Exhibit 99.2
RAM ENERGY, INC.
Consolidated financial statements
(UNAUDITED)
CONTENTS
Consolidated balance sheets at June 30, 2005 and December 31, 2004..................................................F-2
Consolidated statements of operations for the three- and six-month
periods ending June 30, 2005 and June 30, 2004.................................................................F-3
Consolidated statements of stockholders' deficiency for six months ended June 30, 2005..............................F-4
Consolidated statements of cash flows for the three- and six-month
periods ending June 30, 2005 and June 30, 2004.................................................................F-5
Notes to foregoing consolidated financial statements................................................................F-6
Consolidated balance sheets at December 31, 2004 and December 31, 2003.............................................F-18
Consolidated statements of operations for years ended December 31, 2004, 2003 and 2002.............................F-19
Consolidated statements of stockholders' deficiency for the years ended December 31, 2004, 2003 and 2002...........F-20
Consolidated statements of cash flows for the years ended December 31, 2004, 3003 and 2002.........................F-21
Notes to foregoing year-end financial statements...................................................................F-23
ALL OF THE FOLLOWING FINANCIAL STATEMENTS ARE UNAUDITED AND WERE PREPARED BY RAM
ENERGY, INC., AS A PRIVATE COMPANY, IN ACCORDANCE WITH GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES AND MAY NOT CONFORM TO SEC REGULATION S-X.
FINANCIAL INFORMATION FOR THE THREE AND SIX MONTH PERIODS REFERENCED ABOVE IS
SUBJECT TO NORMAL YEAR-END ADJUSTMENTS FOR INTERIM PERIODS.
F-1
RAM ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
JUNE 30, DECEMBER 31,
2005 2004
--------------------------------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,712 $ 1,175
Short-term investments - -
Accounts receivable:
Natural gas and oil sales 6,818 4,874
Joint interest operations, net of allowance for doubtful accounts
of $591 and $687 at June 30, 2005 and December 31, 2004,
respectively 494 630
Other 64 28
Derivative asset - 1,509
Prepaid expenses, deposits and other 450 259
Inventory 155 -
--------------------------------------
Total current assets 9,693 8,475
PROPERTIES AND EQUIPMENT, AT COST:
Natural gas and oil properties and equipment, based on full cost accounting 152,500 147,392
Other property and equipment 6,601 5,779
--------------------------------------
Less accumulated amortization and depreciation 29,746 23,919
--------------------------------------
Total properties and equipment 129,355 129,252
OTHER ASSETS:
Deferred loan costs relating to revolving credit facility, net of accumulated
amortization of $262 and $20 at June 30, 2005 and
December 31, 2004, respectively 1,239 1,481
Deferred offering costs relating to Senior Notes, net of accumulated
amortization of $4,149 and $4,090 at June 30, 2005 and December 31, 2004,
respectively 304 364
Other 699 698
--------------------------------------
Total assets $ 141,290 $ 140,270
======================================
LIABILITIES AND STOCKHOLDERS' DEFICIENCY
CURRENT LIABILITIES:
Accounts payable:
Trade $ 3,923 $ 5,273
Natural gas and oil proceeds due others 2,697 2,528
Related party 50 -
Accrued liabilities:
Compensation 521 583
Interest 1,607 1,547
Current income taxes payable 11,187 11,187
Dividends 500 -
Derivative liability 3,899 -
Long-term debt due within one year 6,564 3,891
--------------------------------------
Total current liabilities 30,948 25,009
DERIVATIVE LIABILITY 2,368 -
GAS BALANCING LIABILITY AND PROCEEDS DUE OTHERS NOT EXPECTED TO BE
SETTLED WITHIN ONE YEAR 2,500 2,275
LONG-TERM DEBT DUE AFTER ONE YEAR 108,374 113,453
DEFERRED INCOME TAXES 13,899 14,536
COMMITMENTS AND CONTINGENCIES 600 600
LIABILITY FOR ASSET RETIREMENT OBLIGATION 6,202 6,057
STOCKHOLDERS' DEFICIENCY:
Common stock, $10.00 par value; authorized -5,000 shares; issued
and outstanding - 2,273 shares 23 23
Paid-in capital 73 73
Accumulated deficit (23,697) (21,756)
--------------------------------------
Total stockholders' deficiency (23,601) (21,660)
--------------------------------------
Total liabilities and stockholders' deficiency $ 141,290 $ 140,270
================ == ==================
The accompanying notes are an integral part of these unaudited consolidated
financial statements
F-2
RAM ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2005 2004 2005 2004
-------------------------------------------------------------------------
OPERATING REVENUES:
Oil and natural gas sales $ 15,512 $ 30,331 $ 8,931
4,169
Realized and unrealized loss from derivatives (2,374) (8,035) (574)
(260)
Other 242 584 50
19
-------------------------------------------------------------------------
Total operating revenues 13,380 3,928 22,880 8,407
OPERATING EXPENSES:
Oil and natural gas production taxes 777 280 1,541 671
Oil and natural gas production expenses 3,838 614 7,536 1,184
Amortization and depreciation 2,857 734 5,816 1,636
Accretion expense 68 9 146 31
General and administrative, overhead
and other expenses, net of operator's
overhead fees 1,860 1,782 3,918 3,060
-------------------------------------------------------------------------
Total operating expenses 9,400 3,419 18,957 6,582
-------------------------------------------------------------------------
Operating income 3,980 509 3,923 1,825
OTHER INCOME (EXPENSE):
Interest expense (2,851) (1,100) (5,624) (2,365)
Interest income 13 9 22 20
Gain on sale of RBOC (Note H) - 12,139 - 12,139
Gain (loss) on sale of properties (28) - - -
-------------------------------------------------------------------------
INCOME (LOSS) BEFORE TAXES 1,114 11,557 (1,679) 11,619
INCOME TAX (BENEFIT) PROVISION 423 4,392 (638) 4,415
------------------------------------- ----------------------------------
NET INCOME (LOSS) $ 691 $ 7,165 $ (1,041) $ 7,204
===================================== ==================================
EARNINGS (LOSS) PER SHARE:
Basic $ 303.98 $ 2,627.43 $ (458.01) $ 2,641.73
Diluted $ 293.23 $ 2,627.43 $ (458.01) $ 2,641.73
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 2,273 2,727 2,273 2,727
Diluted 2,356 2,727 2,273 2,727
===================================== ==================================
The accompanying notes are an integral part of these unaudited
consolidated financial statements.
F-3
RAM ENERGY, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' DEFICIENCY
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SIX MONTHS ENDED JUNE 30, 2005
(UNAUDITED)
Total
Common Paid-In Accumulated Stockholders'
Stock Capital Deficit Deficiency
-------------------------------------------------------------------------------------
BALANCE, December 31, 2004 $23 $73 $(21,756) $(21,660)
Net income - - (1,041) (1,041)
Cash dividends declared ($396.0396
per share) - - (900) (900)
-------------------------------------------------------------------------------------
BALANCE, June 30, 2005 $23 $73 $(23,697) $(23,601)
=====================================================================================
The accompanying notes are an integral part of these unaudited consolidated
financial statements.
F-4
RAM ENERGY, INC.
Consolidated statements of cash flows
(IN THOUSANDS)
(UNAUDITED)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------------------- -------------------------------
2005 2004 2005 2004
--------------------------------- --------------------------------
OPERATING ACTIVITIES:
Net income (loss) $ 691 $ 7,165 $ (1,041) $ 7,204
Adjustments to reconcile net income
(loss) to net cash provided (used) by operating
activities:
Amortization, depletion and depreciation:
Oil and natural gas properties and equipment 2,753 669 5,639 1,497
Amortization of Senior Notes discount 11 11 21 21
Deferred offering costs 29 31 59 62
Deferred loan costs 115 77 242 155
Other property and equipment 92 65 181 139
Accretion expense 68 9 146 31
Loss on sale of assets 28 6 - 6
Gain on the sale of RBOC - (12,139) - (12,139)
Unrealized loss on derivatives 2,307 - 7,776 -
Deferred income taxes 423 4,392 (637) 4,415
Cash provided by (used in) changes in operating
assets and liabilities-
Accounts receivable (823) (486) (1,844) (206)
Prepaid expenses, deposits and other assets (165) (15) (192) (11)
Inventory (155) - (155) -
Accounts payable 357 (344) (1,300) (668)
Accrued liabilities and other 2,806 548 3,984 120
--------------------------------- --------------------------------
Total adjustments 7,846 (7,176) 13,920 (6,578)
--------------------------------- --------------------------------
Net cash provided by (used in)
operating activities 8,537 (11) 12,879 626
--------------------------------- --------------------------------
INVESTING ACTIVITIES:
Proceeds from short-term investments - - - 1,681
Payments for oil and natural gas properties and
equipment (4,745) (649) (7,442) (1,310)
Proceeds from sales of oil and natural gas properties
and equipment 2,335 26 2,335 294
Payments for other property and equipment (779) (31) (844) (60)
Proceeds from sales of other property - 22 28 22
Proceeds from sale of RBOC - 21,791 - 21,791
--------------------------------- --------------------------------
Net cash (used in) provided by investing activities (3,189) 21,159 (5,923) 22,418
--------------------------------- --------------------------------
FINANCING ACTIVITIES:
Payments on long-term debt (4,948) (17,919) (6,082) (18,212)
Proceeds from borrowings on long-term debt 41 - 63 21
Dividends paid (400) (400) (400) (804)
--------------------------------- --------------------------------
Net cash used by financing activities (5,307) (18,319) (6,419) (18,995)
--------------------------------- --------------------------------
Increase in cash and cash equivalents 41 2,829 537 4,049
Cash and cash equivalents at beginning of period 1,671 3,338 1,175 2,118
--------------------------------- --------------------------------
Cash and cash equivalents at end of period $ 1,712 $ 6,167 $ 1,712 $ 6,167
================================= ================================
DISCLOSURE OF NONCASH FINANCING ACTIVITIES:
Accrued interest added to principal balance of
revolving credit facility $ 2,080 $ 92 $ 3,592 $ 390
================================= ================================
The accompanying notes are an integral part of these unaudited consolidated
financial statements.
F-5
RAM ENERGY, INC.
Notes to unaudited consolidated financial statements
A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION, AND BASIS OF
FINANCIAL STATEMENTS
1. Basis of Financial Statements
The accompanying unaudited consolidated financial statements present the
financial position at June 30, 2005 and December 31, 2004 and the results
of operations and cash flows of RAM Energy, Inc. and subsidiaries (the
Company) for the three-month and six-month periods ended June 30, 2005 and
2004. These financial statements include all adjustments, consisting of
normal and recurring adjustments, which, in the opinion of management, are
necessary for a fair presentation of the financial position and the results
of operations for the indicated periods. The results of operations for the
three and six months ended June 30, 2005, are not necessarily indicative of
the results to be expected for the full year ending December 31, 2005.
Reference is made to the Company's financial statements for the year ended
December 31, 2004, for an expanded discussion of the Company's financial
disclosures and accounting policies.
2. Nature of Operations and Organization
The Company operates exclusively in the upstream segment of the oil and gas
industry with activities including the drilling, completion, and operation
of oil and gas wells. The Company conducts the majority of its operations
in the states of Texas, Louisiana, Oklahoma and New Mexico.
On December 17, 2004, the Company completed its acquisition of WG Energy
Holdings, Inc. (WG), a Delaware corporation, in which a wholly owned
subsidiary of the Company created specifically for such purpose merged with
and into WG and WG was the surviving corporation in the merger (the WG
Acquisition). At the time of the merger, the name of WG was changed to RWG
Energy, Inc. (RWG). RWG, with its four existing subsidiaries, are now first
and second tier subsidiaries of the Company.
3. Principles of Consolidation
The consolidated financial statements include the accounts of the Company's
majority or wholly owned subsidiaries. All significant intercompany
transactions have been eliminated.
4. Properties and Equipment
The Company follows the full cost method of accounting for oil and natural
gas operations. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and development of
oil and gas reserves are capitalized. No gains or losses are recognized
upon the sale or other disposition of oil and gas properties except in
transactions which would substantially alter the amortization base of the
capitalized costs.
Under the full cost method, the net book value of oil and gas properties,
less related deferred income taxes, may not exceed the estimated after-tax
future net revenues from proved oil and gas properties, discounted at 10%
per year (the ceiling limitation). In arriving at estimated future net
revenues, estimated lease operating expenses, development costs,
abandonment costs, and certain production-related and ad valorem taxes are
deducted. In calculating future net revenues, prices and costs in effect at
the balance sheet date are held constant indefinitely, except for changes
which are fixed and determinable by existing contracts. The net book value
is compared to the ceiling limitation on a quarterly and yearly basis. The
excess, if any, of the net book value above the ceiling limitation is
charged to expense in the period in which it occurs and is not subsequently
reinstated. Reserve estimates used in determining estimated future net
revenues have been prepared by independent petroleum engineers. At June 30,
2005, the Company's net book value of oil and gas properties did not exceed
the ceiling amount.
Other property and equipment consists principally of automotive and heavy
equipment, furniture and equipment and leasehold improvements. Other
property and equipment and related accumulated amortization and
F-6
depreciation are relieved upon retirement or sale and the gain or loss is
included in operations. Renewals and replacements that extend the useful
life of property and equipment are treated as capital additions.
Accumulated depreciation of other property and equipment at June 30, 2005
and December 31, 2004, is approximately $4,033,000 and $3,845,000,
respectively.
5. Depreciation and Amortization
All capitalized costs of oil and natural gas properties and equipment
including the estimated future costs to develop proved reserves are
amortized using the unit-of-production method using total proved reserves.
Depreciation of other equipment is computed based on an accelerated method
over the estimated useful lives of the assets, which range from three to
ten years. Amortization of leasehold improvements is computed based on the
straight-line method over the term of the associated lease.
6. Natural Gas Sales and Gas Imbalances
Natural gas imbalances are generated on properties for which two or more
owners have the right to take production "in-kind" and, in doing so, take
more or less than their respective entitled percentage.
The Company follows the entitlements method of accounting for natural gas
sales, recognizing as revenues only its net share of all production sold.
Any amount received in excess of or less than the Company's revenue
interest is recorded as a net gas balancing asset or liability. At June 30,
2005 and December 31, 2004, the Company's net underproduced position was
approximately 136,000 Mcf and 121,000 Mcf with an associated asset of
approximately $181,000, which is recorded in other assets in the
consolidated balance sheets.
7. Cash Equivalents
All highly liquid unrestricted investments with a maturity of three months
or less when purchased are considered to be cash equivalents.
8. Inventory
Inventory is stated at the lower of cost (weighted average) or fair market
value.
9. Credit and Market Risk
The Company sells oil and natural gas to various customers and participates
with other parties in the drilling, completion and operation of oil and
natural gas wells Joint interest and oil and natural gas sales receivables
related to these operations are generally unsecured. For the three months
ended June 30, 2005 and year ended December 31, 2004, the provisions for
doubtful accounts receivable were approximately $628,000 and $385,000,
respectively, while there were charge-offs of the allowance for $96,000 and
$146,000 in those periods. The Company has established joint interest
operations accounts receivable allowances which management believes are
adequate for uncollectible amounts at June 30, 2005 and December 31, 2004,
based on management's assessment of the credit worthiness of the joint
interest owners and the Company's ability to realize the receivables
through netting of anticipated future production.
10. Deferred Costs
Deferred loan and offering costs are stated at cost net of amortization
computed using the straight-line method over the term of the related loan
agreement.
11. General and Administrative Expense
The Company receives fees for the operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense.
12. Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of
F-7
assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from those estimates. Estimates and assumptions that, in the opinion
of management of the Company are significant include oil and natural gas
reserves, amortization relating to oil and natural gas properties and asset
retirement obligations.
13. Fair Value of Financial Instruments
Cash and cash equivalents, trade receivables and payables and installment
notes: The carrying amounts reported in the balance sheets approximate fair
value due to the short-term maturity of these instruments.
Long-term debt: The carrying amount reported in the balance sheets
approximates fair value because this debt instrument carries a variable
interest rate based on market interest rates.
Senior Notes: The carrying amount reported in the balance sheets was below
fair value at June 30, 2005, by approximately $1.4 million and in excess of
fair value at December 31, 2004, by approximately $1.4 million, based upon
management's estimates. Management bases its estimate on information from
the bond underwriters on current bids of the Company's bonds.
Derivative contracts: The carrying amount reported in the balance sheets is
the fair value of the contracts based upon prices quoted by the
counterparty to the agreements.
14. Reclassifications
Certain reclassifications of previously reported amounts for 2004 have been
made to conform with the 2005 presentation format. These reclassifications
had no effect on net income.
15. Accounting Policy for Derivatives
The Company applies the provisions of SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended. SFAS No. 133
requires companies to recognize all derivative instruments as either assets
or liabilities in the statement of financial position at fair value.
The accounting for changes in the fair value of a derivative depends on the
intended use of the derivative and resulting designation. For derivatives
designated as cash flow hedges and meeting the effectiveness guidelines of
SFAS No. 133, changes in fair value are recognized in other comprehensive
income until the hedged item is recognized in earnings. Hedge effectiveness
is measured quarterly based on relative changes in fair value between the
derivative contract and hedged item during the period of hedge designation.
The ineffective portion of a derivative's change in fair value is
recognized currently in earnings. Forecasted transactions designated as the
hedged item in a cash flow hedge are regularly evaluated to assess whether
they continue to be probable of occurring, and if the forecasted
transaction is no longer probable of occurring, any gain or loss deferred
in accumulated other comprehensive income is recognized in earnings
currently. All gains and losses, realized and unrealized, for derivatives
not formally designated as hedges are recognized in earnings in the period
incurred.
16. Earnings Per Common Share
Basic earnings per share is computed by dividing net income by the weighted
average number of common shares outstanding for the period. Diluted
earnings per share reflects the potential dilution that could occur if
dilutive stock options and warrants were exercised, calculated using the
treasury stock method. A reconciliation of net income and weighted average
shares used in computing basic and diluted net income per share is as
follows for the three and six months ended June 30 (in thousands, except
share and per share amounts):
F-8
Three Months Ended June 30
2005 2004
---------------------------------
BASIC INCOME PER SHARE:
Net (loss) income $ 691 $ 7,165
=================================
Weighted average shares 2,273 2,727
=================================
Basic (loss) income per share $ 303.98 $2,627.43
=================================
DILUTED INCOME PER SHARE:
Net (loss) income $ 691 $ 7,165
=================================
Weighted average shares 2,273 2,727
Dilutive effect of stock options 83 -
---------------------------------
Weighted average shares assuming dilutive effect
of stock options 2,356 2,727
=================================
Diluted (loss) income per share $ 293.23 $2,627.43
=================================
Six Months Ended June 30
2005 2004
---------------------------------
BASIC INCOME PER SHARE:
Net (loss) income $ (1,041) $ 7,204
=================================
Weighted average shares 2,273 2,727
=================================
Basic (loss) income per share $ (458.01) $2,641.73
=================================
DILUTED INCOME PER SHARE:
Net (loss) income $ (1,041) $ 7,204
=================================
Weighted average shares 2,273 2,727
Dilutive effect of stock options - -
---------------------------------
Weighted average shares assuming dilutive effect
of stock options 2,273 2,727
=================================
Diluted (loss) income per share $ (458.01) $2,641.73
=================================
17. Asset Retirement Obligations
The Company accounts for the future costs of plugging and abandoning its
oil and natural gas properties under Financial Accounting Standards Board
(FASB) SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No.
143 addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated asset
retirement costs and amended FASB Statement No. 19, Financial Accounting
and Reporting by Oil and Gas Producing Companies. SFAS No. 143 requires
that the fair value of a liability for an asset retirement obligation be
recognized in the period in which it is incurred if a reasonable estimate
of fair value can be made, and that the associated asset retirement costs
be capitalized as part of the carrying amount of the long-lived asset.
18. Recently Issued Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS
123R requires all share-based payments to employees, including grants of
employee stock options, to be recognized in the financial statements based
on their fair values and is effective for the first interim or annual
reporting period beginning after January 1, 2006. Management does not
believe the adoption of SFAS 123R will have a significant impact on the
Company's financial position or results of operations.
In March 2005, the FASB issued Interpretation 47, Accounting for
Conditional Asset Retirement Obligations (FIN 47). Statement 143, as
amended by FIN 47, requires all entities to recognize the fair value of
legal obligations to perform asset retirement activities when incurred,
including those for which the timing and/or method of settlement are
conditional on a future event that may or may not be within the control of
the entity. FIN 47 is effective no later than the end of the fiscal years
ending after December 15, 2005 (December 31, 2005 for a
F-9
calendar-year entity). Management does not believe the adoption of FIN 47
will have a significant impact on the Company's financial position or
results of operations.
B - WG ACQUISITION
The Company completed the WG Acquisition on December 17, 2004. The final
adjusted purchase price was $82.6 million, including the assumption and
payment of WG's long-term debt of $24.5 million, the settlement of all
outstanding derivative instruments of $14.4 million and the balance
(excluding the escrow) of $32.7 million was paid in cash. $11.0 million of
the purchase price was deposited in two separate escrow accounts to provide
funds against which the Company may make claims for any subsequently
determined breach by WG of representations and warranties in the merger
agreement and for potential losses that may arise in connection with
certain existing litigation against WG. (See Note E.) The acquisition was
financed with a credit facility provided by Wells Fargo Foothill, Inc.
(Foothill), the Company's existing senior secured lender. (See Note F.)
RWG's principal assets are producing oil properties located in north Texas,
a gas plant and a significant block of undeveloped deep rights in
held-by-production leases. RWG's estimated proved reserves at December 31,
2004 were 13.2 million barrels of oil equivalent.
C - DERIVATIVE CONTRACTS
During 2005 and 2004, the Company entered into numerous derivative
contracts. The Company did not formally designate these transactions as
hedges as required by SFAS No. 133 in order to receive hedge accounting
treatment. Accordingly, all gains and losses on the derivative financial
instruments have been recorded in the statement of operations.
At June 30, 2005, the Company had purchased put options on 184,000 barrels
of oil through December 2005 with a weighted average floor price of $40.00
per barrel, and had purchased call options on 92,000 barrels of oil through
December 2005 with a weighted average ceiling price of $55.75 per barrel.
The Company also had collars on 1,015,250 barrels of oil through December
2007 with a weighted average floor price of $39.55 and a weighted average
ceiling price of $62.42. For natural gas, the Company had collars on
2,714,000 Mmbtu through October 2006. The weighted average floor price was
$5.95 per Mmbtu and the weighted average ceiling price was $8.20 per Mmbtu.
The Company also had purchased calls on 1,070,000 Mmbtu for April 2006
through October 2006 at a weighted average ceiling price of $9.50 per
Mmbtu.
At December 31, 2004, the Company had purchased put options on 455,500
barrels of oil through December 2005, with a floor price of $40.00. For
natural gas, the Company had purchased collars on 1,824,000 MMbtu through
October 2005. The weighted average floor price was $5.65 per MMbtu and the
weighted average ceiling price was $7.84 per MMbtu.
The Company measured the fair value of its derivatives at June 30, 2005 and
December 31, 2004, based on quoted market prices. Accordingly, a liability
of $6,267,000 and an asset of $1,509,000 were recorded in the consolidated
balance sheets at June 30, 2005 and December 31, 2004, respectively.
D - SUBSIDIARY GUARANTORS
The Company's Senior Notes are fully and unconditionally guaranteed,
jointly and severally, on a senior unsecured basis, by all of the Company's
current and future subsidiaries (the Subsidiary Guarantors). The following
table sets forth condensed consolidating financial information of the
Subsidiary Guarantors. There are currently no restrictions on the ability
of the Subsidiary Guarantors to transfer funds to the Company in the form
of cash dividends, loans or advances.
F-10
The following represents the condensed consolidating balance sheets for the
Company and its subsidiaries at June 30, 2005 and December 31, 2004 (in
thousands):
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ----------------- ----------------- ----------------
June 30, 2005
Current assets $ - $ 16,684 $ (6,991) $ 9,693
Property and equipment, net 14,435 114,920 - 129,355
Investment in subsidiary 25,421 - (25,421) -
Other assets 3,462 - (1,220) 2,242
------------- ----------------- ----------------- ----------------
Total assets $ 43,318 $ 131,604 $(33,632) $141,290
============= ================= ================= ================
Current liabilities 32,437 5,502 (6,991) 30,948
Long-term debt 28,336 80,038 108,374
Other non-current liabilities 6,146 5,524 11,670
Deferred income taxes - 15,119 (1,220) 13,899
------------- ----------------- ----------------- ----------------
Total liabilities 66,919 106,183 (8,211) 164,891
Stockholders' equity (deficiency) (23,601) 25,421 (25,421) (23,601)
------------- ----------------- ----------------- ----------------
Total liabilities and stockholders' equity
(deficiency) $ 43,318 $ 131,604 $(33,632) $141,290
============= ================= ================= ================
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ----------------- ----------------- ----------------
December 31, 2004
Current assets $ 1,455 $ 7,020 $ - $ 8,475
Property and equipment, net 10,563 118,689 - 129,252
Investment in subsidiary 11,694 - (11,694) -
Other assets 2,543 - - 2,543
------------- ----------------- ----------------- ----------------
Total assets $ 26,255 $ 125,709 $ (11,694) $ 140,270
============= ================= ================= ================
Current liabilities $ 6,086 $ 18,923 $ - $ 25,009
Long-term debt 34,489 78,964 - 113,453
Other non-current liabilities 3,738 5,194 - 8,932
Deferred income taxes 3,602 10,934 - 14,536
------------- ----------------- ----------------- ----------------
Total liabilities 47,915 114,015 - 161,930
Stockholders' equity (deficiency) (21,660) 11,694 (11,694) (21,660)
------------- ----------------- ----------------- ----------------
Total liabilities and stockholders' equity
(deficiency) $ 26,255 $ 125,709 $ (11,694) $ 140,270
============= ================= ================= ================
F-11
The following represents the condensed consolidating statements of
operations and statements of cash flows for the Company and its
subsidiaries for the three months and six months ended June 30, 2005 and
2004:
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ---------------- ---------------- ----------------
Three Months Ended June 30, 2005
Operating revenues $ (251) $ 13,631 $ - $ 13,380
Operating expenses 2,943 6,457 - 9,400
------------- ---------------- ---------------- ----------------
Operating income (3,194) 7,174 - 3,980
Other income (expense) 2,026 (19) (4,873) (2,866)
------------- ---------------- ---------------- ----------------
Income (loss) before income taxes (1,168) 7,155 (4,873) 1,114
Income taxes (1,859) 2,282 - 423
------------- ---------------- ---------------- ----------------
Net income (loss) $ 691 $ 4,873 $ (4,873) $ 691
============= ================ ================ ================
Cash flows provided by (used in) operating
activities $ 1,938 $ 6599 $ - $ 8,537
Cash flows provided by (used in) investing
activities (1,845) (1,344) - (3,189)
Cash flows provided by (used in) financing
activities (359) (4,948) - (5,307)
------------- ---------------- ---------------- ----------------
Increase (decrease) in cash and cash equivalents (266) 307 - 41
Cash and cash equivalents at beginning of period 399 1,272 - 1,671
------------- ---------------- ---------------- ----------------
Cash and cash equivalents at end of period $ 133 $ 1,579 $ - $ 1,712
============= ================ ================ ================
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ---------------- ---------------- ----------------
Three Months Ended June 30, 2004
Operating revenues $ 1,173 $ 2,795 $ (40) $ 3,928
Operating expenses 2,562 897 (40) 3,419
------------- ---------------- ---------------- ---------------
Operating income (loss) (1,389) 1,898 509 -
Other income (expense) 12,225 - (1,177) 11,048
------------- ---------------- ---------------- ---------------
Income (loss) from continuing operations before
income taxes 10,836 1,898 (1,177) 11,557
Income taxes 3,671 721 4,392 -
------------- ---------------- ---------------- ---------------
Income from continuing operations 7,165 1,177 (1,177) 7,165
Loss from discontinued operations, net of tax - - - -
------------- ---------------- ---------------- ---------------
Net income (loss) $ 7,165 $ 1,177 $ (1,177) $ 7,165
============= ================ ================ ===============
Cash flows provided by (used in) operating
activities $ 21,780 $ (21,791) $ - $ (11)
Cash flows provided by (used in) investing
activities (632) 21,791 21,159 -
Cash flows provided by (used in) financing
activities (18,319) - - (18,319)
------------- ---------------- ---------------- ---------------
Increase (decrease) in cash and cash equivalents 2,829 - 2,829 -
Cash and cash equivalents at beginning of period 3,338 - - 3,338
------------- ---------------- ---------------- ---------------
Cash and cash equivalents at end of period $ 6,167 $ - $ - $ 6,167
============= ================ ================ ===============
F-12
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ---------------- ----------------- ---------------
Six Months Ended June 30, 2005
Operating revenues $ (4,193) $ 27,073 $ - $ 22,880
Operating expenses 5,721 13,236 - 18,957
------------- ---------------- ----------------- ---------------
Operating income (loss) (9,914) 13,837 - 3,923
Other income (expense) 4,050 15 (9,667) (5,602)
------------- ---------------- ----------------- ---------------
Income (loss) from continuing operations before
income taxes (5,864) 13,852 (9,667) (1,679)
Income taxes (4,823) 4,185 - (638)
------------- ---------------- ----------------- ---------------
Net income (loss) $ (1,041) $ 9,667 $ (9,667) $ (1,041)
Cash flows provided by (used in) operating
activities $ 1,983 $ 10,896 $ - $ 12,879
Cash flows provided by (used in) investing
activities (2,492) (3,431) - (5,923)
Cash flows provided by (used in) financing
activities (401) (6,018) - (6,419)
------------- ---------------- ----------------- ---------------
Increase (decrease) in cash and cash equivalents (910) 1,447 - 537
Cash and cash equivalents at beginning of period
1,043 132 - 1,175
------------- ---------------- ----------------- ---------------
Cash and cash equivalents at end of period $ 133 $ 1,579 $ - $ 1,712
============= ================ ================= ===============
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------------- ---------------- ----------------- ---------------
Six Months Ended June 30, 2004
Operating revenues $ 3,530 $ 4,957 $ (80) $ 8,407
Operating expenses 5,294 1,368 (80) 6,582
------------- ---------------- ---------------- ----------------
Operating income (loss) (1,764) 3,589 - 1,825
Other income (expense) 12,008 30 (2,244) 9,794
------------- ---------------- ---------------- ----------------
Income (loss) from continuing operations before
income taxes 10,244 3,619 (2,244) 11,619
Income taxes 3,040 1,375 - 4,415
------------- ---------------- ---------------- ----------------
Income from continuing operations 7,204 2,244 (2,244) 7,204
Loss from discontinued operations, net of tax - - - -
------------- ---------------- ---------------- ----------------
Net income (loss) $ 7,204 $ 2,244 $ (2,244) $ 7,204
Cash flows provided by (used in) operating
activities $ 24,292 $ (23,666) $ - $ 626
Cash flows provided by (used in) investing
activities (1,054) 23,472 - 22,418
Cash flows provided by (used in) financing
activities (18,995) - - (18,995)
------------- ---------------- ---------------- ----------------
Increase (decrease) in cash and cash equivalents 4,243 (194) - 4,049
Cash and cash equivalents at beginning of period
1,924 194 - 2,118
------------- ---------------- ---------------- ----------------
Cash and cash equivalents at end of period $ 6,167 $ - $ - $ 6,167
============= ================ ================ ================
The Company has allocated a portion of its long-term debt and has not allocated
any portion of accrued interest payable, unamortized debt issue costs and
unamortized issue discount to its subsidiaries. In addition, the Company has not
allocated general and administrative expenses or interest charges to its
subsidiaries. Accordingly, the above condensed consolidating information is not
intended to present the Company's subsidiaries on a stand-alone basis.
F-13
E - COMMITMENTS AND CONTINGENCIES
In November 2004, Ted Collins, Jr. filed a lawsuit against WG Energy
Holdings, Inc. and Michael G. Grella, the former President of that company.
Mr. Collins alleges that WG and Mr. Grella failed to timely apply a $1.5
million advance toward enhancing the shallow depths in certain leases, and
failed to deliver assignments of certain interests in those leases, both as
allegedly required by the participation agreement between them. Mr. Collins
further claims that WG has failed to account to him for revenues allegedly
accruing to him under the terms of the participation agreement. Mr. Collins
seeks an accounting and to have the partial assignment and/or participation
agreement reformed based on allegations of mutual mistake, and further
pleads claims of fraud and negligent misrepresentation. He has not pled a
specific amount of damages. Management is unable to estimate a range of
potential loss, if any, related to this lawsuit, and accordingly no amounts
have been recorded in the consolidated financial statements. As this
lawsuit existed at the time of the Company's acquisition of WG, a $5
million escrow was established as a reserve for this lawsuit. (See Note B.)
In 1996, the Company's predecessor sold a natural gas and oil property
located in Louisiana state waters in Plaquemines Parish. The property
included several uneconomical wells for which the Company estimated the
plugging and abandonment (P&A) obligation to be approximately $1,020,000.
The purchaser provided a letter of credit and a bond totaling $420,000 to
ensure funding of a portion of the P&A obligation. The P&A obligation would
revert to the Company in the event the purchaser does not complete the
required P&A activities. As a result, in connection with the sale, the
Company recorded a contingent liability of $600,000, which is included in
the accompanying consolidated balance sheets.
In April 2002, a lawsuit was filed in the District Court for Woods County,
Oklahoma against the Company, certain of its subsidiaries and various other
individuals and unrelated companies, by lessors and royalty owners of
certain tracts of land, which were sold to Chesapeake Energy Corporation in
2001. The petition claims that additional royalties are due, because Carmen
Field Limited Partnership (CFLP), a wholly-owned subsidiary of the Company,
resold oil and gas purchased at the wellhead for an amount in excess of the
price upon which royalty payments were based and paid no royalties on
natural gas liquids extracted from the gas at plants downstream of the
system. Other allegations include under-measurement of oil and gas at the
wellhead by CFLP, failure to pay royalties on take or pay settlement
proceeds and failure to properly report deductions for post-production
costs in accordance with Oklahoma's check stub law.
Company defendants have filed answers in the lawsuit denying all material
allegations set out in the petition. The Company believes that fair and
proper accounting was made to the royalty owners for production from the
subject leases and intends to vigorously defend the lawsuit. Management is
unable to estimate a range of potential loss, if any, related to this
lawsuit, and accordingly no amounts have been recorded in the consolidated
financial statements. In the event the court should find Company defendants
liable for damages in the lawsuit, a former joint venture partner is
contractually obligated to pay a portion of any damages assessed against
the defendant lessees up to a maximum contribution of approximately $2.8
million.
The Company is also involved in legal proceedings and litigation in the
ordinary course of business. In the opinion of management, the outcome of
such matters will not have a material adverse effect on the Company's
financial position or results of operations.
F - LONG-TERM DEBT
Long-term debt consists of the following:
June 30, December 31,
2005 2004
-----------------------------------------
(In thousands)
11.5% Senior Notes due 2008, net of discount $ 28,288 $ 28,268
Revolving Credit Facility 86,355 88,663
Installment loan agreements 295 413
-----------------------------------------
114,938 117,344
Less amount due within one year 6,564 3,891
-----------------------------------------
$ 108,374 $ 113,453
=========================================
F-14
1. Senior Notes
In February 1998, the Company completed the sale of $115 million of 11.5%
Senior Notes due 2008 in a public offering of which $28.4 million remained
outstanding at June 30, 2005 and December 31, 2004. The Senior Notes are
senior unsecured obligations of the Company and are redeemable at the
option of the Company in whole or in part, at any time on or after February
15, 2005, at prices ranging from 111.5% to 103.8% of face amount to their
scheduled maturity in 2008.
At June 30, 2005 and December 31, 2004, the unamortized original issue
discount associated with the Notes totaled $108,000 and $128,000,
respectively.
2. Revolving Credit Facility
On May 24, 2005, the Company amended its loan and security agreement with
Wells Fargo Foothill (Foothill), resulting in the addition of a third
party, ABLECO, and additional hedging requirements.
In December 2004, the Company entered into an amended and restated $90.0
million senior secured credit facility provided by Foothill. The facility
includes a $30.0 million term loan and a $60.0 million revolving credit
facility, reducing by $2.5 million per quarter commencing September 30,
2005 and continuing until the committed amount of the revolver is reduced
to $50.0 million. Borrowings under the revolving credit facility bear
interest at Foothill's base rate plus 2% (8.25% and 7.25% at June 30, 2005
and December 31, 2004), or LIBOR plus 4% (7.46% at June 30, 2005), at the
option of the Company, while advances under the term loan bear interest at
the base rate plus 5% (11.25% at June 30, 2005 and 10.25% at December 31,
2004), or LIBOR plus 7% (10.46% at June 30, 2005), also at the option of
the Company. The entire facility will mature in December 2008. The amount
of credit available under the credit facility at June 30, 2005 and December
31, 2004 was $3.6 million and $1.3 million, respectively.
The Company is required to pay a commitment fee equal to .375% per annum on
the amount by which the borrowing base exceeds the aggregate amount
outstanding under the Foothill credit facility. Amounts outstanding under
the Foothill credit facility are collateralized by substantially all
current and future assets of the Company and its subsidiaries. Along with
the pledged collateral mentioned above, Foothill also has first rights to
the Company's cash accounts.
The credit facility contains customary covenants which, among other things,
require periodic financial and reserve reporting and limit the Company's
incurrence of indebtedness, liens, dividends, loans, mergers, transactions
with affiliates, investments and sales of assets, and require the Company
to maintain certain financial ratios, including minimum tangible net worth,
capital expenditures limitation and EBITDA. The credit facility also
requires the Company to maintain derivative contracts (hedging) for
specified percentages of future production.
If the Company fails to satisfy or obtain a waiver for the covenants of the
credit facility, Foothill could consider the Company to be in default. Upon
default, Foothill may declare all obligations immediately due and payable,
cease advancing money or extending credit, terminate the agreement, and
secure its rights in the Company's collateral. The Foothill credit facility
also contains a subjective acceleration clause whereby Foothill may declare
an event of default if it determines a material adverse change has
occurred. Management believes it is unlikely that the subjective
acceleration clause would be asserted in 2005 and therefore has classified
the credit facility as a long-term obligation in accordance with its stated
maturity.
On April 29, 2004, the Company amended its loan and security agreement with
Foothill to allow for the sale of RBOC (Note H) and to restate certain
future financial covenants.
At June 30, 2005, the Company was in compliance with debt covenants.
G - CAPITAL STOCK
In August 2004, the Company repurchased and retired one-sixth of its
outstanding common shares and vested stock options for $5.0 million and
$135,000, respectively. The cash paid to repurchase the common shares and
stock options is equal to their respective estimated fair values on the
date of settlement and, therefore, is recorded as a reduction of equity. No
additional compensation expense was incurred as a result of the repurchase
of the
F-15
stock options. Absent a market price for or comparable to the untraded
securities, management estimated the fair value of the common stock by
dividing the net asset value by the total number of shares outstanding. The
fair value of the stock options was calculated as the excess of the
estimated value of the common stock over the exercise price of the options.
Management believes the estimation method and assumptions utilized
represent the best available evidence of the value of the equity securities
at the settlement date.
The Company declared cash dividends of $220.0220 and $396.0396 per share or
$400,000 and $900,000 for the three and six months ended June 30, 2005.
The Company declared cash dividends of $0 and $146.6814 per share or $0 and
$400,000 for the three and six months ended June 30, 2004.
H - SALE OF RBOC
On April 23, 2004, the Company entered into a stock sale agreement with
Range Energy I, Inc. to sell all of the issued and outstanding shares of
common capital stock of RB Operating Company (RBOC), a wholly-owned
subsidiary of the Company. The transaction closed on April 29, 2004, for a
purchase price of $22.5 million, subject to customary post-closing
adjustments. The Company received proceeds of $21.8 million, net of
transaction costs of $363,000 and cash paid of $814,000, from the sale, of
which $17.9 million was used to pay the remaining balance on the Foothill
loan and security agreement.
With this sale, the Company sold approximately 27% of its proved natural
gas and oil reserves. As this significantly altered the relationship
between the Company's capitalized costs and proved reserves, the Company
recognized a gain on the sale of $12.1 million.
I - DEFERRED COMPENSATION
On April 21, 2004, the Company adopted a Deferred Bonus Compensation Plan
(the "Plan") for senior management employees of the Company. The Plan is to
provide additional compensation for significant business transactions with
a portion of each bonus to be deferred to encourage retention of key
employees. Determination of significant business transactions and terms of
awards is made by a committee comprised of the owners of the Company.
At June 30, 2005 and 2004, three members of senior management had been
granted awards related to the sale of RBOC. Each award provides for a total
compensation of $75,000 and vests on each anniversary date for three years,
beginning on July 1, 2004. Receipt of the award is contingent to the
members being employed on the anniversary date. Should there be a change of
control or involuntary termination, as defined in the award contract, each
member will become fully vested in his award. At June 30, 2005 and 2004,
$75,000 is recorded in accrued compensation.
J - FINANCIAL CONDITION AND MANAGEMENT PLANS
The financial statements of the Company have been prepared on the basis of
accounting principles applicable to a going concern, which contemplates the
realization of assets and the satisfaction of liabilities in the normal
course of business. As shown in the consolidated financial statements, for
the six months ended June 30, 2005, the Company incurred a net loss of
approximately $1.0 million as compared to net income of approximately $7.2
million for the same period in the prior year. The financial statements do
not include any adjustments relating to the recoverability and
classification of asset carrying amounts or the amount and classification
of liabilities that might result should the Company be unable to continue
as a going concern.
Management believes that borrowings currently available to the Company
under the Company's revolving credit facility, the remaining balance of
unrestricted cash and cash flows from operations will be sufficient to
satisfy its currently expected capital expenditures, working capital and
debt service obligations for the foreseeable future. The actual amount and
timing of future capital requirements may differ materially from estimates
as a result of, among other things, changes in product pricing and
regulatory, technological and competitive developments. Sources of
additional financing may include commercial bank borrowings, vendor
financing and the sale of natural gas and oil properties or equity or debt
securities. Management cannot assure that any such financing will be
available on acceptable terms or at all.
F-16
K - RELATED PARTY TRANSACTIONS
The Company paid rent expense of approximately $29,000 and $32,000 relating
to a condominium for one of the shareholders of the Company for the six
months ended June 30, 2005 and 2004, respectively.
For the six months ended June 30, 2005 and 2004, approximately $225,000 and
$200,000, respectively, of expenses for the shareholders of the Company are
included in general and administrative expenses in the consolidated
statements of operations, some of which may be personal in nature.
L - BRIDGEPORT TRANSACTION
In June 2005, the Company sold overriding royalty interests in certain
properties located in Jack and Wise Counties, Texas for $2.3 million to
Bridgeport Royalties, LLC. Bridgeport Royalties, LLC is a related party of
the Company, owned and operated by the owners and several officers and
employees of the Company, in addition to outside counsel. No gain on the
sale was recognized and the proceeds were applied to reduce the Foothill
Revolver facility. As of June 30, 2005 and December 31, 2004, the Company
had accrued revenues payable of $145,000 and $0 to Bridgeport Royalties,
LLC.
M - SUBSEQUENT EVENTS
In August 2005 and September 2005, the Company paid approximately $3.6
million and $2.8 million to Coral Energy Holding, LP to satisfy margin
calls related to the Company's derivative contracts.
F-17
RAM ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(In thousands, except share and per share amounts)
December 31, 2004 and 2003
2004 2003
----------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,175 $ 2,118
Short-term investments - 1,681
Accounts receivable:
Natural gas and oil sales, net of allowance of $0 ($0 in 2003) 4,874 2,288
Joint interest operations, net of allowance of $687 ($433 in 2003) 630 616
Other, net of allowance of $37 ($0 in 2003) 28 36
Prepaid expenses and deposits 259 522
Derivative assets 1,509 89
----------- ----------
Total current assets 8,475 7,350
PROPERTIES AND EQUIPMENT AT COST (Note P):
Natural gas and oil properties and equipment, full cost method 147,392 60,760
Other property and equipment 5,779 4,642
----------- ----------
153,171 65,402
Less accumulated depreciation and amortization 23,919 27,809
----------- ----------
Total properties and equipment 129,252 37,593
OTHER ASSETS:
Deferred loan costs relating to revolving credit facility, net of accumulated
amortization of $20 ($334 in 2003) (Note D) 1,481 593
Deferred offering costs relating to Senior Notes, net of accumulated amortization of
$4,090 ($3,969 in December 2003) (Note D) 364 485
Other 698 213
----------- ----------
Total assets $ 140,270 $ 46,234
=========== ==========
LIABILITIES AND STOCKHOLDERS' DEFICIENCY
CURRENT LIABILITIES:
Accounts payable:
Trade $ 5,273 $ 1,244
Natural gas and oil proceeds due others 2,528 1,709
Accrued liabilities:
Compensation 583 422
Interest 1,547 1,316
Income tax liability 11,187 3,535
Other - 421
Long-term debt due within one year (Note D) 3,891 61
----------- ----------
Total current liabilities 25,009 8,708
GAS BALANCING LIABILITY - 211
NATURAL GAS AND OIL PROCEEDS DUE OTHERS 2,275 2,155
LONG-TERM DEBT (Note D) 113,453 45,996
DEFERRED INCOME TAXES 14,536 7,886
COMMITMENTS AND CONTINGENCIES (Note K) 600 600
ASSET RETIREMENT OBLIGATION 6,057 1,352
STOCKHOLDERS' DEFICIENCY (Note H):
Common stock, $10.00 par value; authorized - 5,000 shares; issued and
outstanding - 2,273 and 2,727 shares at December 31, 2004 and 2003,
respectively
23 27
Paid-in capital 73 88
Accumulated deficit (21,756) (20,789)
----------- ----------
Stockholders' deficiency (21,660) (20,674)
----------- ----------
Total liabilities and stockholders' deficiency $ 140,270 $ 46,234
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-18
RAM ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(In thousands, except share and per share amounts)
December 31, 2004 and 2003
2004 2003 2002
----------- ---------- --------
OPERATING REVENUES:
Natural gas and oil sales $ 17,677 $ 20,521 $ 10,061
Other 285 155 163
Realized and unrealized loss on derivatives (875) (177) (208)
----------- ---------- ----------
Total operating revenues 17,087 20,499 10,016
OPERATING EXPENSES:
Natural gas and oil production taxes 1,263 1,408 1,044
Natural gas and oil production expenses 3,948 3,527 3,023
Depreciation and amortization 3,273 4,098 2,947
Accretion expense 78 48 -
Provision for litigation - 38 140
General and administrative, overhead and other expenses, net of operator's
overhead fees 6,601 6,293 5,718
----------- ---------- -----------
Total operating expenses 15,163 15,412 12,872
----------- ---------- -----------
Operating income (loss) 1,924 5,087 (2,856)
OTHER INCOME (EXPENSE):
Gain on early extinguishment of debt - - 32,883
Gain on sale of other property, plant and equipment 53 - -
Gain on sale of subsidiary (Note C) 12,139 - -
Interest expense (5,070) (4,912) (9,240)
Interest income 35 41 291
----------- ---------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 9,081 216 21,078
INCOME TAX PROVISION (Note I) 3,733 228 7,975
----------- ---------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS 5,348 (12) 13,103
DISCONTINUED OPERATIONS:
Loss from discontinued operations - (1,723) (18,016)
Income tax benefit - (655) (6,846)
----------- ---------- -----------
LOSS FROM DISCONTINUED OPERATIONS - (1,068) (11,170)
----------- ---------- -----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
5,348 (1,080) 1,933
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (Net of tax benefit of $0, $275
and $0 in 2004, 2003 and 2002, respectively) - (448) -
----------- ---------- -----------
Net income (loss) $ 5,348 $ (1,528) $ 1,933
=========== ========== ===========
BASIC WEIGHTED EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing operations $ 2,098.15 $ (4.40) $ 4,804.92
Loss from discontinued operations - (391.64) (4,096.08)
Cumulative effect of change in accounting principle - (164.28) -
----------- ---------- ----------
Net income (loss) $ 2,098.15 $ (560.32) $ 708.84
=========== ========== ==========
BASIC WEIGHTED AVERAGE SHARES OUTSTANDING 2,549 2,727 2,727
=========== ========== ==========
DILUTED EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing operations $ 2,024.29 $ (4.40) $ 4,804.92
Loss from discontinued operations - (391.64) (4,096.08)
Cumulative effect of change in accounting principle - (164.28) -
----------- ---------- ----------
Net income (loss) $ 2,024.29 $ (560.32) $ 708.84
=========== ========== ==========
DILUTED WEIGHTED AVERAGE SHARES OUTSTANDING 2,642 2,727 2,727
=========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-19
RAM ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIENCY
(UNAUDITED)
(In thousands, except per share amounts)
Years ended December 31, 2004, 2003 and 2002
Total
Common Paid-in Accumulated Stockholders'
Stock Capital Deficit Deficiency
------ ------- ------------ ------------
BALANCE, January 1, 2002 $ 27 $ 16 $ (20,390) $ (20,347)
Net income - - 1,933 1,933
Expense related to stock options - 72 - 72
---- ----- ----------- ----------
BALANCE, December 31, 2002 27 88 (18,457) (18,342)
Net loss - - (1,528) (1,528)
Dividends declared (Note H) - - (804) (804)
---- ----- ----------- ----------
BALANCE, December 31, 2003 27 88 (20,789) (20,674)
Net income - - 5,348 5,348
Dividends declared (Note H) - - (1,200) (1,200)
Purchase and cancellation of shares and outstanding
options (4) (15) (5,115) (5,134)
---- ----- ----------- ----------
BALANCE, December 31, 2004 $ 23 $ 73 $ (21,756) $ (21,660)
==== ===== =========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-20
RAM ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(In thousands)
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
---------- ---------- --------
OPERATING ACTIVITIES:
Net income (loss) $ 5,348 $ (1,528) $ 1,933
Loss from discontinued operations - (1,068) (11,170)
---------- ---------- ----------
Income (loss) from continuing operations 5,348 (460) 13,103
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities-
Depreciation and amortization-
Natural gas and oil properties and equipment 3,011 3,785 2,656
Amortization of Senior Notes discount 42 20 157
Deferred offering costs 121 117 428
Deferred loan costs 329 308 26
Other property and equipment 262 313 291
Accretion expense 78 48 -
Gain on sale of subsidiary (12,139) - -
Cumulative effect in change in accounting principle, net of tax
- 448 -
Provision for litigation - - 140
Unrealized gain on derivatives (128) (67) -
Expense related to stock options - - 72
Loss (gain) on sale of other property and equipment (1) 13 8
(Gain) loss on early extinguishment of debt, net - - (32,883)
Deferred income taxes 3,733 228 7,975
Cash provided by (used in) changes in operating assets and
liabilities, net of acquisitions-
Accounts receivable 666 (373) 194
Prepaid expenses, deposits and other assets 342 109 167
Accounts payable (67) (664) (4,290)
Accrued liabilities 1,907 942 (1,033)
Gas balancing liability (393) 109 (173)
Premiums paid on derivatives (1,314) - -
---------- ---------- ----------
Total adjustments (3,551) 5,336 (26,265)
---------- ---------- ----------
Net cash provided by (used in) continuing operations 1,797 4,876 (13,162)
Net cash provided by (used in) discontinued operations - 898 (1,680)
---------- ---------- ----------
Net cash provided by (used in) operating activities 1,797 5,774 (14,842)
---------- ---------- ----------
INVESTING ACTIVITIES:
Proceeds released from escrow - - 6,375
Payments for natural gas and oil properties and equipment (5,900) (4,282) (6,700)
Proceeds from sales of other natural gas and oil properties and
equipment 320 187 446
F-21
RAM ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
(UNAUDITED)
(In thousands)
Years ended December 31, 2004, 2003 and 2002
2004 2003 2002
---------- ---------- --------
Payments for other property and equipment (205) (343) (266)
Proceeds from sales of other property and equipment 38 15 39
RWG acquisition, net of cash acquired (82,577) - -
Proceeds from the sale of subsidiary 21,791 - -
Proceeds from sale of pipeline system - 12,026 -
Payment for other assets - - (5)
Proceeds from sales of other assets - - 65
Proceeds from (payments for) short-term investments 1,681 (181) -
---------- ----------- ----------
Net cash (used in) provided by investing activities (64,852) 7,422 (46)
---------- ---------- ----------
FINANCING ACTIVITIES:
Payments on long-term debt (18,234) (11,929) (238)
Proceeds from borrowings on long-term debt 88,585 - 27,459
Payments for purchase of Senior Notes - - (30,000)
Payments for deferred loan costs (1,501) - (952)
Stock repurchased and retired (5,134) - -
Dividends paid (1,604) (404) -
---------- ---------- ----------
Net cash provided by (used in) financing activities 62,112 (12,333) (3,731)
---------- ---------- ----------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
(943) 863 (18,619)
CASH AND CASH EQUIVALENTS, beginning of year 2,118 1,255 19,874
---------- ---------- ----------
CASH AND CASH EQUIVALENTS, end of year $ 1,175 $ 2,118 $ 1,255
========== ========== ==========
DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Accrued interest added to principal balance of Credit Facility $ 554 $ 1,699 $ -
========== ========== ==========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for income taxes $ 300 $ - $ -
========== ========== ==========
Cash paid for interest $ 3,266 $ 3,266 $10,199
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-22
RAM ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
December 31, 2004, 2003 and 2002
A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES, ORGANIZATION AND BASIS OF
FINANCIAL STATEMENTS
1. Nature of Operations and Organization
RAM Energy, Inc. (the Company) operates exclusively in the upstream segment
of the natural gas and oil industry with activities including drilling,
completion and operation of natural gas and oil wells. The Company conducts
the majority of its operations in the states of Texas, Louisiana, Oklahoma
and New Mexico. On December 17, 2004, the Company completed its acquisition
of WG Energy Holdings, Inc. (WG), a Delaware corporation, in which a wholly
owned subsidiary of the Company created specifically for such purpose
merged with and into WG and WG was the surviving corporation in the merger
(the WG Acquisition). At the time of the merger, the name of WG was changed
to RWG Energy, Inc., or RWG. RWG, with its four existing subsidiaries, are
now first and second tier subsidiaries of the Company. On August 1, 2003,
the Company sold its natural gas and oil pipeline system and a saltwater
disposal operation in north central Oklahoma (the pipeline system). The
pipeline system purchased, transported and marketed natural gas and oil
production and disposed of saltwater from properties owned by the Company
and other natural gas and oil companies. (See Note J.)
2. Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries. All significant intercompany balances
and transactions have been eliminated.
3. Properties and Equipment
The Company follows the full cost method of accounting for natural gas and
oil operations. Under this method, all productive and nonproductive costs
incurred in connection with the acquisition, exploration and development of
natural gas and oil reserves are capitalized. No gains or losses are
recognized upon the sale or other disposition of natural gas and oil
properties except in transactions that would substantially alter the
amortization base of the capitalized costs.
Under the full cost method, the net book value of natural gas and oil
properties, less related deferred income taxes, may not exceed the
estimated after-tax future net revenues from proved natural gas and oil
properties, discounted at 10% per year (the ceiling limitation). In
arriving at estimated future net revenues, estimated lease operating
expenses, development costs and certain production-related and ad valorem
taxes are deducted. In calculating future net revenues, prices and costs in
effect at the time of the calculation are held constant indefinitely,
except for changes that are fixed and determinable by existing contracts.
The net book value is compared to the ceiling limitation on a quarterly and
yearly basis. The excess, if any, of the net book value above the ceiling
limitation is charged to expense in the period in which it occurs and is
not subsequently reinstated. Reserve estimates used in determining
estimated future net revenues have been prepared by an independent
petroleum engineer.
The discounted future net revenues at December 31, 2004 and 2003, include
approximately $108.0 million and $48.0 million, respectively, related to
undeveloped and nonproducing properties on which estimated discounted
capital expenditures of approximately $36.0 million and $9.5 million,
respectively, will be required to develop and produce the reserves. The
Company expects the funding for these projects to be provided from future
cash flows from operations and borrowings under its credit facility or
additional borrowings. (See Note D.)
F-23
The Company has capitalized internal costs of approximately $596,000,
$434,000 and $600,000 for the years ended December 31, 2004, 2003 and 2002,
respectively. Such capitalized costs include salaries and related benefits
of individuals directly involved in the Company's acquisition, exploration
and development activities based on the percentage of their time devoted to
such activities.
In accordance with the impairment provisions of Statement of Financial
Accounting Standards (SFAS) No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Company assesses the recoverability of
the carrying value of its non-oil and gas long-lived assets when events
occur that indicate an impairment in value may exist. An impairment loss is
indicated if the sum of the expected future cash flows is less than the
carrying amount of the assets. If this occurs, an impairment loss is
recognized for the amount by which the carrying amount of the assets
exceeds the estimated fair value of the asset. At December 31, 2002, the
net book value of the pipeline system exceeded the expected future cash
flows from the pipeline. Accordingly, an impairment charge of $12.7
million, $7.9 million after tax, was recorded in the statement of
operations for the year ended December 31, 2002, for the excess of the net
book value over the fair value. No impairments were recorded in 2004 or
2003.
Other property and equipment consists principally of furniture and
equipment and leasehold improvements. Other property and equipment and
related accumulated amortization and depreciation are relieved upon
retirement or sale and the gain or loss is included in operations. Renewals
and replacements that extend the useful life of property and equipment are
treated as capital additions. Accumulated depreciation of other property
and equipment at December 31, 2004 and 2003, is approximately $3,845,000
and $3,803,000, respectively.
4. Depreciation and Amortization
All capitalized costs of natural gas and oil properties and equipment
including the estimated future costs to develop proved reserves are
amortized using the unit-of-production method using total proved reserves.
Depreciation of other equipment is computed based on an accelerated method
over the estimated useful lives of the assets, which range from three to
ten years. Amortization of leasehold improvements is computed based on the
straight-line method over the term of the associated lease. (See Note A.9.)
5. Natural Gas and Oil Sales and Gas Imbalances
Natural gas and oil imbalances are generated on properties for which two or
more owners have the right to take production "in-kind" and, in doing so,
take more or less than their respective entitled percentage.
The Company follows the entitlements method of accounting for natural gas
and oil sales, recognizing as revenues only its net share of all production
sold. Any amount received in excess of or less than the Company's revenue
interest is recorded as a net gas balancing asset or liability. At December
31, 2004, the Company's net underproduced position was approximately
121,000 Mcf with an associated asset of approximately $181,000, which is
recorded in other assets in the consolidated balance sheet. At December 31,
2003, the Company's net overproduced position was approximately 136,000 Mcf
with an associated liability of approximately $212,000. Charges for
transportation are included in natural gas and oil production taxes.
6. Cash Equivalents
All highly liquid unrestricted investments with a maturity of three months
or less when purchased are considered to be cash equivalents.
7. Short-Term Investments
The Company purchased a $1.5 million certificate of deposit (CD) with a
bank that served as collateral for a three-year $1.5 million standby letter
of credit issued to Carmen Acquisition Corp. in 2001. The CD is included in
current assets in the consolidated balance sheet as of December 31, 2003.
The letter of credit was released during the fourth quarter of 2003 due to
the sale of the Company's pipeline during 2003. (See Note K.) The Company
received proceeds from the CD in the first quarter of 2004, when the CD
matured.
F-24
8. Credit and Market Risk
The Company sells natural gas and oil to various customers and participates
with other parties in the drilling, completion and operation of natural gas
and oil wells. Joint interest and natural gas and oil sales receivables
related to these operations are generally unsecured. In 2004, approximately
52% of total revenues were to four customers (68% to four customers in 2003
and 63% to four customers in 2002), with sales to each comprising 23%, 11%,
10% and 8% (27%, 20%, 12% and 9% in 2003 and 35%, 16%, 6% and 6% in 2002)
of total revenues. For the years ended December 31, 2004, 2003 and 2002,
the provisions for doubtful accounts receivable were approximately
$385,000, $17,000 and $450,000, respectively, while charge-offs of the
allowance were approximately $146,000, $479,000 and $0, respectively. For
the years ended December 31, 2004, 2003 and 2002, the Company received
approximately $62,000, $56,000 and $0, respectively, for accounts
previously written-off. The Company has established joint interest
operations accounts receivable allowances, which management believes are
adequate for uncollectible amounts at December 31, 2004 and 2003, based on
management's assessment of the credit worthiness of the joint interest
owners and the Company's ability to realize the receivables through netting
of anticipated future production.
At December 31, 2004 and 2003, the Company had cash deposits concentrated
in certain banks, which exceeded the maximum insured by the Federal Deposit
Insurance Corporation. The book balances of these deposits totaled
approximately $1,175,000 and $3,799,000 at December 31, 2004 and 2003,
respectively.
9. Deferred Costs
Deferred loan and offering costs are stated at cost net of amortization
computed using the straight-line method over the term of the related loan
agreement. The estimated aggregate amortization expense for the next five
fiscal years is as follows:
2005 $ 619,000
2006 619,000
2007 600,000
2008 7,000
2009 -
10. General and Administrative Expense
The Company receives fees for the operation of jointly-owned oil and gas
properties and records such reimbursements as reductions of general and
administrative expense. Such fees totaled approximately $212,000, $406,000
and $517,000 for the years ended December 31, 2004, 2003 and 2002,
respectively.
11. Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Estimates and assumptions that,
in the opinion of management of the Company are significant include natural
gas and oil reserves, amortization relating to natural gas and oil
properties and asset retirement obligations.
12. Fair Value of Financial Instruments
Cash and cash equivalents, trade receivables and payables and installment
notes: The carrying amounts reported in the balance sheets approximate fair
value due to the short-term maturity of these instruments.
Long-term debt: The carrying amount reported in the balance sheets
approximates fair value because this debt instrument carries a variable
interest rate based on market interest rates.
F-25
Senior Notes: The carrying amount reported in the balance sheets exceeds
fair value at December 31, 2004 and December 31, 2003, by approximately
$1.4 million and $7.1 million, respectively, based upon management's
estimates. Management bases its estimate on information from the bond
underwriters on current bids of the Company's bonds.
Derivative contracts: The carrying amount reported in the balance sheets is
the fair value of the contracts based upon prices quoted by the
counterparty to the agreements.
13. Reclassifications
Certain reclassifications of previously reported amounts for 2003 and 2002
have been made to conform with the 2004 presentation format. These
reclassifications had no effect on net income (loss).
14. Accounting Policy for Derivatives
The Company applies the provisions of SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended. SFAS No. 133
requires companies to recognize all derivative instruments as either assets
or liabilities in the statement of financial position at fair value.
The accounting for changes in the fair value of a derivative depends on the
intended use of the derivative and resulting designation. For derivatives
designated as cash flow hedges and meeting the effectiveness guidelines of
SFAS No. 133, changes in fair value are recognized in other comprehensive
income until the hedged item is recognized in earnings. Hedge effectiveness
is measured quarterly based on relative changes in fair value between the
derivative contract and hedged item during the period of hedge designation.
The ineffective portion of a derivative's change in fair value is
recognized currently in earnings. Forecasted transactions designated as the
hedged item in a cash flow hedge are regularly evaluated to assess whether
they continue to be probable of occurring, and if the forecasted
transaction is no longer probable of occurring, any gain or loss deferred
in accumulated other comprehensive income is recognized in earnings
currently.
F-26
The Company entered into numerous derivative contracts to reduce the impact
of natural gas and oil price fluctuations. The Company did not formally
designate these transactions as hedges as required by SFAS No. 133 in order
to receive hedge accounting treatment. Accordingly, all gains and losses on
the derivative financial instruments during 2004, 2003 and 2002, have been
recorded in the statement of operations.
15. Earnings per Common Share
Basic earnings per share is computed by dividing net income by the weighted
average number of common shares outstanding for the period. Diluted
earnings per share reflects the potential dilution that could occur if
dilutive stock options and warrants were exercised, calculated using the
treasury stock method. A reconciliation of net income (loss) and weighted
average shares used in computing basic and diluted net income (loss) per
share is as follows for the years ended December 31 (in thousands, except
share and per share amounts):
2004 2003 2002
------------ ----------- --------
BASIC INCOME (LOSS) PER SHARE:
Net income (loss) $ 5,348 $ (1,528) $ 1,933
========== ========== ==========
Weighted average shares 2,549 2,727 2,727
========== ========== ==========
Basic net income (loss) per share $ 2,098.15 $ (560.32) $ 708.84
========== ========== ==========
DILUTED INCOME (LOSS) PER SHARE:
Net income (loss) $ 5,348 $ (1,528) $ 1,933
========== ========== ==========
Weighted average shares 2,549 2,727 2,727
Dilutive effect of stock options 93 - -
----------- ----------- ----------
Weighted average shares assuming
dilutive effect of stock options 2,642 2,727 2,727
========== ========== ==========
Diluted net income (loss) per share $ 2,024.29 $ (560.32) $ 708.84
========== ========== ==========
During 2003, the Company executed a 1,000-to-1 reverse stock split. Prior
period amounts have been restated to reflect the reverse stock split.
16. Asset Retirement Obligations
In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143
addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated asset
retirement costs and amends FASB Statement No. 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies. SFAS No. 143 requires that
the fair value of a liability for an asset retirement obligation be
recognized in the period in which it is incurred if a reasonable estimate
of fair value can be made, and that the associated asset retirement costs
be capitalized as part of the carrying amount of the long-lived asset. The
Company adopted this standard as of January 1, 2003. The effect of this
standard on the Company's results of operations and financial condition at
adoption included an increase in long-term liabilities for plugging and
abandonment costs of natural gas and oil properties of $1,304,000, net
increase in natural gas and oil properties equipment of $530,000, and a
non-cash loss as a result of the cumulative effect of change in accounting
principle, net of tax, of $448,000 (using a 6.25% discount factor). The
Company recorded accretion expense of approximately $78,000 and $48,000 in
2004 and 2003, respectively.
Had the provisions of SFAS No. 143 been applied in 2002, the liability for
asset retirement obligation would have been approximately $1,253,000 at
January 1, 2002 and the Company's net income and earnings per share for the
year ended December 31, 2002 would have been as follows (in thousands,
except per share amounts):
As Reported Pro Forma
----------- ---------
Net income $ 1,933 $ 1,847
Income per share (basic and diluted) $ 708.84 $ 677.46
F-27
The Company recorded the following activity related to the asset retirement
liability for the years ended December 31, 2004 and 2003 (in thousands):
2004 2003
-------- -------
Liability for asset retirement obligations, beginning of year $ 1,352 $ 1,304
Obligations for wells sold with RB Operating Company (238) -
Accretion expense 78 48
New obligations for wells drilled 275 -
Obligations for wells purchased in WG Acquisition 4,661 -
Obligations for wells sold (71) -
-------- --------
Liability for asset retirement obligations, end of year $ 6,057 $ 1,352
======== ========
17. Recently Issued Accounting Pronouncements
In April 2002, the FASB issued SFAS No. 145, Recission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. Under the provisions of SFAS No. 145, gains and losses from
the extinguishment of debt generally will no longer be classified as
extraordinary items in the statement of operations. The provisions of SFAS
No. 145 related to the extinguishment of debt become effective for the
Company beginning in 2003. Upon adoption, all gains and losses on
extinguishments of debt that were previously classified as extraordinary
items in prior periods were reclassified in the Company's consolidated
statements of operations.
In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities, which requires companies to recognize
costs associated with exit or disposal activities when they are incurred
rather than at the date of a commitment to an exit or disposal plan.
Examples of costs covered by the standard include lease termination costs
and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or
disposal activity. SFAS No. 146 is effective for fiscal years beginning
after December 31, 2002, with early application encouraged. The Company
adopted this standard January 1, 2003. The adoption did not have a material
impact on the Company's consolidated financial position or results of
operations.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FAS 123. The
standard provides additional transition guidance for companies that elect
to voluntarily adopt the accounting provisions of SFAS No. 123, Accounting
For Stock-Based Compensation. SFAS No. 148 does not change the provisions
of SFAS No. 123 that permit entities to continue to apply the intrinsic
value method of APB 25, Accounting for Stock Issued to Employees. The
Company currently has no stock options outstanding to employees and already
applies the accounting provisions of SFAS No. 123 to the stock options
discussed in Note H. Accordingly, the adoption of SFAS No. 148 did not have
a material impact on the Company's consolidated financial position or
results of operations.
In November 2002, the FASB issued Interpretation No. 45 (FIN 45),
Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45
requires that upon the issuance of guarantees, the guarantor must recognize
a liability for the fair value of the obligations it assumes under the
guarantee. Liability recognition is required on a prospective basis for
guarantees that are made or modified after December 31, 2002. The adoption
of FIN 45 had no impact on the Company's consolidated financial position or
results of operations.
In January 2003, the FASB issued Interpretation No. 46 (FIN 46),
Consolidation of Variable Interest Entities, an interpretation of ARB 51.
The primary objectives of FIN 46 are to provide guidance on the
identification of entities for which control is achieved through means
other than through voting rights (variable interest entities or VIEs) and
how to determine when and which business enterprise should consolidate the
VIE. This new model for consolidation applies to an entity which either (1)
the equity investors, if any, do not have a controlling financial interest
or (2) the equity investment at risk is insufficient to finance that
entity's activities without receiving additional subordinated financial
support from other parties. The adoption of this standard did not have any
impact on the Company's consolidated financial position or results of
operations.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on
Derivative Instruments and Hedging Activities. SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative
F-28
instruments embedded in other contracts (collectively referred to as
derivatives) and for hedging activities under SFAS No. 133. SFAS No. 149 is
effective for contracts entered into or modified after June 30, 2003, and
for hedging relationships designated after June 30, 2003. The Company
adopted SFAS No. 149 as of July 1, 2003. The adoption of SFAS No.149 did
not have a material impact on the Company's consolidated financial position
or results of operations.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity, which
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and equity
and requires that an issuer classify a financial instrument within the
scope of SFAS No. 150 as a liability (or an asset in some circumstances).
SFAS No. 150 was effective for the Company beginning in the third quarter
2003. The adoption of SFAS No. 150 did not have a material impact on the
Company's consolidated financial position or results of operations.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS
123R requires all share-based payments to employees, including grants of
employee stock options, to be recognized in the financial statements based
on their fair values and is effective for the first interim or annual
reporting period beginning after January 1, 2006. Management does not
believe the adoption of SFAS 123R will have a significant impact on the
Company's financial position or results of operations.
The FASB issued Staff Position (FSP) Nos. 141-1 and 142-1 as a result of
the March 17-18, 2004, Emerging Issues Task Force (EITF) meeting, after the
EITF reached a consensus on EITF Issue No. 04-2, Whether Mineral Rights are
Tangible or Intangible Assets, and concluded that mineral rights, as
defined in the issue, are tangible assets. This FSP addressed the
inconsistency between this consensus and the characterization of mineral
rights as intangible assets in SFAS No. 141 and SFAS No. 142. The guidance
in this FSP is applicable to the first reporting period beginning after
April 29, 2004 and, therefore effective for the Company January 1, 2005.
The FASB encourages early adoption. As such, the Company adopted this FSP
effective December 31, 2004. The adoption of this FSP did not have a
significant impact on the Company's financial position or results of
operations.
B - ACQUISITION
As previously disclosed in Note A.1, the Company completed the WG
Acquisition on December 17, 2004.
The final adjusted purchase price was $82.6 million, including the
assumption and payment of WG's long-term debt of $24.5 million, the
settlement of all outstanding derivative instruments of $14.4 million and
the balance (excluding the escrow) of $32.7 million was paid in cash. $11.0
million of the purchase price was deposited in two separate escrow accounts
to provide funds against which the Company may make claims for any
subsequently determined breach by WG of representations and warranties in
the merger agreement and for potential losses that may arise in connection
with certain existing litigation against WG. (See Note K.) The acquisition
was financed with a credit facility provided by Wells Fargo Foothill, Inc.
(Foothill), the Company's existing senior secured lender. (See Note D.)
RWG's principal assets are producing oil properties located in north Texas,
a gas plant and a significant block of undeveloped deep rights in
held-by-production leases. RWG's estimated proved reserves at December 31,
2004 included 9.5 million barrels of oil, 2.1 million barrels of natural
gas liquids and 10.0 billion cubic feet of natural gas, or a total of 13.2
million barrels of oil equivalent. The acquisition was done to increase the
reserve base for the Company.
The WG requisition was accounted for using the purchase method of
accounting in accordance with SFAS No. 141, Business Combinations, and the
purchase price has been initially allocated based on the estimated fair
value of the individual assets acquired and liabilities assumed at the date
of acquisition.
The assets acquired and preliminary purchase price allocation of the WG
acquisition is as follows:
Current assets $ 4,079
Natural gas and oil properties 98,601
F-29
Current liabilities (4,233)
Debt (340)
Asset retirement obligations (4,661)
Deferred taxes (10,869)
----------
$ 82,577
==========
The results of operations for the acquisition have been included in the
consolidated statement of operations from the date of acquisition. The
following unaudited pro forma consolidated results of operations are
presented as if the acquisition had occurred at the beginning of the
periods presented.
Year ended December 31,
2004 2003
------------ ----------
Revenues $ 49,412 $ 41,005
Loss before cumulative effect of
changes in accounting principle (5,768) (4,430)
Net loss $ (5,768) $ (4,878)
============ ============
Basic and diluted loss per share $ (2,262.85) $ (1,788.78)
============ ============
C - SALE OF SUBSIDIARY
On April 23, 2004, the Company entered into a stock sale agreement with
Range Energy I, Inc. to sell all of the issued and outstanding shares of
common capital stock of RB Operating Company (RBOC), a wholly-owned
subsidiary of the Company. The transaction closed on April 29, 2004 for a
purchase price of $22.5 million, subject to customary post-closing
adjustments. The Company received proceeds of $21.8 million, net of
transaction costs of $363,000 and cash held by RBOC transferred in the sale
of $814,000, of which $17.9 million was used to repay the remaining balance
on the Foothill loan and security agreement outstanding at the time. (See
Note D.2.)
With this sale, the Company sold approximately 27% of its proved natural
gas and oil reserves. As this significantly altered the relationship
between the Company's capitalized costs and proved reserves, the Company
recognized a gain on the sale of $12.1 million.
D - LONG-TERM DEBT
Long-term debt at December 31 consists of the following (in thousands):
2004 2003
------------ -----------
11.5% Senior Notes due 2008, net of discount $ 28,268 $ 28,226
Revolving Credit Facility 88,663 17,752
Installment loan agreements 413 79
------------ -----------
117,344 46,057
Less amount due within one year 3,891 61
------------ -----------
$ 113,453 $ 45,996
============ ===========
The amount of required principal payments for the next five years and
thereafter, as of December 31, 2004, are as follows: 2005-$3.9 million;
2006-$5.1 million; 2007-$80.0 million; 2008-$28.4 million; 2009-none.
1. Senior Notes
In February 1998, the Company completed the sale of $115 million of 11.5%
Senior Notes due 2008 in a public offering of which $28.4 million remained
outstanding at December 31, 2004 and 2003. The Senior Notes are senior
unsecured obligations of the Company and are redeemable at the option of
the Company in whole or in part, at any time on or after February 15, 2005,
at prices ranging from 111.5% to 103.8% of face amount to their scheduled
maturity in 2008.
F-30
The indenture under which the Senior Notes were issued contained certain
covenants, including covenants that limited (i) incurrences of additional
indebtedness and issuances of disqualified capital stock, (ii) restricted
payments, (iii) dividends and other payments affecting subsidiaries, (iv)
transactions with affiliates and outside directors' fees, (v) asset sales,
(vi) liens, (vii) lines of business, (viii) merger, sale or consolidation
and (ix) non-refundable acquisition deposits.
In November 2002, the Company recognized a gain (net of unamortized
deferred offering and original issue discount costs, transaction fees) of
$32.9 million as a result of the purchase of an additional $63.475 million
face amount of the Senior Notes. The Senior Notes, plus accrued interest of
$1.988 million, were purchased at 46% of face amount and were canceled by
the Company. The Company utilized borrowings under its revolving credit
agreement and available cash to purchase the Senior Notes.
In connection with the Company's November 2002 purchase of the Senior
Notes, the indenture was amended to eliminate the limitations described
above.
At December 31, 2004 and 2003, the unamortized original issue discount
associated with the Notes totaled approximately $128,000 and $170,000,
respectively.
2. Revolving Credit Facility
In November 2002, the Company entered into a two-part revolving credit
facility with Foothill. It provided for a three year, $30 million revolving
commitment, subject to certain limitations. Advances under the credit
facility bore interest, payable monthly, at the Foothill reference rate
plus 2% per annum, but no less than 6% per annum on Loan A ($17.8 million
outstanding at December 31, 2003) and at the Foothill reference rate plus
6% per annum, but no less than 10% per annum on Loan B ($0 outstanding at
December 31, 2003). (See Note C.)
In December, 2004 the Company entered into an amended and restated $90.0
million senior secured credit facility provided by Foothill. The facility
includes a $30.0 million term loan and a $60.0 million revolving credit
facility, reducing by $2.5 million per quarter commencing September 30,
2005 and continuing until the committed amount of the revolver is reduced
to $50.0 million. Borrowings under the revolving credit facility bear
interest at Foothill's base rate plus 2% (7.25% at December 31, 2004), or
LIBOR plus 4%, at the option of the Company, while advances under the term
loan bear interest at the base rate plus 4% (9.25% at December 31, 2004),
or LIBOR plus 6%, also at the option of the Company. The entire facility
will mature in three years. The amount of credit available under the credit
facility at December 31, 2004 was $1.3 million.
The Company is required to pay a commitment fee equal to .375% per annum on
the amount by which the borrowing base exceeds the aggregate amount
outstanding under the Foothill credit facility. Amounts outstanding under
the Foothill credit facility are collateralized by substantially all
current and future assets of the Company and its subsidiaries. Along with
the pledged collateral mentioned above, Foothill also has first rights to
the Company's cash accounts.
The credit facility contains customary covenants which, among other things,
require periodic financial and reserve reporting and limit the Company's
incurrence of indebtedness, executive compensation, capital expenditures,
transactions with affiliates, sales of assets, liens, loans, mergers and
investments and require the Company to meet minimum EBITDA thresholds.
Additionally, the credit facility requires the Company to hedge at least
40%, but not more than 80%, of its estimated production for the ensuing
six-month period. The Company was in compliance with these covenants or had
obtained waivers at December 31, 2004.
If the Company fails to satisfy or obtain a waiver for the covenants of the
credit facility, Foothill could consider the Company to be in default. Upon
default, Foothill may declare all obligations immediately due and payable,
cease advancing money or extending credit, terminate the agreement, and
secure its rights in the Company's collateral. The Foothill credit facility
also contains a subjective acceleration clause whereby Foothill may declare
an event of default if it determines a material adverse change has
occurred. Management believes it is unlikely that the subjective
acceleration clause would be asserted in 2005 and therefore has classified
the credit facility as a long-term obligation in accordance with its stated
maturity.
F-31
E - SUBSIDIARY GUARANTORS
The Company's Senior Notes are fully and unconditionally guaranteed,
jointly and severally, on a senior unsecured basis, by all of the Company's
current and future subsidiaries (the Subsidiary Guarantors). The following
table sets forth condensed consolidating financial information of the
Subsidiary Guarantors. There are currently no restrictions on the ability
of the Subsidiary Guarantors to transfer funds to the Company in the form
of cash dividends, loans or advances.
The following represents the condensed consolidating balance sheets for the
Company and its subsidiaries as of December 31, 2004 and 2003 (in
thousands):
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------ ---------- ----------- -------
December 31, 2004
Current assets $ 1,455 $ 7,020 $ - $ 8,475
Property and equipment, net 10,563 118,689 - 129,252
Investment in subsidiaries 11,694 - (11,694) -
Other assets 2,543 - - 2,543
---------- ----------- ----------- -----------
Total assets $ 26,255 $ 125,709 $ (11,694) $ 140,270
========== =========== =========== ===========
Current liabilities $ 6,086 $ 18,923 $- $ 25,009
Long-term debt 34,489 78,964 - 113,453
Other non-current liabilities 3,738 5,194 - 8,932
Deferred income taxes 3,602 10,934 - 14,536
---------- ----------- ----------- -----------
Total liabilities 47,915 114,015 - 161,930
Stockholders' equity (deficiency) (21,660) 11,694 (11,694) (21,660)
---------- ----------- ----------- -----------
Total liabilities and stockholders' equity
(deficiency) $ 26,255 $ 125,709 $ (11,694) $ 140,270
========== =========== =========== ===========
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------ ---------- ----------- -------
December 31, 2003
Current assets $ 3,509 $ 15,455 $ (11,614) $ 7,350
Property and equipment, net 16,946 20,647 - 37,593
Investment in subsidiaries 28,216 - (28,216) -
Other assets 1,291 - - 1,291
---------- -------- ---------- ---------
Total assets $ 49,962 $ 36,102 $ (39,830) $ 46,234
========== ======== ========== =========
Current liabilities $ 16,302 $ 4,020 $ (11,614) $ 8,708
Long-term debt 45,996 - - 45,996
Other non-current liabilities 3,908 410 - 4,318
Deferred income taxes 4,430 3,456 - 7,886
---------- --------- ---------- ---------
Total liabilities 70,636 7,886 (11,614) 66,908
Stockholders' equity (deficiency) (20,674) 28,216 (28,216) (20,674)
---------- --------- ---------- ---------
Total liabilities and stockholders' equity
(deficiency) $ 49,962 $ 36,102 $ (39,830) $ 46,234
========== ========= ========== =========
The following represents the condensed consolidating statements of
operations and statements of cash flows for the Company and its
subsidiaries for the years ended December 31, 2004, 2003 and 2002 (in
thousands):
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------ ---------- ----------- -------
F-32
Year ended December 31, 2004
Operating revenues $ 7,986 $ 9,181 $ (80) $ 17,087
Operating expenses 11,553 3,690 (80) 15,163
---------- --------- ---------- --------
Operating (loss) income (3,567) 5,491 - 1,924
Other income 12,015 25 (4,883) 7,157
---------- --------- ---------- --------
Income before income taxes 8,448 5,516 (4,883) 9,081
Income taxes 3,100 633 - 3,733
---------- --------- --------- --------
Net income $ 5,348 $ 4,883 $ (4,883) $ 5,348
========== ========= ========= ========
Cash flows provided by (used in)
operating activities $ 85,788 $ (83,991) $ - $ 1,797
Cash flows (used in) provided by
investing activities (66,556) 1,704 - (64,852)
Cash flows (used in) provided by
financing activities (20,113) 82,225 - 62,112
---------- --------- --------- --------
Decrease in cash and cash equivalents
(881) (62) - (943)
Cash and cash equivalents, beginning of
year 1,924 194 - 2,118
---------- --------- --------- --------
Cash and cash equivalents, end of year
$ 1,043 $ 132 $ - $ 1,175
========== ========= ========= ========
F-33
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------ ---------- ----------- -------
Year ended December 31, 2003
Operating revenues $ 15,104 $ 5,395 $ - $ 20,499
Operating expenses 14,320 1,092 - 15,412
--------- ---------- -------- --------
Operating income 784 4,303 - 5,087
Other expense (3,270) - (1,601) (4,871)
--------- ---------- -------- --------
Income (loss) from continuing operations
before income taxes (2,486) 4,303 (1,601) 216
Income taxes (1,406) 1,634 - 228
--------- ---------- -------- --------
Income (loss) from continuing operations
(1,080) 2,669 (1,601) (12)
Loss from discontinued operations, net of
tax - (1,068) - (1,068)
--------- ---------- -------- --------
Net income (loss) before cumulative
effect of change in accounting principle
(1,080) 1,601 (1,601) (1,080)
Cumulative effect of change in accounting
principle, net of tax (448) - - (448)
--------- ---------- -------- --------
Net income (loss) $ (1,528) $ 1,601 $ (1,601) $ (1,528)
========= ========== ======== ========
Cash flows provided by (used in)
operating activities $ 17,756 $ (11,982) $ - $ 5,774
Cash flows (used in) provided by
investing activities (4,423) 11,845 - 7,422
Cash flows (used in) provided by
financing activities (12,333) - - (12,333)
--------- ---------- -------- --------
Increase (decrease) in cash and cash
equivalents 1,000 (137) - 863
Cash and cash equivalents, beginning of
year 924 331 - 1,255
--------- ---------- -------- --------
Cash and cash equivalents, end of
year $ 1,924 $ 194 $ - $ 2,118
========= ========== ======== ========
F-34
Total
Subsidiary Consolidating Consolidated
Parent Guarantors Adjustments Amounts
------ ---------- ----------- -------
Year ended December 31, 2002
Operating revenues $ 7,441 $ 2,575 $ - $ 10,016
Operating expenses 12,512 360 - 12,872
--------- --------- --------- ---------
Operating income (loss) (5,071) 2,215 - (2,856)
Other income 2,656 1,481 19,797 23,934
--------- --------- --------- ---------
Income (loss) from continuing operations
before income taxes (2,415) 3,696 19,797 21,078
Income taxes (4,348) 12,323 - 7,975
--------- --------- --------- ---------
Income (loss) from continuing operations
1,933 (8,627) 19,797 13,103
Loss from discontinued operations, net of
tax - (11,170) - (11,170)
--------- --------- --------- ---------
Net income (loss) $ 1,933 $ (19,797) $ 19,797 $ 1,933
========= ========= ========= =========
Cash flows used in operating activities
$ (6,349) $ (8,493) $ - $ (14,842)
Cash flows provided by (used in)
investing activities 4,332 (4,378) - (46)
Cash flows (used in) provided by
financing activities (3,889) 158 - (3,731)
--------- --------- --------- ---------
Decrease in cash and cash equivalents
(5,906) (12,713) - (18,619)
Cash and cash equivalents, beginning of
year 6,830 13,044 - 19,874
--------- --------- --------- ---------
Cash and cash equivalents, end of year
$ 924 $ 331 $ - $ 1,255
========= ========= ========= =========
The Company has not allocated to its subsidiaries general and
administrative expenses. Accordingly, the above condensed consolidating
information is not intended to present the Company's subsidiaries on a
stand-alone basis.
F - LEASES
The Company leases office space and equipment under noncancelable operating
lease agreements that expire on various dates through 2007. Approximate
future minimum lease payments for operating leases at December 31, 2004,
are as follows:
2005 $ 287,000
2006 261,000
2007 54,000
-----------
$ 602,000
===========
F-35
Rent expense of approximately $288,000, $254,000 and $203,000 was incurred
under operating leases in the years ended December 31, 2004, 2003 and 2002,
respectively.
In conjunction with the WG Acquisition, the Company acquired capital leases
for operating equipment. Future minimum lease payments for capital leases
are approximately $100,000 in 2005 and approximately $50,000 in 2006.
G - DEFINED CONTRIBUTION PLAN
The Company sponsors a 401(k) defined contribution plan for the benefit of
substantially all employees. The plan allows eligible employees to
contribute up to 100% of their annual compensation, not to exceed $13,000
for those under 50 years of age and $16,000 for those over 50 in 2004.
Employer contributions to the plan are discretionary. Company contributions
to the plan in 2004, 2003 and 2002 were $190,000, $163,000 and $148,000,
respectively.
H - CAPITAL STOCK
Pursuant to a Special Retainer Agreement effective July 1, 1998, as
amended, the Board of Directors granted an outside counsel an option to
purchase 50 shares of the Company's common stock, which became fully vested
during 2000, and is exercisable through June 30, 2008. On April 4, 2002,
the Board of Directors granted fully-vested options to purchase an
additional 50 shares of the Company's common stock and set the exercise
price on all options at $2,500, an amount which management believes
approximates the per common share value of the Company at that date.
Expense of approximately $71,000 related to the stock options has been
recognized in the 2002 statement of operations based on the estimated fair
value of the stock options. As of December 31, 2004, after the redemption
of one-sixth of the outstanding stock options in August 2004 described
below, options to purchase 83.33 shares remained outstanding.
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following
assumptions: risk-free interest rate of 5.0%, no expected dividends,
expected life of 6.7 years and no volatility.
Additionally, the Board of Directors approved the 1998 Stock Incentive Plan
and reserved 550 shares of common stock, which may be granted under the
plan. No grants have been made at December 31, 2004.
In April 2002, the Company amended its Articles of Incorporation and
replaced all its preferred stock and outstanding common stock shares with
5,000 shares of common stock. Prior to the amendment, the Company had an
authorized class of Preferred Stock consisting of 5,000 shares, none of
which were issued and outstanding.
In December 2003, the Company amended its Articles of Incorporation for a
1,000-to-1 reverse stock split, authorizing 5,000 shares of common stock
with a par value of $10.00 per share. Prior period amounts have been
restated to reflect the reverse stock split.
In August 2004, the Company repurchased and retired one-sixth of its
outstanding common shares and vested stock options for $5.0 million and
$135,000, respectively. The cash paid to repurchase the common shares and
stock options is equal to their respective estimated fair values on the
date of settlement and, therefore, is recorded as a reduction of equity. No
additional compensation expense was incurred as a result
F-36
of the repurchase of the stock options. Absent a market price for or
comparable to the untraded securities, management estimated the fair value
of the common stock by dividing the estimated net asset value per share by
the total number of shares outstanding. The fair value of the stock options
was calculated as the excess of the estimated value of the common stock
over the exercise price of the options. Management believes the estimation
method and assumptions utilized represent the best available evidence of
the value of the equity securities at the settlement date.
The Company declared cash dividends of $804,000 for the year ended December
31, 2003, $294.68 per share. The unpaid dividends at December 31, 2003 are
recorded as other accrued liabilities on the balance sheet and were paid in
January 2004. The Company declared cash dividends of $1,200,000 for the
year ended December 31, 2004, $146.68 per share for $800,000 declared prior
to the stock repurchase, and $176.02 per share for the $400,000 declared
subsequent to the stock repurchase. All dividends declared in 2004 were
paid by December 31, 2004.
I - INCOME TAXES
Deferred income taxes of the Company reflect the net tax effects of
temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for
income tax purposes. Significant components of the Company's deferred tax
assets and liabilities as of December 31, are as follows (in thousands):
2004 2003
----------- --------
DEFERRED TAX ASSETS RELATED TO:
Financial charges which are deferred for tax purposes $ 179 $ 573
Net operating loss carryforward 8,542 -
---------- ----------
8,721 573
DEFERRED TAX LIABILITIES RELATED TO:
Financial bases in excess of tax bases primarily on
properties and equipment 23,257 8,459
---------- ----------
net deferred income tax liabilities $ 14,536 $ 7,886
========== ==========
The reconciliation of income taxes computed at the U.S. Federal statutory
tax rates to the Company's income tax provision based on income from
continuing operations before income taxes for the years ended December 31
is as follows (in thousands):
2004 2003 2002
----------- ----------- -----------
Income tax provision (benefit) at statutory $ 3,088 $ 73 $ 7,167
rate
State income taxes 361 6 611
Non-deductible expenses and other 284 149 197
----------- ----------- -----------
Income tax provision (benefit) $ 3,733 $ 228 $ 7,975
=========== =========== ===========
The Company paid $300,000 for income taxes in the year ended December 31,
2004 and $0 in 2003 and 2002.
F-37
J - SALE OF PIPELINE SYSTEM
On July 18, 2003, the Company entered into an agreement to sell its
pipeline system to Continental Gas, Inc. (CGI) for $15.0 million, effective
August 1, 2003, and subject to certain adjustments. The purchase price was
reduced by $3 million in settlement of the claim by CGI. (See Note K.) The
sale of the pipeline closed July 31, 2003, and approximately $11.8 million
net proceeds were used to reduce the Company's credit facility.
The results of operations and cash flows related to the pipeline system are
reflected in the accompanying financial statements as discontinued
operations. For the years ended December 31, 2003 and 2002, revenues for
discontinued operations were $14,500,000 and $14,409,000, respectively.
Interest expense of $609,000 and $1,419,000 for the years ended December
31, 2003 and 2002, respectively, has been allocated to discontinued
operations in the statements of operations. The 2002 financial statements
have been reclassified to provide for comparison.
K - COMMITMENTS AND CONTINGENCIES
The Company has established a severance agreement for the President and CEO
of the Company. This agreement provides for severance benefits to be paid
upon involuntary separation as a result of actions taken by the Company or
its successors. At December 31, 2004 and 2003, the severance benefits under
this agreement were approximately $1,750,000 and $1,825,000, respectively.
A provision for these benefits will not be made until an involuntary
termination is probable.
In November, 2004 Ted Collins, Jr. filed a lawsuit against WG Energy
Holdings, Inc. (WG) and Michael G. Grella, the former President of that
company. Mr. Collins alleges that WG and Mr. Grella failed to timely apply
a $1.5 million advance toward enhancing the shallow depths in certain
leases, and failed to deliver assignments of certain interests in those
leases, both as allegedly required by the participation agreement between
them. Mr. Collins further claims that WG has failed to account to him for
revenues allegedly accruing to him under the terms of the participation
agreement. Mr. Collins seeks an accounting and to have the partial
assignment and/or participation agreement reformed based on allegations of
mutual mistake, and further pleads claims of fraud and negligent
misrepresentation. He has not pled a specific amount of damages. Management
is unable to estimate a range of potential loss, if any, related to this
lawsuit, and accordingly no amounts have been recorded in the consolidated
financial statements. As this lawsuit existed at the time of the Company's
acquisition of WG, a $5 million escrow was established as a reserve for
this lawsuit. (See Note B.)
In June 2003, a lawsuit was filed by CGI against Great Plains Pipeline
Company (GPPC), a wholly owned subsidiary of the Company, in the District
Court of Garfield County, Oklahoma. GPPC and CGI were parties to a Gas
Service Contract (the Contract) dated November 22, 1996, pursuant to which
GPPC delivered to CGI all of the gas that flowed through GPPC's pipeline
system. CGI compressed and processed the gas and then redelivered thermally
equivalent volumes to GPPC at the tailgate of the CGI processing plant in
Woods County. The term of the Contract is for the life of the leases from
which GPPC purchased gas in a specified service area.
In the lawsuit, CGI alleged that over several years, GPPC delivered gas
under the Contract that was produced from wells and leases lying outside
the specified service area and that such gas was not covered by and should
not have been delivered under the Contract. CGI alleged that only gas
produced from wells and
F-38
leases lying inside the service area should be counted for purposes of
determining whether or not a compression and processing fee is due, that
when outside volumes were excluded, compressing and processing fees were
due CGI, and with respect to the outside volumes GPPC delivered under the
Contract, GPPC owed CGI a market rate for compressing and processing
services performed with respect to such gas.
As a part of the agreement for the sale of the pipeline system by GPPC to
CGI, the parties agreed to $3.0 million as consideration for a
contemporaneous mutual release by CGI and GPPC of all claims of every
nature arising out of the Gas Service Agreement between the parties. A
provision for litigation settlements in the amount of $3.0 million was
recorded at December 31, 2002 as a current liability and netted from the
proceeds received from the sale of the pipeline. (See Note J.)
In April 2002, a lawsuit was filed in the District Court for Woods County,
Oklahoma against the Company, certain of its subsidiaries and various other
individuals and unrelated companies, by lessors and royalty owners of
certain tracts of land, which were sold to Chesapeake in 2001. The petition
claims that additional royalties are due, because Carmen Field Limited
Partnership (CFLP), a wholly-owned subsidiary of the Company, resold oil
and gas purchased at the wellhead for an amount in excess of the price upon
which royalty payments were based and paid no royalties on natural gas
liquids extracted from the gas at plants downstream of the system. Other
allegations include under-measurement of oil and gas at the wellhead by
CFLP, failure to pay royalties on take-or-pay settlement proceeds and
failure to properly report deductions for post-production costs in
accordance with Oklahoma's check stub law.
Company defendants have filed answers in the lawsuit denying all material
allegations set out in the petition. The Company believes that fair and
proper accounting was made to the royalty owners for production from the
subject leases and intends to vigorously defend the lawsuit. Management is
unable to estimate a range of potential loss, if any, related to this
lawsuit, and accordingly no amounts have been recorded in the consolidated
financial statements. In the event the court should find Company defendants
liable for damages in the lawsuit, a former joint venture partner is
contractually obligated to pay a portion of any damages assessed against
the defendant lessees up to a maximum contribution of approximately $2.8
million.
In a suit filed in mid-2001 by a large independent oil and gas exploration
and production company, claims arising from gas balancing on seven wells
located in western Oklahoma, then operated by the Company, were made. In
December 2002, a provision for settlement of this claim was made in the
amount of $140,000, which was paid in May 2003.
Pursuant to a Special Retainer Agreement effective July 1, 1998, as
amended, the Company is obligated to pay an outside counsel law firm
approximately $348,000 in the event that the agreement is terminated by
reason of expiration of term, by counsel for good reason, by reason of
change in control, or by the Company at will. A provision for the payment
will not be made until termination of the agreement is probable.
In 1996, the Company's predecessor sold a natural gas and oil property
located in Louisiana state waters in Plaquemines Parish. The property
included several uneconomical wells for which the Company estimated the
plugging and abandonment (P&A) obligation to be approximately $1,020,000.
The purchaser provided a letter of credit and a bond totaling $420,000 to
ensure funding of a portion of the P&A obligation. The P&A obligation would
revert to the Company in the event the purchaser does not complete the
required P&A activities. As a result, in connection with the sale, the
Company recorded a contingent liability of $600,000, which is included in
the accompanying consolidated balance sheets.
The Company is also involved in legal proceedings and litigation in the
ordinary course of business. In the opinion of management, the outcome of
such matters will not have a material adverse effect on the Company's
financial position or results of operations.
L - HEDGING ACTIVITIES
The Company utilizes a cash flow hedging program to reduce its exposure to
unfavorable changes in natural gas prices that are subject to significant
and often volatile fluctuation. In 2002, the Board of Directors approved
risk management policies and procedures to utilize financial products for
the reduction of defined commodity price risks in alignment with the terms
of the Company's revolving credit facility with Foothill. These policies
F-39
prohibit speculation with derivatives, limit the amount of production
hedged and limit hedge agreements to counterparties with appropriate credit
standings. During 2002, the Company hedged portions of its forecasted
natural gas production by utilizing options and fixed-price natural gas
swap contracts. Under the swap contracts, the Company received a fixed
price for natural gas and paid a floating price (generally NYMEX futures
prices) to a counterparty. When market prices for natural gas decline, the
decline in the value of the cash flows from the Company's forecasted
natural gas production designated as being hedged is substantially offset
by gains in the value of the fixed price swap contracts. Conversely, when
market prices increase, the increase in the value of the cash flows from
the Company's forecasted natural gas production designated as being hedged
is substantially offset by losses in the value of the fixed price swap
contracts.
During 2004, 2003 and 2002, the Company entered into numerous derivative
contracts. The Company did not formally designate these transactions as
hedges as required by SFAS No. 133 in order to receive hedge accounting
treatment. Accordingly, all gains and losses on the derivative financial
instruments during 2004, 2003 and 2002 have been recorded in the statement
of operations.
At December 31, 2004, the Company had purchased put options on 37,958
barrels/month of crude oil through December, 2005, with a floor price of
$40.00. For natural gas, the Company had purchased collars on 152,000 MMbtu
through October 2005. The weighted average floor price was $5.65 per MMbtu
and the weighted average ceiling price was $7.84 per MMbtu. An asset of
approximately $1,509,000 was recorded in the consolidated balance sheets.
At December 31, 2003, the Company had collars in place on 15,167
barrels/month in 2004 for future oil production. The 15,167 barrels/month
in 2004 had a weighted average floor and ceiling of $24.50 and $32.35,
respectively. At December 31, 2003, the Company had purchased natural gas
put options on total notional volumes of 52,941 Mcf/month for 2004 with a
weighted average price of $4.92. At December 31, 2003, the Company also had
natural gas call options on total notional volumes of 54,000 Mcf/month for
2004 with a weighted average price of $6.71. An asset of approximately
$89,000 and a liability of approximately $67,000 were recorded in the
consolidated balance sheets.
The primary market risk related to the Company's derivative contracts are
the volatility in commodity prices. However, this market risk is offset by
the gain or loss recognized upon the related sale or purchase of the
natural gas that is hedged. Credit risk relates to the risk of loss as a
result of nonperformance by the Company's counterparties. The
counterparties are primarily major investment and commercial banks which
management believes present minimal credit risks.
F-40
M - FINANCIAL CONDITION AND MANAGEMENT PLANS
The financial statements of the Company have been prepared on the basis of
accounting principles applicable to a going concern, which contemplates the
realization of assets and the satisfaction of liabilities in the normal
course of business. As shown in the consolidated financial statements, the
Company has an accumulated deficit of $21,756,000 and negative working
capital of $17,871,000 at December 31, 2004. The financial statements do
not include any adjustments relating to the recoverability and
classification of asset carrying amounts or the amount and classification
of liabilities that might result should the Company be unable to continue
as a going concern.
Management believes that borrowings currently available to the Company
under the Company's credit facilities ($1.3 million available at December
31, 2004), the balance of unrestricted cash and anticipated cash flows from
operations will be sufficient to satisfy its currently expected capital
expenditures, working capital and debt service obligations for the
foreseeable future. The actual amount and timing of future capital
requirements may differ materially from estimates as a result of, among
other things, changes in product pricing and regulatory, technological and
competitive developments. Sources of additional financing may include
commercial bank borrowings, vendor financing and the sale of natural gas
and oil properties or equity or debt securities. Management cannot assure
that any such financing will be available on acceptable terms or at all.
N - RELATED PARTY TRANSACTIONS
For the years ended December 31, 2004, 2003 and 2002, the Company paid
expenses in the amount of $0, $260,000 and $46,000, respectively, for
expenses on behalf of the Danish Knights, a Limited Partnership, which is
owned by one of the shareholders of the Company.
The Company paid rent expense of approximately $66,000, $54,000 and $0
relating to a condominium for one of the shareholders of the Company for
the year ended December 31, 2004, 2003 and 2002, respectively.
For the years ended December 31, 2004, 2003 and 2002, approximately
$792,000, $299,000 and $140,000, respectively, of expenses (excluding the
rent payments discussed above) for the shareholders of the Company are
included in general and administrative expenses in the consolidated
statements of operations, some of which may be personal in nature.
O - DEFERRED COMPENSATION
On April 21, 2004, the Company adopted a Deferred Bonus Compensation Plan
(the Plan) for senior management employees of the Company. The Plan is to
provide additional compensation for significant business transactions with
a portion of each bonus to be deferred to encourage retention of key
employees. Determination of significant business transactions and terms of
awards is made by a committee comprised of the shareholders of the Company.
During 2004, three members of senior management were granted awards related
to the sale of RBOC. Each award provides for a total cash compensation of
$75,000 and vests on each anniversary date for three years, beginning on
July 1, 2004. Receipt of the award is contingent to the members being
employed on the anniversary date. Should there be a change of control or
involuntary termination, as defined in the award contract, each member will
become fully vested in his award. At December 31, 2004, $37,500 is recorded
in accrued compensation. Compensation expense is recorded on a
straight-line basis. For the year ended December 31, 2004, $112,500 has
been recorded as compensation expense in the consolidated statement of
operations.
P - NATURAL GAS AND OIL PRODUCING ACTIVITIES
Capitalized costs relating to natural gas and oil producing activities and
related accumulated depreciation and amortization at December 31 are
summarized as follows (in thousands):
2004 2003
------------ ---------
F-41
Proved natural gas and oil properties $ 147,392 $ 60,760
Accumulated depreciation and amortization (20,074) (24,006)
----------- -----------
$ 127,318 $ 36,754
=========== ===========
Costs incurred in natural gas and oil producing activities for the years
ended December 31 are as follows (in thousands, except per equivalent Mcf):
2004 2003 2002
---------- ----------- --------
Acquisition of proved properties $ 82,600 $ - $ 1,300
Development costs 5,580 4,080 3,698
Exploration costs 727 202 1,702
Amortization rate per equivalent Mcf 1.00 .92 .89
Q - SUBSEQUENT EVENTS
The Company amended the credit facility with Foothill on March 7, 2005.
This amendment decreased the minimum EBITDA threshold and decreased the
limit on the annual maximum amount of capital expenditures. In addition,
the Company paid dividends of $400,000 on April 12, 2005.
R - SUPPLEMENTARY NATURAL GAS AND OIL RESERVE INFORMATION (UNAUDITED)
The Company has interests in natural gas and oil properties that are
principally located in Texas, Louisiana, Oklahoma and New Mexico. The
Company does not own or lease any natural gas and oil properties outside
the United States of America.
The Company retains independent engineering firms to provide year-end
estimates of the Company's future net recoverable natural gas, oil, and
natural gas liquids reserves. Estimated proved net recoverable reserves as
shown below include only those quantities that can be expected to be
commercially recoverable at prices and costs in effect at the balance sheet
dates under existing regulatory practices and with conventional equipment
and operating methods.
Proved developed reserves represent only those reserves expected to be
recovered through existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells on undrilled acreage or
from existing wells on which a relatively major expenditure is required for
recompletion.
F-42
Net quantities of proved developed and undeveloped reserves of natural gas
and oil, including condensate and natural gas liquids, are summarized as
follows:
Natural Gas Crude Oil
(Million (Thousand
Cubic Feet) Barrels)
----------- ---------
December 31, 2001 35,488 1,902
Extensions and discoveries 2,808 813
Sales of reserves in place (96) (74)
Purchases of reserves in place 6,395 66
Revisions of previous estimates (6,931) (52)
Production (1,744) (204)
---------- ----------
December 31, 2002 35,920 2,451
---------- ----------
Extensions and discoveries 1,152 258
Sales of reserves in place (16) -
Purchases of reserves in place 1,114 -
Revisions of previous estimates (1,222) (99)
Production (2,381) (288)
---------- ----------
December 31, 2003 34,567 2,322
---------- ----------
Extensions and discoveries 3,016 17
Sales of reserves in place (4,979) (1,299)
Purchases of reserves in place 9,986 11,573
Revisions of previous estimates (2,496) 329
Production (1,899) (187)
---------- ----------
December 31, 2004 38,195 12,755
========== ==========
Proved developed reserves:
December 31, 2001 22,089 1,556
December 31, 2002 28,379 2,234
December 31, 2003 26,237 2,151
December 31, 2004 31,048 7,809
The following is a summary of a standardized measure of discounted net cash
flows related to the Company's proved natural gas and oil reserves. For
these calculations, estimated future cash flows from estimated future
production of proved reserves were computed using natural gas and oil
prices as of the end of the period presented. Future development and
production costs attributable to the proved reserves were estimated
assuming that existing conditions would continue over the economic lives of
the individual leases
F-43
and costs were not escalated for the future. Estimated future income tax
expenses were calculated by applying future statutory tax rates (based on
the current tax law adjusted for permanent differences and tax credits) to
the estimated future pretax net cash flows related to proved natural gas
and oil reserves, less the tax basis of the properties involved.
The Company cautions against using this data to determine the fair value of
its natural gas and oil properties. To obtain the best estimate of fair
value of the natural gas and oil properties, forecasts of future economic
conditions, varying discount rates, and consideration of other than proved
reserves would have to be incorporated into the calculation. In addition,
there are significant uncertainties inherent in estimating quantities of
proved reserves and in projecting rates of production that impair the
usefulness of the data.
The standardized measure of discounted future net cash flows relating to
proved natural gas and oil reserves at December 31 are summarized as
follows (in thousands):
2004 2003 2002
----------- ----------- ------------
Future cash inflows $ 711,781 $ 281,149 $ 220,558
Future production and development costs (283,809) (80,178) (64,264)
Future income tax expenses (136,669) (69,787) (52,533)
----------- ----------- -----------
Future net cash flows 291,303 131,184 103,761
10% annual discount for estimated timing of cash flows (129,983) (63,250) (50,392)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 161,320 $ 67,934 $ 53,369
=========== =========== ===========
The following are the principal sources of change in the standardized
measure of discounted future net cash flows of the Company for each of the
three years in the period ended December 31 (in thousands):
2004 2003 2002
----------- ----------- ------------
Discounted future net cash flows at beginning of year $ 67,934 $ 53,369 $ 33,020
Changes during the year:
Sales and transfers of natural gas and oil produced, net
of production costs (12,466) (15,428) (5,786)
Net changes in prices and production costs 7,612 33,972 30,124
Extensions and discoveries, less related costs 9,337 5,153 15,620
Development costs incurred and revisions - - 525
Sales of reserves in place (19,840) (26) (1,005)
Purchases of reserves in place 153,364 1,643 11,867
Revisions of previous quantity estimates (2,323) (8,657) (13,075)
Net change in income taxes (38,246) (9,253) (19,911)
Accretion of discount 6,793 8,075 4,049
Other (10,845) (914) (2,059)
----------- ----------- -----------
Net change 93,386 14,565 20,349
----------- ----------- -----------
Discounted future net cash flows at end of year $ 161,320 $ 67,934 $ 53,369
=========== =========== ===========
F-44
Prices used in computing these calculations of future cash flows from
estimated future production of proved reserves were $40.25, $29.25 and
$27.75 per barrel of oil at December 31, 2004, 2003 and 2002, respectively,
and $6.02, $6.17 and $4.24 per thousand cubic feet of natural gas at
December 31, 2004, 2003 and 2002, respectively.
F-45
