002 compared to the same period ended 2001. Depletion expense on a
per McfE for the three months ended March 31, 2002 was $1.35 per McfE compared
to $1.68 per McfE for the same period in 2001. Depreciation expense related to
other assets decreased $41,543 from the same period in 2001 to $52,802 for the
three months ended March 31, 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
March 31, 2002 resulted in lower depreciation expense for the period.
Interest expense decreased for three months ended March 31, 2002, compared
to the same period 2001, as a result of lower interest rates.
Income Taxes
As of March 31, 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 month of December 2001
production rate, we have approximately 53% of our future natural gas production
hedged through February 2003. We have approximately 41% 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.
-18-
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
See Note 5 to Consolidated Financial Statements.
Item 2. Changes in Securities
In January 2002, we issued 36,485 treasury shares of common stock
to Relucent.com ltd.co for geological and geophysical services associated with
certain of its unevaluated properties. These shares were issued in compliance
with the terms of an agreement for services dated September 15, 2001. The fair
value of the shares was $170,767 or $4.60 per share. No underwriters were
involved in the transaction. The buyers were considered qualified investors. The
transaction was exempt from registration under Section 4(2).
In February 2002, 25,000 non-callable common stock purchase warrants were
issued to a director with an exercise price of $5.22 and expiring in 2006. No
other warrants or options were issued during the first quarter 2002.
Item 6. Exhibits and Reports on Form 8-K
(a) No exhibits are filed with this report:
(b) There were no reports filed on Form 8-K during the quarter ended
March 31, 2002.
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: May 15, 2002 By /s/ Joseph L. Burnett
------------------------
Joseph L. Burnett
Chief Financial Officer and
Principal Accounting Officer
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