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SECURITIES AND EXCHANGE COMMISSION
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WASHINGTON, D.C. 20549
FORM 8-K
Current Report Pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
Date of Report (date of earliest event reported):
SEPTEMBER 5, 2000 (AUGUST 30, 2000)
BETA OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
Nevada 333-68381 86-0876964
(State or other jurisdiction of (Commission File Number) (I.R.S. Employer
incorporation or organization) 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)
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Item 1. NOT APPLICABLE
Item 2. ACQUISITION OR DISPOSITION OF ASSETS
On August 30, 2000, Beta Oil and Gas, Inc. ("Beta") closed the previously
reported Agreement and Plan of Merger ("Agreement") to acquire 100% interest in
Red River Energy, Inc. ("Red River"). The acquisition was consummated through a
merger ("Merger") between Beta Acquisition Company, Inc., a wholly-owned
subsidiary of Beta, and Red River following approval of the Agreement.
The assets of Red River consist of five components: 1) a 97.4% working interest
(80% net revenue interest) in a 30,160 acre unit which is currently producing
approximately 2.8 net MMBTU/d and 96 net Bopd from 22 active wells in the Hunton
Limestone formation in Central Oklahoma; 2) an 85% working interest (68% net
revenue interest) in 8,100 acres which are currently producing 630 net MMBTU/d
from 45 wells in the Atoka and Gilcrease formations in Eastern Oklahoma; 3) a
gas gathering system consisting of 40 miles of pipeline which is currently
transporting approximately 1950 MMBTU/d in Eastern Oklahoma; 4) a 46 well coal
bed methane project also located in Eastern Oklahoma which is operated by Red
River and is currently under development and producing approximately 600
MMBTU/d; and 5) as of June 14, 2000 Red River purchased from ONEOK Resources
Company, 124 oil and gas properties and prospects in 26 fields in Kansas,
Oklahoma and Texas and is currently producing approximately 1050 net MMBTU/d and
128 net Bopd.
For financial accounting purposes, the Merger will be accounted for using the
purchase method of accounting. Beta's cost to acquire Red River calculated to be
$14.455 million assuming an average Beta common stock price of $6.38 per share
with 2,250,000 shares issued to the stockholders of Red River which will be
allocated to the assets acquired and liabilities assumed according to their fair
values. The aggregate market value of the common stock issued to Red River was
20,250,000 on August 30, 2000, the date the Agreement was signed by the parties
to the Agreement.
Mr. Rolf Hufnagel, former President and a former Director of Red River, and
Robert E. Davis, Jr., former Chief Financial Officer and a former Director of
Red River, have entered into three-year employment agreements with Beta.
Additionally, Mr. Hufnagel has been elected to Beta's board of directors.
Messrs. Hufnagel and Davis negotiated the terms of the Merger Agreement and
participated in the discussion, deliberation and voting of the Red River board
to adopt the Merger Agreement.
Item 3. NOT APPLICABLE
Item 4. NOT APPLICABLE
Item 5. NOT APPLICABLE
Item 6. NOT APPLICABLE
Item 7. FINANCIAL STATEMENTS AND EXHIBITS
-2-
(a) Financial Statements of Business Acquired.
(1) Red River Energy,Inc. and Subsidiaries Consolidated Balance Sheets as
of December 31, 1999 and 1998 and the Related Consolidated Statements of Income
and Retained Earnings and of Consolidated Cash Flows and Independent Auditors'
Report.
(2) ONEOK Resources Company Statements of Revenues and Direct Operating
Expenses of Certain Properties sold to Red River Energy, Inc.for the years ended
December 31, 1998 and 1999.
(b) Pro Forma Financial Information.
(1) Beta Oil & Gas, Inc. Pro Forma Combined Condensed Consolidated Balance
Sheet as of June 30, 2000.
(2) Beta Oil & Gas, Inc. Unaudited Pro Forma Combined Condensed
Consolidated Statements of Operations for the Year Ended December 31, 1999 and
the six months ended June 30, 2000.
(3) Notes to Pro Forma Condensed Consolidated Financial Statements
(unaudited).
(c) Exhibits.
(1) Press Release dated August 31, 2000.
Item 8. NOT APPLICABLE
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: September 5, 2000 By /s/ Joseph L. Burnett
Joseph L. Burnett
Chief Financial Officer and
Principal Accounting Officer
-3-
Red River Energy, Inc.
and Subsidiaries
Consolidated Financial Statements
For the Years Ended
December 31, 1998 and 1999 and
For the Six Months Ended
June 30, 1999 and 2000
F-1
INDEX TO FINANCIAL STATEMENTS
Page
Independent Auditor's Report...................................................................F-2
Consolidated Balance Sheets - December 31, 1998, 1999 and June 30, 2000 (unaudited)............F-3
Consolidated Statements of Operations - For the Years Ended December 31, 1998 and 1999 and
For the Six Months Ended June 30, 1999 and 2000 (unaudited)...............................F-4
Consolidated Statement of Stockholders' Equity - For the Years Ended December 31, 1998
and 1999 and For the Six Months Ended June 30, 2000 (unaudited)...........................F-5
Consolidated Statements of Cash Flows - For the Years Ended December 31, 1998 and 1999 and
For the Six Months Ended June 30, 1999 and 2000 (unaudited)...............................F-6
Notes to Consolidated Financial Statements.....................................................F-8
F-2
INDEPENDENT AUDITOR'S REPORT
The Stockholders and Board of Directors
Red River Energy, Inc.
Tulsa, Oklahoma
We have audited the consolidated balance sheets of Red River Energy, Inc. and
subsidiaries as of December 31, 1998 and 1999, and the related consolidated
statements of operations, stockholders' equity, and cash flows for the years
then ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Red River Energy,
Inc. and subsidiaries as of December 31, 1998 and 1999 and the results of their
operations and their cash flows for the years then ended in conformity with
generally accepted accounting principles.
/s/Hein + Associates llp
Hein + Associates llp
Certified Public Accountants
Orange, California
February 16, 2000
F-3
RED RIVER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
December 31, December 31, June 30,
1998 1999 2000
------------ ------------ ------------
.................................................................. (unaudited)
ASSETS
Current Assets:
Cash ...................................................... $ 48,980 $ 366,653 $ 256,697
Accounts receivable ....................................... 335,002 308,572 485,878
Advance on drilling contract .............................. 30,000 -- --
Due from ONEOK Resources Company .......................... -- -- 367,250
Prepaid expenses .......................................... -- 600 53,760
---------- ---------- -----------
Total current assets .................................. 413,982 675,825 1,163,585
Oil and Gas Properties, at cost (full cost method)
Evaluated properties ...................................... 5,224,845 5,897,603 10,193,321
Unevaluated properties .................................... 1,143,656 2,708,661 2,863,257
Less - accumulated amortization of full cost pool ......... (137,936) (548,334) (816,114)
---------- ---------- -----------
Net oil and gas properties ............................ 6,230,565 8,057,930 12,240,464
Other Operating Property and Equipment, at cost
Gas gathering system ...................................... -- 1,303,160 1,335,431
Support equipment ......................................... 1,012,335 1,096,415 2,426,069
Less - accumulated depreciation ........................... (38,118) (201,315) (331,678)
Net other operating property and equipment ............ 974,217 2,198,260 3,429,822
Furniture, Fixtures and Equipment, net ......................... 39,316 28,194 25,441
Other assets ................................................... -- 8,818 8,818
---------- ------------ ------------
Total Assets ................................................... $ 7,658,080 $ 10,969,027 $ 16,868,130
============== ============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt ......................... $ 68,424 $ 2,233,176 $ 2,236,565
Accounts payable, trade ................................... 303,931 161,329 421,733
Accounts payable, related party ........................... 95,931 57,023 6,694
Accrued interest .......................................... 36,154 126,989 112,999
Other accrued liabilities ................................. 2,300 60,855 66,674
---------- ----------- -----------
Total current liabilities ............................. 506,740 2,639,372 2,844,665
Long-Term Debt, less current portion ........................... 6,421,095 7,767,386 13,337,498
---------- ------------ -----------
Total liabilities ......................................... 6,927,835 10,406,758 16,182,163
Commitments (Note 8) ........................................... -- -- --
Stockholders' Equity
Common stock, $1.00 par value, 50,000 shares authorized,
1,000 shares issued and outstanding ..................... 1,000 1,000 1,000
Additional paid-in capital ................................ 1,238,911 1,255,500 1,240,500
Accumulated deficit ....................................... (509,666) (694,231) (555,533)
---------- ---------- -----------
Total stockholders' equity ..................................... 730,245 562,269 685,967
---------- ---------- ----------
Total Liabilities and Stockholders' Equity ..................... $ 7,658,080 $ 10,969,027 $ 16,868,130
========== =========== ==========
F-4
RED RIVER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
For the years ended For the six months ended
December 31, June 30,
1998 1999 1999 2000
------------------ ------------------ ----------------- ------------------
(unaudited) (unaudited)
Revenues:
Oil and gas sales $ 865,356 $ 2,852,121 $ 1,148,192 $ 1,802,770
Field services - 336,637 87,811 278,162
---------- ----------- ----------- ------------
Total revenue 865,356 3,188,758 1,236,003 2,080,932
---------- ----------- -----------
Costs and Expenses:
Oil and gas production costs 316,533 1,148,421 494,221 404,560
Field services - 148,354 42,666 120,978
General and administrative 685,573 980,627 470,892 671,762
Depreciation, depletion and
amortization expense 182,747 586,095 246,518 405,609
---------- ---------- ---------- ----------
Total costs and expenses 1,184,853 2,863,497 1,254,297 1,602,909
---------- ---------- ---------- ----------
Income (Loss) From Operations (319,497) 325,261 (18,294) 478,023
---------- ----------- ---------- ---------
Other Income (Expense):
Gain (loss) on sale of fixed assets (20,000) 2,438 2,438 -
Interest expense, net (168,851) (512,264) (249,092) (339,306)
Other, net (1,318) - - (19)
---------- ---------- --------- ----------
Total other income (expense) (190,169) (509,826) (246,654) (339,325)
---------- ---------- ---------- -----------
Net Income (Loss) $ (509,666) $ (184,565) $ (264,948) $ 138,698
=========== =========== =========== ===========
F-5
RED RIVER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1999 AND
FOR THE SIX MONTHS ENDED JUNE 30, 2000 (UNAUDITED)
See accompanying notes to consolidated financial statements.
Additional Total
Common Stock Paid-in Accumulated Stockholders'
Shares Amount Capital Deficit Equity
---------- ------------ ----------- ------------- -------------
Common stock issued to form the company . 1,000 $ 1,000 $ 379,000 $ -- $ 380,000
Contribution of equipment by officers ... -- -- 774,000 -- 774,000
Contribution of salaries by stockholders -- -- 217,800 -- 217,800
Additional cash contributions by officers -- -- 38,565 -- 38,565
Distributions to stockholders ........... -- -- (170,454) -- (170,454)
Net loss ............................ -- -- -- (509,666) (509,666)
---------- ---------- ---------- ---------- ----------
Balances, December 31, 1998 ............. 1,000 1,000 1,238,911 (509,666) 730,245
Contribution of salaries by stockholders -- -- 151,200 -- 151,200
Distributions to stockholders ........... -- -- (134,611) -- (134,611)
Net loss ............................ -- -- -- (184,565) (184,565)
----------- ---------- ----------- ------------ ----------
Balances, December 31, 1999 ............. 1,000 1,000 1,255,500 (694,231) 562,269
Distributions to stockholders (unaudited) -- -- (15,000) -- (15,000)
Net income (unaudited) .............. -- -- -- 138,698 138,698
----------- ----------- ----------- ------------- ----------
Balances, June 30, 2000 (unaudited) ..... 1,000 $ 1,000 $ 1,240,500 $ (555,533) $ 685,967
=========== ========== =========== ============ ==========
F-6
RED RIVER ENERGY, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
See accompanying notes to consolidated financial statements.
For the years ended for the six months ended
December 31, June 30,
1998 1999 1999 2000
------------ ------------ ------------ -----------
Cash Flows From Operating Activities: .............. (unaudited) (unaudited)
Net income (loss) ............................. $ (509,666) $ (184,565) $ (264,948) $ 138,698
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion, and
amortization ........................... 182,747 586,095 246,518 405,609
Contribution of salaries by stockholders 217,800 151,200 138,600 --
(Gain) loss on sale of equipment .......... 20,000 (2,438) (2,438) --
(Increase) decrease in:
Accounts receivable ....................... (335,002) 26,430 59,352 (177,306)
Advance in drilling contract .............. (30,000) 30,000 30,000 --
Prepaid expenses .......................... -- (600) (4,095) (68,160)
Other assets .............................. -- (8,818) -- --
Increase (decrease) in:
Accounts payable, trade ................... 303,931 (142,602) (81,477) 263,154
Accounts payable, related party ........... 95,931 (38,908) -- (50,329)
Accrued interest .......................... 36,154 90,835 (33,608) (13,990)
Other accrued liabilities ................. 2,300 58,555 37,410 5,819
----------- ----------- ----------- -----------
Net cash provided by (used in) operating activities (15,805) 565,184 125,314 503,495
----------- ----------- ----------- -----------
Cash Flows From Investing Activities:
Capital expenditures for:
Evaluated oil and gas property ............ (5,224,845) (672,758) (1,160,035) (154,596)
Unevaluated oil and gas property .......... (1,127,656) (1,565,005) (666,098) (266,425)
Gas gathering system ...................... -- (1,303,160) (1,294,296) (32,271)
Support equipment ......................... (284,335) (106,623) (97,097) (121,008)
Furniture, fixtures and equipment ......... (46,009) (1,378) (640) (3,842)
Proceeds from sale of property and equipment 10,000 24,981 24,981 --
----------- ------------ ----------- ----------
Net cash (used in) investing activities ....... (6,672,845) (3,623,943) (3,193,185) (578,142)
----------- ------------ ----------- ----------
F-7
RED RIVER ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
See accompanying notes to consolidated financial statements.
for the years ended for the six months ended
December 31, June 30,
1998 1999 1999 2000
----------- ----------- ---------- -----------
Cash Flows From Financing Activities: ........... (Unaudited) (unaudited)
Cash borrowings from line of credit ........ 6,274,734 3,584,729 3,204,931 --
Issuance of notes payable .................. 345,000 -- -- --
Principal payments on borrowings ........... (130,215) (73,686) (38,921) (35,309)
Proceeds from sale of stock ................ 380,000 -- -- --
Capital contributions ...................... 38,565 -- -- --
Distributions to stockholders .............. (170,454) (134,611) (7,284) --
----------- ----------- ----------- -----------
Net cash provided (used) by financing
activities .............................. 6,737,630 3,376,432 3,158,726 (35,309)
----------- ----------- ----------- ------------
Increase in Cash and Cash Equivalents
48,980 317,673 90,855 (109,956)
Cash and Cash Equivalents, at beginning of period -- 48,980 48,980 366,653
========== ========== ============ =============
Cash and Cash Equivalents, at end of period
$ 48,980 $ 366,653 $ 139,835 $ 256,697
Supplemental Disclosure of Cash Flow Information
Cash paid for:
Interest ............................... $ 152,342 $ 499,380 $ 365,746 $ 459,213
========== ========== ============ =============
Non-cash investing and financing transactions:
Assets contributed by stockholders ..... $ 774,000 $ -- $ -- $ --
========== ========== ============ ============
Assets financed through additional
borrowings under bank financing
$ -- $ -- $ -- $ 5,608,809
========== ========== ============ =============
F-8
RED RIVER ENERGY, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Information subsequent to December 31, 1999 is unaudited)
1. Nature of Operations:
Red River Energy, LLC ("Red River Energy") was incorporated in the State of
Oklahoma in November 1997, with operations commencing in February 1998, to
engage in the business of oil and gas exploration, acquisition, production,
development, marketing, and transportation in the United States.
The Company also conducts business through its subsidiaries TCM, LLC ("TCM") and
Red River Field Services, LLC ("Red River Field"). TCM was formed by Red River
Energy and was incorporated in the State of Oklahoma in November 1997, with
operations commencing in August 1998, to explore, produce, market, and transport
coal bed methane gas from leases located in Eastern Oklahoma. Red River Field
was incorporated in the State of Oklahoma in March 1999 to market and transport
gas produced by Red River Energy and others from leasehold interests located in
Eastern Oklahoma.
In November 1999, the members of Red River Energy exchanged their units of
ownership interest for stock in Red River Energy, Inc. (Red River) an Oklahoma
corporation that has elected to be taxed as an S corporation. As a result of
this transaction, Red River is now the parent of Red River Energy and the former
members of Red River Energy now own all of the issued and outstanding stock of
Red River.
Also in November 1999, Red River entered into a binding Agreement and Plan of
Merger with Beta Oil & Gas Inc. (Beta). The merger consideration consists of
Beta common stock. Under the agreement, Beta has also agreed to guarantee
certain of the Company's bank indebtedness. Upon closing of the agreement, the
shareholders of Red River will convert all issued and outstanding common stock
into 2.25 million shares of Beta common stock. Completion of the agreement is
contingent upon approval by Beta shareholders.
2. Summary of Significant Accounting Policies:
Principles of Consolidation - The consolidated financial statements include the
accounts of Red River and subsidiaries ("the Company"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
TCM has 1,000 member units outstanding at December 31, 1999 with 800 units owned
by the Company and 200 units owned individually by a stockholder of the Company
as a minority interest. Upon formation of TCM, the Company committed to
contribute cash and assets to be used on establishing and developing TCM. The
minority member contributed cash of $20. For the additional cash and assets
contributed, the Company received no additional ownership units. Under the
operating agreement, the Company is to receive all income and losses of TCM
until such time as the total amount of income allocated to the Company equals
the amount of cash, service, and equipment contributions made to TCM.
Thereafter, profits and losses of TCM will be allocated to the two owners in
proportion to their respective ownership interests. Distributions are limited to
available cash as defined in the operating agreement.
F-9
Use of Estimates - The preparation of the Company's consolidated financial
statements in conformity with generally accepted accounting principles requires
the Company's management to make estimates and assumptions that affect the
amounts reported in these financial statements and accompanying notes. Actual
results could differ from those estimates.
The Company's financial statements are based on significant estimates including
the selection of useful lives for property, plant and equipment, and oil and gas
reserve quantities which form the basis for the calculation of amortization and
impairment of oil and gas properties. Management emphasizes that reserve
estimates are inherently imprecise and that estimates of more recent discoveries
are more imprecise than those for properties with long production histories.
Oil and Gas Properties - The Company follows the full cost method of accounting
for oil and gas producing activities and, accordingly, capitalizes 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. All 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 reserves on a country by country
basis. Unevaluated oil and gas properties are assessed for impairment either
individually or on an aggregate 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%, and the lower of cost
or estimated fair value of unproved properties, net of tax considerations.
Joint Ventures - All exploration and production activities are conducted jointly
with others and, accordingly, the accounts reflect only the Company's
proportionate interest in such activities.
Revenue Recognition - The Company recognizes oil and gas sales upon delivery to
the purchaser.
Furniture, Fixtures and Equipment - Furniture, fixtures, and equipment are
stated at cost. Provision for depreciation and amortization on property and
equipment is calculated using the straight-line and accelerated methods over the
estimated useful lives (ranging from 3 to 5 years) of the respective assets. The
cost of normal maintenance and repairs is charged to operating expense as
incurred. Material expenditures, which increase the life of an asset, are
capitalized and depreciated over the estimated remaining useful life of the
asset. The cost of properties sold, or otherwise disposed of, and the related
accumulated depreciation or amortization are removed from the accounts, and any
gain or losses are reflected in current operations.
Impairment of Long-Lived Assets - In the event that facts and circumstances
indicate that the costs of long-lived assets, other than oil and gas properties,
may be impaired, an evaluation of recoverability would be performed. If an
evaluation is required, the estimated future undiscounted cash flows associated
with the asset would be compared to the asset's carrying amount to determine if
a write-down to market value or discounted cash flow value is required.
Impairment of oil and gas properties is evaluated subject to the full cost
ceiling as described under oil and gas properties.
Income Taxes - No provision has been made for income taxes since the Company has
elected to be taxed as an "S Corporation" as defined in the Internal Revenue
Code. The Company's shareholders will report the Company's taxable income or
loss on their individual tax returns.
F-10
Concentrations of Credit Risk - Credit risk represents the accounting loss that
would be recognized at the reporting date if counterparties 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 described below. In accordance with FASB
Statement No. 105, Disclosure of Information about Financial Instruments with
Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit
Risk, the credit risk amounts shown in cash and accounts receivable do not take
into account the value of any collateral or security.
The Company operates primarily in the oil and gas industry within the United
States. Oil and gas sales are based solely on short-term purchase contracts from
three customers with related accounts receivable subject to credit risk.
Fair Value of Financial Instruments - The estimated fair values for financial
instruments under FASB Statement No. 107, Disclosures about Fair Value of
Financial Instruments, are determined at discrete points in time based on
relevant market information. These estimates involve uncertainties and cannot be
determined with precision. The estimated fair values of the Company's financial
instruments, which includes all cash, accounts receivable, accounts payable, and
long term debt approximates the carrying values in the financial statements at
December 31, 1998 and 1999.
Hedging Activities - The Company uses derivative commodity instruments to manage
commodity price risk associated with future natural gas and crude oil
production, but does not use them for speculative purposes. The Company's
commodity price hedging program utilizes swap contracts. To qualify as a hedge,
these contracts must correlate to anticipated future production such that the
Company's exposure to the effects of commodity price changes is reduced. The
gains and losses related to these hedging transactions are recognized as
adjustments to revenue recorded for the related production. No such contracts
were outstanding as of December 31, 1998. As of December 31, 1999, the Company
had contracts expiring on March 31, 2000 on the sale of 315,000 Mmbtu of gas at
an average price of $2.62 per Mmbtu. Effective April 1, 2000, the Company has
committed to sell 225,000 Mmbtu of natural gas at a price of $2.46 per Mmbtu and
108,000 Mmbtus at a price of $2.49 per Mmbtu through June 30, 2000. Effective
July 1, 2000, the Company has committed for one year to sell 985,500 Mmbtu of
natural gas at a price of $3.085 per Mmbtu, representing approximately 60% of
Red River's average daily gas production.
Statement of Cash Flows - For purposes of the statement of cash flows, the
Company considers all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents.
Impact of Recently Issued Standards - In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133
(FASB133), "Accounting for Derivative Instruments and Hedging Activities." This
statement was effective for fiscal years beginning after June 15, 1999. However,
in July 1999, FASB137 was issued delaying the effective date of FASB133 for one
year, to fiscal years beginning after June 15, 2000. FASB133 requires that an
entity recognize all derivatives as assets or liabilities in the statement of
financial position and measure their instruments at fair value. The Company has
not yet determined the impact of FASB133 on its financial statements.
F-11
Segment Information - The Company has adopted SFAS 131, "Disclosure about
Segments of an Enterprise and Related Information." As defined in that Standard,
the Company operates in only one segment, oil and gas exploration.
Interim Financial Information - The June 30, 1999 and 2000 financial statements
have been prepared by the Company without audit. In the opinion of management,
the accompanying financial statements contain all adjustments (consisting of
only normal recurring accruals) necessary for a fair presentation of the
Company's financial position as of June 30, 2000 and the results of operations
and cash flows for the six months ended June 30, 1999 and 2000. The results of
operations for the six months ended June 30, 1999 and 2000 are not necessarily
indicative of those that will be obtained for the entire fiscal year.
3. Basis of Presentation:
As reflected in the accompanying financial statements, the Company has incurred
net losses of $509,666 and $184,565 for the years ending December 31, 1998 and
1999, respectively and has negative working capital of $1,963,547 as of December
31, 1999. Net losses of $376,634 and $483,826 for the years ended December 31,
1998 and 1999, respectively, and negative working capital of $2,255,980 as of
December 31, 1999 are attributable to TCM. As discussed in Note 7, the Company
is in the process of renegotiating the payment terms of TCM's loan with an
energy financial services company. If the Company is unsuccessful and becomes in
default under the loan, the lender's recourse is solely to certain assets of
TCM. The remainder of the Company's operations are profitable and are generating
sufficient cash flows to pay the Company's obligations as they come due and, in
management's opinion, will continue to do so for at least the next year.
4. Summary of Oil and Gas Operations:
Property Acquisitions - In July 1998, the Company acquired a 97.4% working
interest (80.0% net revenue interest) in a producing oil and gas prospect in
Central Oklahoma for a cash payment of $5,258,000. The property includes a
30,160-acre unit producing from 22 active wells. In March 1999, the Company
acquired an 85.0% working interest (68.0% net revenue interest) in 7,500 acres
that are currently producing from 45 active wells in Eastern Oklahoma for a cash
payment of $1,950,000. The property also includes a gas gathering system
consisting of 40 miles of pipeline transporting gas produced to Eastern
Oklahoma.
On June 14, 2000, Red River completed the purchase of 124 properties and
prospects in 26 fields located in Kansas, Oklahoma, and Texas from ONEOK
Resources Company. The purchase price is $5,608,809, subject to final post
closing adjustments for production revenues and operational expenses between the
effective date of January 1, 2000 through the closing date of June 14, 2000, and
in connection with any exercise by third parties of existing preferential
purchase rights. At June 30, 2000, the Company has estimated that a post closing
adjustment of $367,250 is due from the seller.
F-12
Full Cost Amortization Expense - Amortization expense amounted to $137,936,
$410,398, and $271,029 for the years ended December 31, 1998 and 1999 and the
six month period ended June 30, 2000, respectively. Amortization expense per
equivalent units of oil and gas produced amounted to $1.58, $2.21 and $2.60 per
barrel for the years ended December 31, 1998, 1999 and for the six month period
ended June 30, 2000, respectively. Natural gas is converted to equivalent units
of oil on the basis of six MCF of gas to one equivalent barrel of oil.
Unevaluated Oil and Gas Properties - The Company is currently developing a 76
well coal bed methane project located in Eastern Oklahoma. As of June 30, 2000,
the evaluation of the property had not been completed through exploration, and
therefore is not included in the depletion base. The completed wells are
currently producing gas and water and have generated revenue of $168,518 and
$106,624 during the year ended December 31, 1999 and the six months ended June
30, 2000, respectively, but it has not yet been determined whether the wells
will produce gas in commercial quantities.
The Company is in the process of testing various completion techniques in an
effort to effectively de-water the coal beds and optimize gas production. It is
estimated that six to nine months of additional operational data will be
required to effectively evaluate the properties. Drilling is expected to
continue on the prospects through the year ended December 31, 2000 and in future
periods. As the prospect is evaluated through future drilling and testing
operations, the property development and exploration costs associated with the
wells drilled will be transferred to evaluated properties and included in the
depletion base.
Capitalization of Interest - For the years ended December 31, 1998 and 1999 and
the six month period ended June 30, 2000, the Company capitalized interest costs
of $18,896, $176,498 and $113,008 respectively, related to the unevaluated oil
and gas properties' exploration activities.
Costs Included in Oil and Gas Producing Activities - Costs incurred in oil and
gas producing activities, all of which have been in the United States, are as
follows:
December 31, June 30,
1998 1999 2000
---------- ---------- ----------
(unaudited)
Property Acquisition $5,224,845 $ 672,758 4,068,448
---------- ---------- ----------
Exploration .......... $1,143,656 $1,565,005 381,866
---------- ---------- ----------
Development .......... $ -- $ -- --
---------- ---------- ----------
F-13
5. Other Operating Property and Equipment:
Other operating property and equipment are the 40 miles of pipeline acquired
during 1999 in Eastern Oklahoma and specific equipment and vehicles related to
the oil and gas activities purchased in 1998, 1999 and 2000. During the years
ended December 31, 1998 and 1999 and the six month period ended June 30, 2000,
the Company recorded depreciation expense of $38,118, $163,197 and $131,973,
respectively.
At June 30, 2000, support equipment with a net book value of $705,000 was
classified as idle. In management's opinion, the net book value of the idle
equipment is not in excess of net realizable value.
6. Furniture, Fixtures and Equipment:
Property and equipment consisted of the following:
December 31, June 30,
-------- -------- --------
(unaudited)
Office equipment .............. $ 40,000 $ 40,000 40,000
Computer equipment ............ 6,009 7,387 10,491
Less- Accumulated depreciation (6,693) (19,193) (25,050)
-------- -------- --------
$ 39,316 $ 28,194 25,441
-------- -------- --------
During the years ended December 31, 1998 and 1999 and the six months ended June
30, 2000, the Company recorded depreciation expense of $6,693, $12,500 and
$5,857, respectively.
7. Long-Term Debt:
Long-term debt consisted of the following:
December 31, June 30,
1998 1999 2000
------------ ------------- -------------
(unaudited)
Note payable under a revolving credit agreement, due July 31, 2001,
bearing interest at the prime rate minus .25% (7.627% at December 31,
1999), accrued interest payable monthly, collateralized by
substantially all oil and gas properties owned by Red River Energy and
Red River Field.
$ 5,413,000 $ 7,694,676 $ 13,303,038
F-14
December 31, June 30,
1998 1999 2000
------------ ------------ -----------
(unaudited)
Note payable under a revolving credit agreement, monthly payments of
principal and accrued interest equal to 100% of the net production
proceeds of specific coal bed methane wells, final payment on outstanding
principal and interest due July 31, 2002, bearing interest at the prime
rate plus 1.50% (8.50% at December 31, 1999), collateralized by certain
assets of TCM.
861,734 2,165,234 2,165,234
Note payable, due in monthly installments of $6,845 including interest of
7.50% maturing on October 31, 2001, unsecured.
214,785 140,652 105,791
------------- ---------- -----------
$ 6,489,519 10,000,562 15,574,063
------------- ---------- -----------
Less current portion 68,424 2,233,176 2,236,565
------------- ---------- -----------
$ 6,421,095 $7,767,386 $ 13,337,498
------------- ----------- -------------
The $13,303,038 note at June 30, 2000 arises from a credit agreement with a
commercial bank for Red River Energy that provides for maximum outstanding
borrowings aggregating $25 million and maturing on July 31, 2001. The aggregate
amount of advances under the revolving credit agreement are limited to a
collateral borrowing base of $5.8 million at December 31, 1998 and $9.2 at
December 31, 1999 and $13,900,000 at June 30, 2000. The shareholders have
committed to a limited personal guarantee of the repayment of the credit
agreement up to $800,000. Under the terms of the agreement, the Company is
required to maintain certain ratios and be in compliance with other covenants.
At June 30, 2000, the Company was not in compliance with a certain covenant. The
Company has obtained a waiver that waives compliance with such covenant through
July 31, 2001.
The $2,165,234 note at June 30, 2000 arises from a credit agreement between an
energy financial services company and TCM which provides for maximum outstanding
borrowings aggregating $2.5 million and maturing on July 31, 2002. Under the
terms of the agreement, TCM may make periodic draws to fund specific costs
incurred in developing certain coal bed methane wells. Also, TCM is required to
make monthly repayments of principal and accrued interest equal to 100% of the
net production proceeds of specific coal bed methane gas wells. The agreement
allows for the deferral of the required monthly repayments if the purchase of
the production from those wells does not meet specific percentages of
production. However, if outstanding borrowings on the agreement are greater than
90%, 50%, and 25% of the total borrowings made under the agreement at March 31,
2000 and July 31, 2000, 2001, and 2002, respectively, then TCM is required to
make additional payments equal
F-15
to the difference between the outstanding borrowings at the date and the
specific percentage of total borrowings made under the agreement.
TCM has also granted to the lender an undivided 2% overriding royalty interest
in the coal bed methane gas wells. The overriding royalty interest is reduced
(to a minimum of 1-7/12%) if the borrowings are repaid prior to specified dates
and, may be increased (to a maximum of 3%) if borrowings are not repaid by
specific dates. No value has been assigned to the overriding royalty interest
because the properties are still being evaluated. At the time that the
properties are evaluated and overriding royalties are due, TCM will treat the
payments as additional interest expense to the extent paid. For the years ended
December 31, 1998 and 1999 and the six months ended June 30, 2000, there have
been no overriding royalty payments made to the lender.
The Company did not make the March 31, 2000 payment. The Company is in the
process of renegotiating the payment terms of the loan and, while the Company
believes they will be successful, there are no assurances of their success.
Therefore, the entire balance of the line of credit is classified as current at
December 31, 1999 and June 30, 2000.
Scheduled maturities of notes payable and long-term debt are as follows:
Years Ending December 31, Amount
---------------------
2000 $ 2,233,176
2001 7,767,386
---------------------
$ 10,000,562
Total =====================
8. Commitments:
Lease Commitments - The Company leases office space in Oklahoma and certain
vehicles under long-term operating leases. The Company's leases include the cost
of real property taxes. Insurance, utilities, and routine maintenance are the
Company's responsibility.
Future minimum lease payments for all non-cancelable operating leases are as
follows:
Years ending December 31, Amount
---------------------
2000 $ 116,169
2001 105,815
2002 105,815
2003 105,815
2004 8,818
---------------------
Total $ 442,432
=====================
Rent expense was $51,827, $97,564 and $56,674 for the years ended December 31,
1998, 1999 and for the six month period ended June 30, 2000, respectively.
F-16
RED RIVER ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Stockholders' Equity:
The Company was originally formed as Red River Energy, LLC with 100 membership
units authorized and issued to the members. In November 1999, the members formed
Red River Energy, Inc. and exchanged each membership unit of Red River Energy,
LLC for ten shares of common stock of Red River Energy, Inc. The accompanying
financials statements have been retroactively restated to reflect this
transaction.
Two majority stockholders also made additional contributions of assets to the
Company totaling $812,565. The assets consist of office furniture with a
historical cost of $19,000 and equipment with a historical cost of $755,000,
$705,000 of which is idle at June 30, 2000, and is expected to be used in the
exploration and production of the coal bed methane gas properties.
The Company has assigned overriding royalty interests to certain employees who
are also stockholders of the Company to reward such employees with incentive
compensation based on the results of the Company's oil and gas drilling
activities. The interests assigned were determined at the discretion of
management prior to the commencement of certain drilling programs by the
Company. For the year ended December 31, 1999, the Company had paid $15,547 to
these employees for their overriding royalty interests and an additional $6,344
was accrued as other accrued liabilities as of December 31, 1999.
10. Subsequent Events (unaudited):
In February 2000, the Company entered into an agreement with an operator to
jointly test and develop additional production during 2000 in the Company's West
Edmond Hunton Lime Unit (Wehlu) in Eastern Oklahoma.
11. Unaudited Supplementary Oil and Gas Reserve Information:
The following supplementary information is presented in compliance with United
States Securities and Exchange Commission ("SEC") regulations and is not covered
by the report of the Company's independent auditors.
The information required to be disclosed for the year ended 1998 and after in
accordance with FASB Statement No. 69, "Disclosures About Oil and Gas Producing
Activities," is discussed below and is further detailed in the following tables.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
oil and gas reserves are those reserves expected to be recovered through
existing wells with existing equipment and operating methods. The Company's
reserves are substantially all proved developed. The reserve data is based on
studies prepared by the Company's independent consulting petroleum engineers.
Reserve estimates require substantial judgement on the part of petroleum
engineers resulting in imprecise determinations, particularly with respect to
new discoveries. Accordingly, it is expected
F-17
that the estimates of reserves will change as future production and development
information become available. At December 31, 1998 and 1999, all of the
Company's proved oil and gas reserve quantities are located in Oklahoma. The
following table presents estimates of the Company's net proved oil and gas
reserves and changes therein for the years ended December 31, 1998 and 1999:
Changes in Quantities of Proved Petroleum and Natural Gas Reserves (unaudited)
Proved Reserves
Oil Gas
(Bbls) (Mcf)
- ----------------------------------------------------------------
Proved reserves, beginning of year -- --
Purchase of minerals in place .. 447,470 15,878,536
Production ..................... (13,470) (336,536)
----------- -----------
Proved reserves, December 31, 1998 434,000 15,542,000
Purchase of minerals in place .. 1,852,138
Production ..................... (33,584) (911,036)
Revisions of previous estimates (50,832) (4,081,102)
---------- ------------
Proved reserves, December 31, 1999 349,584 12,402,000
---------- ------------
Standardized Measure of Discounted Future Net Cash Flows (unaudited) - Statement
of Financial Accounting Standards No. 69 prescribes guidelines for computing a
standardized measure of future cash flows and changes therein relating to
estimated proved reserves. The Company has followed these guidelines which are
briefly discussed below.
Future cash inflows and future production and development costs are determined
by applying year-end prices and costs to the estimated quantities of oil and gas
to be produced. Estimates of future income taxes are computed using current
statutory income tax rates including consideration for estimated future
statutory depletion and tax credits. The resulting net cash flows are reduced to
present value amounts by applying a 10% discount factor.
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations for actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously are equally applicable to
the standardized measure computations since those estimates are the basis for
the valuation process.
F-18
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves as of December 31, 1998 and 1999 based on the
standardized measure prescribed in Statement of Financial Accounting Standard
No. 69:
Year ended December 31,
1998 1999
------------ ------------
Future cash inflows ........................ $ 39,090,229 $ 36,330,303
Future costs-
Production ............................... (12,614,429) (10,485,704)
Development .............................. (48,721) --
------------- -------------
Future net cash inflows before income tax .. 26,427,079 25,844,599
Future income tax .......................... (5,505,574) (4,975,498)
------------- --------------
Future net cash flows ...................... 20,921,505 20,869,101
10% discount factor ........................ (12,556,496) (10,025,071)
------------- --------------
Future net cash flows ...................... $ 8,365,009 $ 10,844,030
============= ==============
Changes in the Standardized Measure (unaudited) - The following are the
principal sources of changes in the standardized measure of discounted future
net cash flows for the years ended December 31, 1998 and 1999:
Year ended December 31,
1998 1999
------------ ------------
Standardized measure, beginning of year ......... $ -- $ 8,365,009
Purchase of minerals in place ................... 11,295,703 $ 995,917
Sale of oil and gas produced, net of production
costs ...................................... (548,823) (1,993,551)
Changes in income taxes, net .................... (2,381,871) (530,567)
Changes in prices and costs ..................... -- 5,150,637
Changes in development costs .................... -- 38,805
Accretion of discount ........................... -- 836,501
Revisions of estimates and other ................ -- (2,018,721)
------------- ------------
Standardized measure, end of year ............... $ 8,365,009 $ 10,844,030
============= =============
F-19
ONEOK RESOURCES COMPANY
Statements of Revenues and Direct Operating Expenses of
Certain Properties Being Sold to Red River Energy, Inc.
For the Years Ended
December 31, 1998 and 1999,
For the Six Months Ended June 30, 1999 (unaudited)
and June 14, 2000 (unaudited)
INDEPENDENT AUDITOR'S REPORT
The Stockholders and Board of Directors
ONEOK Resources Company
Tulsa, Oklahoma
We have audited the accompanying statement of revenues and direct operating
expenses of the certain properties being sold to Red River Energy, Inc. (ONEOK
properties) of ONEOK Resources Company (see Note 1) for the years ended December
31, 1998 and 1999. These statements are the responsibility of the ONEOK
Resources Company's management. Our responsibility is to express an opinion on
the financial statements based on our audits.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the statement of revenues and direct operating expenses
is free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the statement. An audit also
includes assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall statement presentation. We
believe that our audits provides a reasonable basis for our opinion.
The accompanying statement of revenues and direct operating expenses were
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in the proxy statement and
report on Form 8-K of Beta Oil & Gas, Inc.) as described in Note 2 and are not
intended to be a complete presentation of the ONEOK properties' revenues and
expenses.
In our opinion, the statements of revenues and direct operating expenses
referred to above present fairly, in all material respects, the revenues and
direct operating expenses of the ONEOK properties for the years ended December
31, 1998 and 1999 in conformity with generally accepted accounting principles.
/s/ Hein + Associates, LLP
Hein + Associates, LLP
Orange, California
August 4, 2000
F-2
ONEOK PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
See accompanying notes to these financial statements.
For the years ended For the six months ended
December 31, June 30, June 14,
1998 1999 1999 2000
---------- ---------- ---------- ----------
(unaudited) (unaudited)
Revenues:
Oil and gas sales ................... $1,566,646 $2,087,384 $ 830,630 $1,126,504
Costs and Expenses:
Oil and gas production costs ........ 731,414 940,267 341,348 285,165
----------- ---------- ---------- ----------
Excess of revenues over direct operating
expenses ............................ $ 835,232 $1,147,117 $ 489,282 $ 841,339
=========== ========== ========== ==========
F-3
ONEOK PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
1. Nature of Operations:
On May 1, 2000, ONEOK Resources Company (ONEOK) entered into a purchase and sale
agreement (the agreement) to sell certain oil and gas properties and related
assets (collectively, the properties) to Red River Energy, Inc. (Red River). The
purchase price at January 1, 2000, the effective date, $6,041,680, was subject
to certain adjustments including net revenues (as defined in the agreement)
between the effective date and the closing date. The net purchase price at
closing, June 14, 2000, was approximately $5,608,808 and is subject to
additional adjustment. The properties, are primarily designated as oil wells
with associated gas leases and are located in the following three geographic
concentrations: mid-continent including Kansas, Oklahoma, North Texas and the
Texas Panhandle, West Texas, and Texas Gulf Coast.
2. Basis of Presentation:
Revenues and direct operating expenses for the oil and gas properties included
in the accompanying statements represent ONEOK's interest in the properties and
are presented on the accrual basis of accounting. Direct operating expenses
include all the costs of production, marketing and distribution. Costs related
to general corporate activities, depreciation, depletion, and amortization, and
federal and state income taxes were not allocated to the above properties
because the property interests and related assets acquired represent only a
portion of ONEOK's business and the costs incurred by ONEOK are not necessarily
indicative of the costs to be incurred by Red River. Historical financial
information reflecting financial position, results of operations and cash flows
of the properties are not presented because the entire acquisition cost was
assigned to the oil and gas property interests. Accordingly, historical
statements of revenues and direct operating expenses have been presented in lieu
of the financial statements required under Rule 3-05 of the Securities and
Exchange Commission Regulation S-X.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make certain estimates and
assumptions that affect the reported amounts of revenues and direct operating
expenses during the reporting period. Actual results could differ from those
estimates.
3. Related Parties:
Included in oil and gas revenues for the properties is approximately $11,919 and
$0 for the years ended December 31, 1999 and December 31, 1998, respectively are
sales to affiliates of ONEOK. Additionally, for the six months ended June 14,
2000 and June 30, 1999, $981 and $4,928, respectively are sales to affiliates of
ONEOK.
F-4
4. Commitments:
Pursuant to the terms of the agreement, certain claims, litigation or disputes
pending as of the effective date and certain matters arising in connection with
ownership of the properties prior to the effective date are retained by ONEOK.
ONEOK is not aware of any claims, litigation or disputes which should be accrued
or disclosed in accordance with FASB5 "Accounting for Contingencies."
5. Unaudited Supplementary Oil and Gas Reserve Information:
The following supplementary information is presented in compliance with United
States Securities and Exchange Commission ("SEC") regulations and is not covered
by the report of the Company's independent auditors.
The information required to be disclosed for the years ended 1998 and 1999 in
accordance with FASB Statement No. 69, "Disclosures About Oil and Gas Producing
Activities," is discussed below and is further detailed in the following tables.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
oil and gas reserves are those reserves expected to be recovered through
existing wells with existing equipment and operating methods. Proved undeveloped
oil and gas reserves are reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major
expenditure is required for recompletion. Approximately 74% and 69% of the
proved reserves (on a barrels of oil equivalent basis) attributable to the ONEOK
properties at December 31, 1998 and 1999, respectively, as disclosed in the data
room material, were proved developed with the remaining reserves being proved
undeveloped. Reserve estimates require substantial judgement on the part of
petroleum engineers resulting in imprecise determinations, particularly with
respect to new discoveries. Accordingly, it is expected that the estimates of
reserves will change as future production and development information become
available. At December 31, 1998 and 1999, all of the properties' proved oil and
gas reserve quantities are located in Texas, Kansas, and Oklahoma. The following
table presents estimates of the properties' net proved oil and gas reserves and
changes therein for the years ended December 31, 1998 and 1999:
F-5
Changes in Quantities of Proved Petroleum and Natural Gas Reserves (unaudited)
Proved Reserves
Oil Gas
(Bbls) (Mcf)
- -----------------------------------------------------------------------------
Proved reserves, December 31, 1997 .......... 197,243 4,914,245
Purchase of minerals in place ............ 562,100 456,400
Production ............................... (48,445) (555,306)
Revisions of previous estimates and other 69,582 69,801
---------- ----------
Proved reserves, December 31, 1998 .......... 780,480 4,885,140
Purchase of minerals in place ............ 69,900 1,072,500
Production ............................... (62,843) (462,565)
Revisions of previous estimates and other 5,398 92,029
---------- ----------
Proved reserves, December 31, 1999 .......... 792,935 5,587,104
---------- ----------
Standardized Measure of Discounted Future Net Cash Flows (unaudited) - Statement
of Financial Accounting Standards No. 69 prescribes guidelines for computing a
standardized measure of future cash flows and changes therein relating to
estimated proved reserves. ONEOK has followed these guidelines which are briefly
discussed below.
Future cash inflows and future production and development costs are determined
by applying year-end prices and costs to the estimated quantities of oil and gas
to be produced. Estimates of future income taxes are computed using current
statutory income tax rates including consideration for estimated future
statutory depletion and tax credits. The resulting net cash flows are reduced to
present value amounts by applying a 10% discount factor.
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect ONEOK's expectations for actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously are equally applicable to
the standardized measure computations since those estimates are the basis for
the valuation process.
F-6
The future cash flows presented by Red River in the future will be based upon
its cost structure and timing of future development and production may be
significantly different from those of ONEOK. The following summary sets forth
ONEOK's future net cash flows relating to proved oil and gas reserves as of
December 31, 1998 and 1999 based on the standardized measure prescribed in
Statement of Financial Accounting Standard No. 69.
Year ended December 31,
1998 1999
------------ ------------
Future cash inflows ........................ $ 17,395,529 $ 31,071,083
Future costs-
Production ............................... (12,908,981) (12,879,318)
Development .............................. (1,108,428) (1,220,328)
------------- --------------
Future net cash inflows before income tax .. 3,378,120 16,971,437
Future income tax .......................... -- (4,545,052)
------------- --------------
Future net cash flows ...................... 3,378,120 12,426,385
10% discount factor ........................ (1,141,044) (4,493,528)
------------- --------------
Future net cash flows ...................... $ 2,237,076 $ 7,932,857
============= ==============
Changes in the Standardized Measure (unaudited) - The following are the
principal sources of changes in the standardized measure of discounted future
net cash flows for the years ended December 31, 1998 and 1999:
Year ended December 31,
1998 1999
----------- -----------
Standardized measure, beginning of year ........... $ 3,917,761 $ 2,237,076
Purchase of minerals in place ..................... 493,790 1,616,289
Sale of oil and gas produced, net of production
costs ........................................ (835,232) (1,147,117)
Changes in income taxes, net ...................... 116,055 (2,473,702)
Changes in prices and costs ....................... (1,917,868) 9,105,682
Changes in development costs ...................... 615,944 88,938
Accretion of discount ............................. 391,776 223,708
Revisions of estimates and other .................. (545,150) (1,718,017)
------------ -----------
Standardized measure, end of year ................. $ 2,237,076 $ 7,932,857
============ ===========
F-7
Beta Oil & Gas, Inc.
Pro Forma Combining, Condensed Financial Statements
The following unaudited pro forma combining, condensed financial information is
presented to reflect the merger under the Agreement and Plan of Merger of Beta
Oil & Gas, Inc. and subsidiaries ("Beta") and Red River Energy, Inc. and
subsidiaries ("Red River") and the acquisition of the ONEOK properties on June
14, 2000 under the purchase and sale agreement between Red River and ONEOK
Resources Company ("ONEOK properties") on (1) the unaudited historical condensed
balance sheet as of June 30, 2000, and (2) the unaudited historical condensed
statements of operations for the year ended December 31, 1999 and the six months
ended June 30, 2000.
The Pro Forma Combined Condensed Balance Sheet gives effect to the merger as if
it had taken place on June 30, 2000. The Pro Forma Combined Condensed Statements
of Operations reflects both of these transactions as if they had taken place at
the beginning of the periods presented.
For financial accounting purposes, it is expected that the merger will be
accounted for using the purchase method of accounting. Therefore, Beta's cost to
acquire Red River, calculated to be $14.455 million assuming an average Beta
common stock price of $6.38 per share with 2,250,000 shares issued to the
stockholders of Red River, will be allocated to the assets acquired and
liabilities assumed according to their fair values.
The ONEOK properties were acquired on June 14, 2000 for total consideration of
$5,608,809, subject to an additional post-closing adjustment for the final
accounting of net revenues and operating expenses estimated by the Company to be
$367,250 from the effective date to the closing. Such adjustment will be
determined within 90 days after closing. The acquisition of the ONEOK properties
was funded through additional borrowings under the Red River line of credit.
The unaudited pro forma combining, condensed financial statements are based on
the assumptions set forth in the notes to such statements and should be read in
conjunction with the historical financial statements and related notes of Beta
and Red River and the ONEOK Properties' statement of revenues and direct
operating expenses contained herein, which were used to prepare the pro forma
combining, condensed financial statements.
See accompanying notes to combining, condensed financial information.
F-1
Beta Oil & Gas, Inc.
Combining, Condensed Balance Sheet
June 30, 2000
(unaudited)
Merger
pro forma Combined
Beta Red River adjustments pro-forma
------------ ------------ ------------ ------------
Assets
Current assets:
Cash and cash equivalents .............. $ 3,006,118 $ 256,697 $ -- $ 3,262,816
Accounts receivable .................... 993,049 485,878 -- 1,478,927
Other receivable ....................... -- 367,250 367,250
Prepaid expenses ....................... 54,211 53,760 -- 107,970
------------ ------------ ------------ ------------
Total current assets .............. 4,053,378 1,163,585 -- 5,216,963
Oil and gas properties, at cost (full cost
method):
Evaluated properties ................... 10,581,984 10,193,321 13,769,033 (1) 34,544,338
Unevaluated properties ................. 12,564,191 2,863,257 -- 15,427,448
Less-accumulated amortization
and impairments of full cost pool .... (4,963,371) (816,114) -- (5,779,485)
------------ ------------- ------------- -----------
Net oil and gas properties ........ 18,182,804 12,240,464 13,769,033 44,192,301
Other operating property and equipment:
Gas gathering system ................... -- 1,335,431 -- 1,335,431
Support equipment ...................... -- 2,426,069 -- 2,426,069
Less-accumulated depreciation .......... -- (331,678) -- (331,678)
------------ ------------- ------------- ------------
Net other operating property
and equipment...................... -- 3,429,822 -- 3,429,822
Furniture, fixtures and equipment, net 5,846 25,441 -- 31,287
Other assets ............................... 1,390,183 8,818 -- 1,399,001
------------- ------------ ------------ -------------
Total assets $ 23,632,211 $ 16,868,130 $ 13,769,033 $ 54,269,374
============= ============ ============ ==============
(Continued)
F-2
Beta Oil & Gas, Inc.
Combining, Condensed Balance Sheet
June 30, 2000
(unaudited)
(Continued)
Merger
pro forma Combined
Beta Red River adjustments pro-forma
------------ ------------ ------------ ------------
Liabilities and stockholders' equity
Current liabilities:
Premiums payable - current portion
of long-term debt ............................. $ 26,775 $ -- -- $ 26,775
Current portion of long-term debt ......... -- 2,236,565 -- 2,236,565
Accounts payable, trade ................... 300,479 421,733 100,000 (1) 822,212
Accounts payable, related party ........... -- 6,694 -- 6,694
Accrued interest .......................... -- 112,999 -- 112,999
Accrued liabilities ....................... 55,767 66,674 -- 122,441
------------ ------------ ----------- -----------
Total current liabilities ............ 383,021 2,844,665 100,000 3,327,686
Long-term debt, less current portion........... 14,236 13,337,498 -- 13,351,734
------------ ------------ ------------ -----------
Total liabilities .................... 397,257 16,182,163 100,000 16,679,420
Stockholders' equity 23,234,954 685,967 13,669,033 (1) 37,589,954
------------ ------------ ----------- -----------
Total liabilities and stockholders' equity .... $ 23,632,211 $ 16,868,130 $ 13,769,033 $ 54,269,374
============= ============ =========== ===========
F-3
Beta Oil & Gas, Inc.
Pro Forma Combining, Condensed Statement of Operations
For the Six Months Ended June 30, 2000
(unaudited)
Red River Energy, Inc.
ONEOK
ONEOK Acquisition Combined pro forma Combined
Beta Red River Properties Adjustments pro-forma adjustments pro-forma
------------ ------------ ----------- ----------- ------------ ------------ ------------
Revenues $ 2,022,503 $ 2,080,932 1,126,504 $ -- 3,207,436 $ -- $5,229,939
190,649 (2)
Costs and expenses ............ 2,253,699 1,602,909 285,165 12,000 (5) 2,090,723 184,999 (3) 4,529,421
--------- ---------- --------- ---------- ---------- --------- ---------
Income (loss) from Operations . (231,196) 478,023 841,339 (202,649) 1,116,713 (184,999) 700,518
Other income (expense), net ... 55,228 (339,325) -- (214,364) (553,689) -- (498,461)
---------- ---------- --------- ----------- ----------- --------- ---------
Net income (loss) (175,968) $ 138,698 $ 841,339 $ (417,013) $ 563,024 $ (184,999) $ 202,057
========== ========== ========= =========== ============ ========== =========
Basic and diluted Income (loss) $ (0.02) $ 0.02
per share
Weighted average number of
common shares outstanding ... 9,651,143 2,250,000 (7) 11,901,143
(basic) ========== ========= ===========
Weighted average number of
common shares outstanding ... 10,349,591 2,250,000 (7) 12,599,591
(diluted) ========== ========== ===========
F-4
Beta Oil & Gas, Inc.
Pro Forma Combining, Condensed Statement of Operations
For the Year Ended December 31, 1999
(unaudited)
Red River Energy, Inc.
ONEOK
ONEOK Acquisition Combined pro forma Combined
Beta Red River Properties Adjustments pro-forma adjustments pro-forma
---------- ----------- ------------ ------------ ------------ ------------ ------------
Revenues $ 1,199,480 $ 3,188,758 $ 2,087,384 $ -- $ 5,276,142 $ -- $ 6,475,622
Costs and expenses ............ 3,638,973 2,863,497 940,267 558,619 (2) 907,481 (3)
24,000 (5) 4,386,383 1,807,560 (4) 10,740,397
----------- --------- --------- ---------- ------------- ---------- ----------
Income (loss) from operations . (2,439,493) 325,261 1,147,117 (582,619) 889,759 (2,715,041) (4,264,775)
Other income (expense), net ... (2,944,910) (509,826) -- (420,661) (930,487) -- (3,875,397)
------------ ---------- ---------- ----------- ------------- ----------- -----------
Net income (loss) $(5,384,403) $ (184,565) $ 1,147,117 $ (1,003,280) $ (40,728) $ (2,715,041) $(8,140,172)
============ ========== ========== =========== ============= ==========
Basic and diluted income (loss)
per share $ (.66) $ (0.78)
============ ============
Weighted average number of
common shares outstanding ... 8,160,000 2,250,000 (7) 10,410,000
============ ========= ===========
(basic)
F-5
Beta Oil & Gas, Inc.
Notes to the Pro Forma Combining, Condensed Statement of Operations
(unaudited)
(1) To reflect the acquisition of Red River in a purchase transaction where Beta
acquired 100% of the net assets of Red River for 2,250,000 shares of Beta common
stock. The acquisition was valued at $14,455,000 including $100,000 of estimated
acquisition costs. Based on an analysis performed by Beta management, the assets
and liabilities of Red River are adjusted to their fair values, which
approximate book values, except for the evaluated oil and gas properties which
were increased by $13,769,033 to their estimated fair value based on the
September 1, 1999 Ryder Scott Reserve Report . This amount will be included in
the full cost amortization base of the Company. The adjustment also includes the
removal of Red River's stockholders' equity accounts.
(2) To reflect additional amortization costs giving effect to the increase in
the amortization base of the evaluated properties due to the acquisition of the
ONEOK properties by Red River.
(3) To reflect additional amortization costs giving effect to the increase in
the amortization base of the evaluated properties acquired through the merger of
Beta and Red River. The amortization base of Red River includes the amortization
base of the ONEOK properties as if they had been acquired by Red River from the
beginning of the periods presented.
(4) To reflect the impairment charge, on a consolidated basis, under full cost
method of accounting for oil and gas properties due to the book basis of the
properties being greater than the calculated ceiling assuming prices and costs
in effect as of December 31, 1999.
(5) Reflects estimated incremental general and administrative expenses due
to the acquisition of the ONEOK properties.
(6) Reflects increased interest expense, based upon the current rate for each of
the periods presented, from borrowings under the Red River line of credit to
finance the acquisition of the ONEOK properties as if the borrowings had been
outstanding as of the beginning of the periods presented.
(7) The pro forma combined weighted average common shares reflect the adjustment
for the issuance of 2.25 million shares of Beta common stock to Red River
stockholders, per the Agreement and Plan of Merger.
F-6
Beta Oil & Gas, Inc. Announces Closing of Merger with
Red River Energy, LLC
FOR IMMEDIATE RELEASE - August 31, 2000
Tulsa, Oklahoma - August 31, 2000 - Beta Oil & Gas, Inc. (NASDAQ:BETA) announced
today the closing of its merger with Red River Energy, Inc. ("Red River")
effective September 1, 2000. The combined companies` assets will be in excess of
an estimated $50 million representing an approximate 112% increase in Beta's
assets. Furthermore, the combined companies daily production will be
approximately 10 million cubic feet of natural gas equivalent per day, a 186%
increase to Beta's current production level. For the six months ended June 30,
2000, the combined companies' gross revenues and net income would have been
approximately $5 million and $2300,000, respectively. Related "Earning Before
Interest, Taxes, Depreciation and Amortization" (EBITDA) for the same six months
would have been approximately $2.4 million or $0.20 per share. Beta's common
shares outstanding are 12,225,159.
In the second quarter prior to the merger, Red River completed a multi-state
production acquisition. Steve Antry, President of Beta, commented, "On June 14,
2000, while Beta's merger with Red River was still pending, Red River closed an
acquisition of predominantly Mid-Continent properties. I believe that
acquisition was very accretive to both Red River at the time and thus Beta now.
Beta has over 200 producing wells mainly in Oklahoma, Texas, and Louisiana.
While the emphasis of the Company is still on exploration, these are the types
of acquisitions we will continue to pursue. Also, as the revenue and cash flow
streams improve, the general and administrative expenses should decline as we
wrap up our merger and relocation efforts."
Beta Oil and Gas, Inc. is an independent energy company engaged in the
production, exploration, acquisition and development of oil and gas properties
using advanced seismic technology. For more information please contact Steve
Antry or Steve Fischer at (800) 866-8055.
Forward Looking Statement: The statements in this report regarding projected
revenues and earnings, projected production performance and expected drilling
and development activities are "forward-looking statements" within the meaning
of the federal security laws. Such statements are inherently uncertain, and
actual results and activities may differ materially from those estimated or
projected. Certain factors that can affect the Company's ability to achieve
projected results are described in the Company's Annual Report and other reports
filed with the Securities and Exchange Commission. Such factors include, among
others, uncertainties inherent in reserve estimations and production rates,
especially for estimates of undeveloped reserves, operational risks inherent in
the offshore environment with corresponding exposure to delays, significant cost
overruns, and mechanical problems, the highly competitive nature of activity
offshore with corresponding resource shortages, and the uncertain cost and
pricing environment in the industry. The Company has no obligation to update the
statements contained in this report or to take action that is described herein
or otherwise presently planned.