UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2000
--------------------------------------------
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
--------------- ---------------------
Commission File Number: 1-15639
---------------------
CARBON ENERGY CORPORATION
--------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Colorado 84-1515097
------------------------------- -------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1700 Broadway, Suite 1150, Denver, CO 80290
----------------------------------------------- ------------------
(Address of principal executive offices) (Zip Code)
(303) 863-1555
----------------------------------------------------
(Registrant's telephone number, including area code)
Not Applicable
-------------------------------------------------------------------------------
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section the past 90 days. Yes X No
---- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the
Class Outstanding at August 6, 2000
---------------------------- ------------------------------
Common stock, no par value 6,052,826 shares
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
------------- ------------
ASSETS (unaudited)
------
<S> <C> <C>
Current assets:
Cash $ 143,000 $ 995,000
Current portion of employee trust 351,000 881,000
Accounts receivable, trade 2,680,000 2,286,000
Accounts receivable, other 257,000 69,000
Amounts due from broker 3,622,000 1,250,000
Prepaid expenses and other 277,000 107,000
------------- ------------
Total current assets 7,330,000 5,588,000
------------- ------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 7,481,000 7,879,000
Proved properties 41,855,000 25,020,000
Furniture and equipment 359,000 214,000
------------- ------------
49,695,000 33,113,000
Less accumulated depreciation, depletion and amortization (3,119,000) (627,000)
------------- ------------
Property and equipment, net 46,576,000 32,486,000
------------- ------------
Other assets:
Deferred acquisition costs - 310,000
Deposits and other 324,000 245,000
Employee trust 638,000 669,000
------------- ------------
Total other assets 962,000 1,224,000
------------- ------------
Total assets $ 54,868,000 $ 39,298,000
============= ============
</TABLE>
The accompanying notes are an integral part of these
financial statements.
2
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS - (continued)
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
------------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY (unaudited)
------------------------------------
<S> <C> <C>
Current liabilities:
Accounts payable and accrued expenses $ 3,759,000 $ 4,391,000
Accrued production taxes payable 394,000 367,000
Income taxes payable 181,000 -
Undistributed revenue 856,000 598,000
------------- ------------
Total current liabilities 5,190,000 5,356,000
------------- ------------
Long term debt 15,412,000 9,100,000
Other long term liabilities 270,000 527,000
Deferred income taxes 2,681,000
------------- ------------
Total long term liabilities 18,363,000 9,627,000
------------- ------------
Commitments and contingencies (Note 5)
Minority interest 153,000 -
Stockholders' equity:
Preferred stock, no par value:
10,000,000 shares authorized, none outstanding - -
Common stock, no par value:
20,000,000 shares authorized, issued, and
6,013,292 shares and 4,510,000 shares outstanding
at June 30, 2000 and December 31, 1999 respectively 31,435,000 24,806,000
Accumulated deficit (143,000) (491,000)
Currency translation adjustment (130,000) -
------------- ------------
Total stockholders' equity 31,162,000 24,315,000
------------- ------------
Total liabilities and stockholders' equity $ 54,868,000 $ 39,298,000
============= ============
</TABLE>
The accompanying notes are an integral part of these
financial statements.
3
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
Three Months Six Months
Ended Ended
June 30, 2000 June 30, 2000
------------- -------------
(unaudited) (unaudited)
<S> <C> <C>
Revenues:
Oil and gas sales $ 3,852,000 $ 7,029,000
Gas marketing and transportation 818,000 2,303,000
Other 74,000 122,000
----------- -----------
4,744,000 9,454,000
Expenses:
Oil and gas production costs 1,226,000 2,248,000
Gas marketing and transportation costs 841,000 2,318,000
Depreciation, depletion and amortization expense 1,367,000 2,517,000
General and administrative expense, net 755,000 1,306,000
Interest expense, net 265,000 460,000
----------- -----------
Total operating expenses 4,454,000 8,849,000
Minority interest in net income 4,000 7,000
----------- -----------
Income before income taxes 286,000 598,000
Income taxes:
Current 107,000 165,000
Deferred 61,000 85,000
----------- -----------
Net income $ 118,000 $ 348,000
=========== ===========
Earings per share:
Basic $ 0.02 $ 0.06
Diluted 0.02 0.06
Average number of common shares
outstanding (in thousands):
Basic 6,011 5,624
Diluted 6,054 5,662
</TABLE>
The accompanying notes are an integral part of these
financial statements.
4
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Six Months Ended June 30, 2000
(unaudited)
<TABLE>
<CAPTION>
Common Stock Currency
--------------------------------- Accumulated Translation
Shares Amount Deficit Adjustment Total
-------------- ---------------- ----------------- ------------------- ---------------
<S> <C> <C> <C> <C> <C>
Balances, December 31, 1999 4,510,000 $ 24,806,000 $ (491,000) $ - $ 24,315,000
Issuance of common stock 1,503,292 6,629,000 - - 6,629,000
Currency translation adjustment - - - (130,000) (130,000)
Net income - - 348,000 - 348,000
-------------- ---------------- ----------------- ------------------- -----------------
Balances, June 30, 2000 6,013,292 $ 31,435,000 $ (143,000) $ (130,000) $ 31,162,000
============== ================ ================= =================== =================
</TABLE>
The accompanying notes are an integral part of these
financial statements.
5
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Six Months
Ended
June 30, 2000
--------------
(unaudited)
<S> <C>
Cash flows from operating activities:
Net income $ 348,000
Adjustments to reconcile net income to net cash
provided by opertating activities:
Depreciation, depletion and amortization expense 2,517,000
Currency translation adjustment (207,000)
Minority interest 7,000
Employee stock grants 57,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable 769,000
Amounts due from broker (2,372,000)
Employee trust 561,000
Prepaid expenses and other (170,000)
Other assets (79,000)
Increase (decrease) in:
Accounts payable and accrued expenses (2,240,000)
Undistributed revenue 258,000
-------------
Net cash used in operating activities (551,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (3,833,000)
Cash acquisition of CEC Resources (144,000)
Capital expenditures for support equipment (145,000)
-------------
Net cash used in investing activities (4,122,000)
Cash flows from financing activities:
Proceeds from note payable 6,080,000
Principal payments on note payable (2,314,000)
Proceeds from issuance of common stock 55,000
-------------
Net cash provided by financing activities 3,821,000
-------------
Net decrease in cash (852,000)
Cash, beginning of period 995,000
-------------
Cash, end of period $ 143,000
=============
Supplemental cash flow information:
Cash paid for interest $ 499,000
Cash paid for taxes 11,000
The Company acquired 97.5% of the interest of CEC Resources Ltd. in the
period (Note 2).
</TABLE>
The accompanying notes are an integral part of these
financial statements.
6
<PAGE>
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Nature of Operations and Significant Accounting Policies:
--------------------------------------------------------
Carbon Energy Corporation (Carbon) was incorporated in September 1999 under
the laws of the State of Colorado to facilitate the acquisition of
Bonneville Fuels Corporation (BFC) and subsidiaries. The acquisition of BFC
closed on October 29, 1999 and was accounted for as a purchase. In February
2000, Carbon completed an offer to exchange shares of Carbon for shares of
CEC Resources, Ltd. (CEC), an Alberta, Canada company. Over 97% of the
shareholders of CEC accepted the offer for exchange. This acquisition
closed on February 17, 2000 and was also accounted for as a purchase as
further described in Note 2. Collectively, Carbon, CEC, BFC and its
subsidiaries are referred to as the Company. The Company's operations
currently consist of the acquisition, exploration, development, and
production of oil and natural gas properties located primarily in Colorado,
Kansas, New Mexico, Utah, and the Canadian provinces of Alberta and
Saskatchewan.
The financial statements included herein have been prepared in conformity
with generally accepted accounting principles. The statements are unaudited
but reflect all adjustments which, in the opinion of the management, are
necessary to fairly present the Company's financial position at June 30,
2000 and the results of operations and cash flows for the periods
presented. The results of operations for interim periods are not
necessarily indicative of results to be expected for the full year.
All amounts are presented in U.S. dollars unless otherwise stated.
Principles of Consolidation - The consolidated financial statements include
the accounts of Carbon and its subsidiaries all of which are wholly owned,
except CEC of which the Company owns approximately 97% of the equity. All
significant intercompany transactions and balances have been eliminated.
Cash Equivalents - The Company considers all highly liquid instruments with
original maturities of three months or less when purchased to be cash
equivalents.
Amounts Due From Broker - This account generally represents net cash margin
deposits held by a brokerage firm for the Company's futures accounts.
Property and Equipment - The Company follows the full cost method of
accounting for its oil and gas properties, whereby all costs incurred in
the acquisition, exploration and development of properties (including costs
of surrendered and abandoned leaseholds, delay lease rentals, dry holes and
direct overhead related to exploration and development activities) are
capitalized.
7
<PAGE>
Capitalized costs are accumulated on a country-by-country basis and are
depleted using the units of production method based on proved reserves of
oil and gas. The Company presently has two cost centers - the United
States and Canada. For purposes of the depletion calculation, oil and gas
reserves are converted to a common unit of measure on the basis of six
thousand cubic feet of gas to one barrel of oil. A reserve is provided for
the estimated future cost of site restoration, dismantlement and
abandonment activities as a component of depletion. Investments in unproved
properties are recorded at the lower of cost or fair market value and are
not depleted pending the determination of the existence of proved reserves.
Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes may not exceed the sum of
(1) the present value of future net revenue from estimated production of
proved oil and gas reserves using a 10% discount factor and unescalated oil
and gas prices as of the end of the period; plus (2) the cost of properties
not being amortized, if any; plus (3) the lower of cost or estimated fair
value of unproved properties included in the costs being amortized, if any;
less (4) related income tax effects. The costs reflected in the
accompanying financial statements do not exceed this limitation.
Proceeds from disposal of interests in oil and gas properties are accounted
for as adjustments of capitalized costs with no gain or loss recognized,
unless such adjustment would significantly alter the rate of depletion.
Buildings, transportation and other equipment are depreciated on the
straight-line method with lives ranging from three to seven years.
Employee Trust - The employee trust represents amounts which will be used
to satisfy obligations to persons who have been, or will be, terminated as
a result of the Company's acquisition of BFC (see Note 4). The current
portion of the employee trust is expected to be disbursed by June 30, 2001.
Undistributed Revenue - Represents amounts due to other owners of jointly
owned oil and gas properties for their share of revenue from the
properties.
Revenue Recognition - The Company follows the sales method of accounting
for natural gas revenues. Under this method, revenues are recognized based
on actual volumes of gas sold to purchasers. The volumes of gas sold may
differ from the volumes to which the Company is entitled based on its
interests in the properties, creating gas imbalances. Revenue is deferred
and a liability is recorded for those properties where the estimated
remaining reserves will not be sufficient to enable the underproduced owner
to recoup its entitled share through production.
The Company records sales and the related cost of sales on gas and
electricity marketing transactions using the accrual method of accounting
(i.e., the transaction is recorded when the commodity is purchased and/or
delivered).
8
<PAGE>
The Company's gas marketing contracts are generally month-to-month and
provide that the Company will sell gas to end users, which is produced from
the Company's properties and/or acquired from third parties.
Income Taxes - The Company accounts for income taxes under the liability
method which requires recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been included
in the financial statements or tax returns. Under this method, deferred tax
assets and liabilities are determined based on the difference between the
financial statement and tax basis of assets and liabilities using enacted
tax rates in effect for the year in which the differences are expected to
reverse.
Hedging Transactions - The Company periodically enters into commodity
futures and option contracts, fixed price swaps and basis swaps as hedges
of commodity prices associated with the production of oil and gas and with
the purchase of natural gas.
Pursuant to Company guidelines, the Company is to engage in these
activities only as a hedging mechanism against price volatility associated
with gas or crude oil sales in order to protect realized price levels.
Changes in the market value of futures, forwards, and swap contracts are
not recognized until the related production occurs or until the related gas
purchase takes place. Realized gains or losses from any positions which are
closed early are deferred and recorded as an asset or liability in the
accompanying balance sheet, until the related production, purchase or sale
takes place. In the event energy financial instruments do not qualify for
hedge accounting, the difference between the current market value and the
original contract value would be currently recognized in the statement of
operations. Gains and losses incurred on these contracts are included in
oil and gas revenue or in gas marketing costs in the accompanying statement
of operations.
Upon the acquisition of BFC and CEC the Company assumed open hedge
contracts that when marked to market reflected an obligation of $1,733,000
and $553,000 respectively. These obligations were recorded as a liability.
At June 30, 2000 these obligations were $1,027,000 and $399,000 for BFC and
CEC, respectively. These liabilities will decline as the contracts expire
or if the Company exits the position. The recorded liabilities related to
hedge positions that will mature within the next twelve months are included
as current liabilities. The following tables summarize BFC's and CEC's
derivative financial instrument positions on its natural gas and oil
production as of June 30, 2000:
9
<PAGE>
BFC Contracts CEC Contracts
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtu per MMBtu Year MMBtu per MMBtu
----- --------- ----------- ----- ------- -----------
2000 1,204,000 $ 2.41 2000 476,000 $ 2.32
2001 1,543,000 $ 2.36 2001 304,000 $ 2.35
--------- -------
2,747,000 780,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
----- --------- ----------- ----- ------- -----------
2000 24,000 $ 20.73 2000 18,000 $ 25.37
As of June 30, 2000, the Company would have been required to pay $5,053,000
and $1,495,000 to exit the BFC and CEC contracts, respectively.
In addition, the Company utilizes collars that establish a price between a
floor and ceiling to hedge natural gas and oil prices. As of June 30, 2000
CEC had the following natural gas collars in place:
Average Average
Floor Ceiling
Year MMBtu per MMBtu per MMBtu
-------------- ------------- ---------------- ---------------
2000 58,000 $ 3.38 $ 4.70
2001 85,000 $ 3.38 $ 4.70
As of June 30, 2000, the Company would have received $3,000 upon exiting
the contracts.
In June 1998, the Financial Accounting Board issued Statement of Financial
Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on
the balance sheet as either an asset or liability measured at its fair
value. It also requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria
are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
SFAS 133, as amended, is effective for all fiscal quarters of fiscal years
beginning after June 15, 2000. The Company has not yet quantified the
impacts of adopting SFAS 133 on its financial statements and has not
determined the timing of, or method of, adoption of SFAS 133. However, SFAS
133 could increase volatility in earnings and other comprehensive income.
10
<PAGE>
Foreign Currency Translation - The functional currency of CEC, the
Company's approximately 97 percent owned Canadian subsidiary, is the
Canadian dollar. Assets and liabilities related to the Company's Canadian
operations are generally translated at current exchange rates, and related
translation adjustments are reported as a component of shareholders'
equity. Income statement accounts are translated at the average rates
during the period. As a result of the change in the value of the Canadian
dollar relative to the US dollar, the Company reported a non cash currency
translation adjustment of ($130,000) for the six months ended June 30,
2000.
Earnings (Loss) Per Share - The Company uses the weighted average number of
shares outstanding in calculating earnings per share data. When dilutive,
options are included as share equivalents using the treasury stock method
and are included in the calculation of diluted per share data.
Accounting Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts
reported in these financial statements and the accompanying notes. The
actual results could differ from those estimates.
11
<PAGE>
2. Acquisition of CEC Resources Ltd.:
On February 17, 2000 Carbon completed the acquisition of approximately 97%
of the stock of CEC. An offer for exchange of Carbon stock for CEC stock
resulted in the issuance of 1,482,826 shares of Carbon stock to holders of
CEC stock. The acquisition was accounted for as a purchase.
The adjusted purchase price of $13,811,000 was comprised of the following:
Current liabilities $ 1,041,000
Open hedges 553,000
Deferred income taxes 2,645,000
Long term debt 2,599,000
Professional fees 455,000
Carbon common stock exchanged 6,518,000
------------
Total purchase price $ 13,811,000
============
The following unaudited pro forma information presents a summary of the
consolidated results of operations as if the acquisition had occurred at
the beginning of the period presented. Because Carbon was not in existence
at June 30, 1999, the pro forma information presented is for the six month
period ending June 30, 2000 only.
Six Months
Ended
June 30, 2000
-------------
(unaudited)
Total revenue $ 10,104,000
Net income $ 441,000
Earnings per share:
Basic $ 0.08
Diluted $ 0.08
These unaudited pro forma results have been prepared for comparative
purposes only and do not purport to be indicative of results of operations
that actually would have resulted had the combination occurred at the
beginning of the period presented, or future results of operations of the
consolidated entities.
12
<PAGE>
3. Long term Debt:
Debt consisted of the following at June 30, 2000:
U.S. facility $12,800,000
Canadian facility 2,612,000
-----------
$15,412,000
Current portion -
-----------
Long term $15,412,000
===========
U.S. Facility
The Company has an oil and gas reserve-based line-of-credit with U.S. Bank,
N.A. The facility had a borrowing base of $15.9 million with outstanding
borrowings of $12.8 million at June 30, 2000. Letters of credit totaling
$1.5 million were issued at June 30, 2000 which reduces the amount
available for borrowings. The facility is secured by certain U.S. oil and
gas properties of the Company and is scheduled to convert to a term note on
July 1, 2001. This term is scheduled to have a maturity date of either the
economic half life of the Company's remaining U.S. based reserves on the
date of conversion or July 1, 2006, whichever is earlier. The facility
bears interest at a rate equal to LIBOR plus 1.75% or U.S. Bank, N.A.
Prime, depending on the option of the Company. The rate was approximately
8.4% at June 30, 2000. The borrowing base is based upon the lender's
evaluation of the Company's proved oil and gas reserves, generally
determined semi-annually.
The credit agreement contains various covenants which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is
also required to maintain certain financial ratios.
Credit Facility
The Company also has an accounts receivable-based credit facility which
includes a revolving line-of-credit with U.S. Bank, N.A. which provides for
borrowings and letters of credit up to $500,000. There were no outstanding
borrowings or letters of credit under this facility at June 30, 2000. This
facility bears interest at U.S. Bank, N.A. Prime (9.5% at June 30, 2000).
This facility is collateralized by certain trade receivables of the Company
and has a maturity date of July 1, 2001.
Canadian Facility
The facility with the Canadian Imperial Bank of Commerce (CIBC), has a
borrowing base of approximately $4.5 million with outstanding borrowings of
$2.6 million at June 30, 2000. The Canadian facility is secured by the
Canadian oil and gas properties of the Company. The revolving phase of the
Canadian facility will expire on December 31, 2000. If the revolving
commitment is not renewed, the loan will be converted into a term loan and
will be reduced by way of consecutive monthly payments over a period not to
exceed 36 months. The Canadian facility bears interest at the CIBC Prime
rate plus 3/4%. The rate was approximately 8.25% at June 30, 2000.
13
<PAGE>
The Canadian facility contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness,
sell properties, or merge with another entity.
The agreement with CIBC also contains a $3.0 million swap facility that
provides at the Company's request and subject to market availability,
interest rate swaps and forward rate agreements to provide fixed or
floating rate funding for part or all of the production loan, commodity
swaps covering a portion of the Company's oil and gas production, forward
exchange contracts and firm gas purchase and sales transactions.
4. Salary Continuation Plan:
In 1999, BFC established a Salary Continuation Plan (the Plan). The Plan
provides for continuation of salary and health, dental, disability, and
life insurance benefits for a certain period of time based upon employment
contracts or length of service, if the employee is terminated within two
years following the effective date of BFC's acquisition by Carbon. The Plan
was initially funded with a deposit of $1,546,000 into an employee trust
account. Distributions through June 30, 2000 have been $696,000 for
employees who were terminated or had their employment contracts terminated.
Subsequent to June 30, 2000, additional distributions in the amount of
$348,000 will be made to these employees within the next 12 months and the
liabilities related to these disbursements are included in current
liabilities. The funds to meet this obligation is included in current
assets. The liabilities related to these employee terminations were
recorded in 1999.
The employee trust account is restricted from disbursing funds except for
the payment of benefits or upon the insolvency of the Company. Trustee fees
were minimal for the period ended June 30, 2000. Any remaining amounts in
the trust will revert to the Company upon expiration of the trust.
14
<PAGE>
5. Commitments and Contingencies:
Office Lease - The Company entered into various lease agreements, which
provides for total minimum rental commitments as follows:
U.S. Canada
--------- --------
2000 - Remainder of year $ 97,000 $ 38,000
2001 197,000 86,000
2002 203,000 86,000
2003 208,000 79,000
2004 212,000 -
---------- ---------
$ 917,000 $289,000
========== =========
6. Stock Options and Award Plans:
In 1999, the Company adopted a stock option plan. All salaried employees of
the Company and its subsidiaries are eligible to receive both incentive
stock options and nonqualified stock options. Directors and consultants who
are not employees of the Company or its subsidiaries are eligible to
receive non-qualified stock options, but not incentive stock options under
the plan. The option price for the incentive stock options granted under
the plan are not to be less than 100% of the fair market value of the
shares subject to the option. The option price for the nonqualified stock
options granted under the plan are not to be less than 85% of the fair
market value of the shares subject to the options. The aggregate number of
shares of common stock, which may be issued under options granted pursuant
to the plan, may not exceed 700,000 shares. A total of 264,500 options
outstanding under the CEC Incentive Share Option Plan were exchanged for
Carbon options upon the completion of the offer to exchange shares of
Carbon for shares of CEC. An additional 197,000 options were also granted
during the six months ended June 30, 2000.
The specific terms of grant and exercise is determined by the Company's
Board of Directors unless and until such time as the Board of Directors
delegates the administration of the plan to a committee. The options vest
over a three year period and expire ten years from the date of grant.
In 1999, the Company adopted a restricted stock plan for selected
employees, directors and consultants of the Company and its subsidiaries.
The aggregate number of shares of common stock which may be issued under
the plan may not exceed 300,000. The shares vest ratably over 36 months.
The Company recognized compensation expense of $30,000 and $57,000 for the
second quarter and first six months of 2000, respectively. For financial
reporting purposes, the Company presents only vested shares as outstanding.
15
<PAGE>
7. Income Taxes:
The income tax expense is different from amounts computed by applying the
statutory Federal income tax rate for the following reasons:
Six Months
Ended
June 30, 2000
-------------
(in thousands)
Tax expense at 35% of income before income
taxes $ 211
Change in the valuation allowance against
deferral tax asset 2
Tax expense of higher effective rate on
Canadian income 52
Canadian resource allowance (160)
Canadian Crown payments (net of Alberta
Royalty Tax Credit) not deductible
for tax purposes 129
Other 16
-------
$ 250
=======
The net deferred tax liability by geographic area is comprised of the
following:
<TABLE>
<CAPTION>
June 30, 2000
----------------------------------------
United States Canada Total
-------------- ------ -----
(in thousands)
<S> <C> <C> <C>
Federal net operating loss carryforward $ (960) $ - $ (960)
Property and equipment 850 2,712 3,562
Other (18) (31) (49)
Valuation allowance 128 - 128
--------- ---------- ---------
Net deferred tax liability $ - $ 2,681 $ 2,681
========= ========== =========
</TABLE>
As of June 30, 2000, the Company had a net operating loss carryforward for
federal income tax purpose of $2,741,000 which expires in 2020.
16
<PAGE>
8. Properties Subject to Tax Credit Agreement:
During 1995, BFC entered into an agreement to sell 99% of its interest in
14 coal gas wells located in New Mexico that qualified for IRC section 29
tax credits. Under the terms of the agreement BFC is to receive 99% of the
net cash flow on the properties until certain cumulative production levels
have been reached, at which time the purchaser will receive 100% of the net
cash flow until a subsequent production level is reached. Upon reaching the
second target, 100% of the cash flows will revert to BFC for substantially
the remaining life of the properties. The first production level was
reached in January 2000. Due to these contractual agreements, BFC will not
be entitled to sales proceeds or be obligated for the cost of operations on
these properties until an additional 235,000 Mcf has been produced. The
Company estimates this will take approximately fifteen months. During this
15 month period, the Company will still be entitled to receive tax credit
benefits estimated to be $150,000.
17
<PAGE>
9. Business and Geographical Segments:
Segment information has been prepared in accordance with Statement of
Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information" (SFAS No. 131). Carbon has two
reportable and geographic segments: BFC and CEC, representing oil and gas
operations in the United States and Canada, respectively. The segments are
strategic business units which operate in unique geographic locations. The
segment data presented below was prepared on the same basis as Carbon's
consolidated financial statements.
<TABLE>
<CAPTION>
Three Months Three Months
Ended Ended
June 30, 2000 June 30, 2000
United Consolidated
States Canada Totals
----------------- ----------------- -----------------
<S> <C> <C> <C>
Oil and gas sales $ 2,249,000 $ 1,603,000 $ 3,852,000
Gas marketing, transportation, and other 892,000 - 892,000
----------------- ----------------- -----------------
Total revenues 3,141,000 1,603,000 4,744,000
Oil and gas production costs 790,000 436,000 1,226,000
Gas marketing, transportation, and other 841,000 - 841,000
Depreciation and depletion 905,000 462,000 1,367,000
General and administrative, net 433,000 322,000 755,000
Interest expense, net 210,000 55,000 265,000
----------------- ----------------- -----------------
Total operating expenses 3,179,000 1,275,000 4,454,000
Minority interest in net income - 4,000 4,000
Income tax - 168,000 168,000
----------------- ----------------- -----------------
Net income $ (38,000) $ 156,000 $ 118,000
================= ================= =================
----------------- ----------------- -----------------
Total assets $ 40,599,000 $ 14,269,000 $ 54,868,000
================= ================= =================
</TABLE>
18
<PAGE>
<TABLE>
<CAPTION>
For the period
from
Six Months February 18
Ended through
June 30, 2000 June 30, 2000
United Consolidated
States Canada Totals
----------------- ----------------- -----------------
<S> <C> <C> <C>
Oil and gas sales $ 4,679,000 $ 2,350,000 $ 7,029,000
Gas marketing, transportation, and other 2,425,000 - 2,425,000
----------------- ----------------- -----------------
Total revenues 7,104,000 2,350,000 9,454,000
Oil and gas production costs 1,616,000 632,000 2,248,000
Gas marketing, transportation, and other 2,318,000 - 2,318,000
Depreciation and depletion 1,850,000 667,000 2,517,000
General and administrative, net 871,000 435,000 1,306,000
Interest expense, net 382,000 78,000 460,000
----------------- ----------------- -----------------
Total operating expenses 7,037,000 1,812,000 8,849,000
Minority interest in net income - 7,000 7,000
Income tax - 250,000 250,000
----------------- ----------------- -----------------
Net income $ 67,000 $ 281,000 $ 348,000
================= ================= =================
----------------- ----------------- -----------------
Total assets $ 40,599,000 $ 14,269,000 $ 54,868,000
================= ================= =================
</TABLE>
19
<PAGE>
The following unaudited financial statements and accompanying notes are for
Bonneville Fuels Corporation, the predecessor company to Carbon Energy
Corporation.
BONNEVILLE FUELS CORPORATION
STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Three Months Six Months
Ended Ended
June 30, 1999 June 30, 1999
------------- -------------
(unaudited) (unaudited)
<S> <C> <C>
Revenues:
Oil and gas sales $ 2,653,000 $ 4,560,000
Gas marketing and transportation 2,433,000 9,950,000
Other 111,000 218,000
------------ --------------
5,197,000 14,728,000
------------ --------------
Expenses:
Oil and gas production costs 1,010,000 1,679,000
Gas marketing and transportation costs 2,359,000 9,742,000
Depreciation, depletion and amortization expense 726,000 1,213,000
General and administrative expense, net 356,000 792,000
Exploration expense 395,000 639,000
Impairment expense 60,000 60,000
Interest expense, net 91,000 203,000
------------ --------------
Total operating expenses 4,997,000 14,328,000
------------ --------------
Income before income taxes 200,000 400,000
Income taxes
Current 0 0
Deferred 0 0
------------ --------------
0 0
------------ --------------
Net income $ 200,000 $ 400,000
============ ==============
</TABLE>
The accompanying notes are an integral part of these
financial statements.
20
<PAGE>
BONNEVILLE FUELS CORPORATION
STATEMENT OF CASH FLOW
<TABLE>
<CAPTION>
Six Months
ended
June 30, 1999
-------------
(unaudited)
<S> <C>
Cash flows from operating activities
Net income (loss) $ 400,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 1,264,000
Amortization of loan costs 10,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable, trade 2,490,000
Amounts due from broker (674,000)
Prepaid expenses and other 83,000
Increase (decrease) in:
Accounts payable and accrued expenses (5,504,000)
Undistributed revenue 403,000
-----------
Net cash used in operating activities (1,528,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (3,544,000)
Other net property and equipment (59,000)
Other assets (16,000)
-----------
Net cash used in investing activities (3,619,000)
Cash flows from financing activities:
Proceeds from note payable 9,099,000
Principal payments on note payable (6,250,000)
-----------
Net cash provided by (used in) financing activities 2,849,000
Net increase (decrease) in cash and equivalents (2,298,000)
Cash, beginning of year 2,742,000
-----------
Cash, end of year $ 444,000
===========
Supplemental disclosures of cash flow information:
Cash paid for interest $ 300,000
===========
</TABLE>
The accompanying notes are an integral part of these
financial statements.
21
<PAGE>
BONNEVILLE FUELS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Nature of Operations and Significant Accounting Policies:
Nature of Operation - Bonneville Fuels Corporation (BFC), a wholly owned
subsidiary of Bonneville Pacific Corporation (BPC), was incorporated in the
State of Colorado in April 1987 and began doing business in June 1987. The
Company owns four subsidiaries, Bonneville Fuels Marketing Corporation
(BFMC), Bonneville Fuels Management Corporation (BFM Corp.), Bonneville
Fuels Operating Corporation (BFO), and Colorado Gathering Corporation
(CGC). Collectively, these entities are referred to as the Company. The
Company's principal operations include exploration for and production of
oil and gas reserves, marketing of natural gas, and gathering of natural
gas. The Company from time to time also purchases and resells electricity.
Principles of Consolidation - The consolidated financial statements include
the accounts of BFC and its four wholly owned subsidiaries. All significant
intercompany transactions and balances have been eliminated in the
accompanying consolidated financial statements.
Cash Equivalents - The Company considers all highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Gas Marketing - the Company's marketing contracts are generally
month-to-month or up to eighteen months, and provide that the Company will
sell gas to end users which is produced from the Company's properties and
acquired from third parties.
Amounts Due from Broker - This account generally represents net cash margin
deposits held by a brokerage firm for the Company's trading accounts.
Oil and Gas Producing Activities - The Company follows the "successful
efforts" method of accounting for its oil and gas properties, all of which
are located in the continental United States. Under this method of
accounting, all property acquisition costs and costs of exploratory and
development wells are capitalized when incurred, pending determination of
whether the well has found proved reserves. If an exploratory well has not
found proved reserves, the costs of drilling the well are charged to
expense. The costs of development wells are capitalized whether productive
or nonproductive.
Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Depreciation and depletion
of capitalized costs for producing oil and gas properties is computed using
the units-of-production method based upon proved reserves for each field.
In 1997, the Company began to accrue for future plugging, abandonment, and
remediation using the negative salvage value method whereby costs are
expensed through additional depletion expense over the remaining economic
lives of the wells. Management's estimate of the total future costs to
plug, abandon, and remediate the Company's share of all existing wells,
including those currently shut in is approximately $3,500,000, net of
salvage values. The total amount expensed for this liability was $100,000
and $-0-, for the periods ended June 30, 1999 and 1998, respectively.
22
<PAGE>
The Company follows Statement of Financial Accounting Standards (SFAS) No.
121, Accounting for Impairment of Long-Lived Assets. This statement limits
net capitalized costs of proved and unproved oil and gas properties to the
aggregate undiscounted future net revenues related to each field. If the
net capitalized costs exceed the limitation, impairment is provided to
reduce the carrying value of the properties in the field to estimated
actual value.
Gains and losses are generally recognized upon the sale of interests in
proved oil and gas properties based on the portion of the property sold.
For sales of partial interests in unproved properties, the Company treats
the proceeds as a recovery of costs with no gain recognized until all costs
have been recovered.
Energy Marketing Arrangements - In 1998, BFC entered into an agreement to
manage certain natural gas contracts of an unrelated entity. For some
contracts, BFC takes title to the gas purchased to service these contracts
prior to the sale under the contracts. For these contracts BFC records all
revenues, expenses, receivables, and payables associated with the
contracts. In contracts where title is not taken, BFC only records the
margin associated with the transaction. This agreement was terminated at
the end of April 1999.
Other Property and Equipment - Depreciation of other property and equipment
is calculated using the straight-line method over the estimated useful
lives (ranging from 3 to 25 years) of the respective assets. The cost of
normal maintenance and repairs is charged to operating expenses as
incurred. Material expenditures, which increase the life of an asset, are
capitalized and depreciated over the estimated remaining useful life of the
asset. The cost of properties sold, or otherwise disposed of, and the
related accumulated depreciation or amortization is removed from the
accounts, and any gains or losses are reflected in current operations.
Deferred Loan Costs - Costs associated with the Company's note payable have
been deferred and are being amortized using the effective interest method
over the original term of the note.
Gas Balancing - The Company uses the sales method of accounting for amounts
received from the natural gas sales resulting from production credited to
the Company in excess of its revenue interest share. Under this method, all
proceeds from the production credited to the Company are recorded as
revenue until such time as the Company has produced its share of related
estimated remaining reserves. Thereafter, additional amounts received are
recorded as a liability.
Income Taxes - The Company accounts for income taxes under the liability
method, which requires recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been included
in the financial statements or tax returns. Under this method, deferred tax
assets and liabilities are determined based on the difference between the
financial statement and tax bases of assets and liabilities using enacted
tax rates in effect for the year in which the differences are expected to
reverse. BPC includes the Company's operations in its consolidated tax
return. Income taxes are allocated by BPC as if the Company was a separate
taxpayer.
23
<PAGE>
Accounting for Hedged Transactions - The Company periodically enters into
futures, forwards, and swap contracts as hedges of commodity prices
associated with the production of oil and gas and with the purchase and
sale of natural gas in order to mitigate the risk of market price
fluctuations. Changes in the market value of futures, forwards, and swap
contracts are not recognized until the related production occurs or until
the related gas purchase or sale takes place. Realized losses from any
positions, which were closed early, are deferred and recorded as an asset
or liability in the accompanying balance sheet, until the related
production, purchase or sale takes place. Gains and losses incurred on
these contracts are included in oil and gas revenue or in gas marketing
costs in the accompanying statements of operations.
Accounting Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles required
management to make estimates and assumptions that affect the amounts
reported in these financial statements and the accompanying notes. The
actual results could differ from those estimates.
Reclassifications - Certain reclassifications have been made to conform the
1999 financial statements to the presentation in 1998. These
reclassifications had no effect on net income.
2. Long -Term Debt:
The Company has an asset-based line-of-credit with a bank which provides
for borrowing up to the borrowing base (as defined). The borrowing base was
$16,900,000 at June 30, 1999. Outstanding borrowings were $8,400,000, with
interest at a variable rate that approximated 6.7% at June 30, 1999. The
Company has issued letters of credit totaling $2,500,000, which further
reduces the amount available for borrowing the base. This facility is
collateralized by certain oil and gas properties of the Company and is
scheduled to convert to a term note on July 1, 2001. This term loan is
scheduled to have a maturity of either the economic half life of the
Company's remaining reserves on the date of conversion, or July 1, 2006,
whichever is earlier. The borrowing base is based upon the lender's
evaluation of BFC's proved oil and gas reserves, generally determined
semi-annually. The future minimum principal payments under the term note
will be dependent upon the bank's evaluation of the Company's reserves at
that time.
The Company also has an accounts receivable-based credit facility which
includes a revolving line-of-credit with the bank which provides for
borrowings up to $1,500,000. Outstanding borrowings under this facility at
June 30, 1999, amounted to $300,000. This facility bears interest at prime
(7.75% at June 30, 1999). This facility is collateralized by certain trade
receivables of BFC and has a maturity date of July 1, 2001.
24
<PAGE>
The credit agreement contains various covenants, which prohibit or limit
the subsidiary's ability to pay dividends, purchase treasury shares, incur
indebtedness, repay debt to the Parent, sell properties or merge with
another entity. Additionally, the Company is required to maintain certain
financial ratios.
3. Commitments:
Office Lease - the Company leases office space under a noncancellable
operation lease. Total rental expense was approximately $73,000 and $57,000
for the periods ended June 30, 1999 and 1998, respectively. Beginning in
1998, the Company has a new lease agreement, which provides for total
minimum rental commitments of:
1999 $ 73,000
2000 $153,000
2001 $159,000
2002 $166,000
--------
$551,000
========
4. Income Taxes:
The components of the net deferred tax assets are as follows:
December 31,
1998
-------------
Excess of tax basis over book
basis of oil and gas properties $ 1,873,000
Deferred tax assets $ 1,873,000
Less valuation allowance $(1,873,000)
------------
Net deferred tax assets $ -
============
The effective tax rate of the Company differed from the Federal statutory
rate primarily due to changes in the valuation allowance on the deferred
tax assets.
25
<PAGE>
5. Concentrations of Credit Risk and Price Risk Management:
Concentrations of Credit Risk - Substantially all of the Company's accounts
receivable at June 30, 1999, result from crude oil and natural gas sales
and/or joint interest billings to companies in the oil and gas industry.
This concentration of customers and joint interest owners may impact the
Company's overall credit risk, either positively or negatively, since these
entities may be similarly affected by changes in economic or other
conditions. In determining whether or not to require collateral from a
customer or joint interest owner, the Company analyzes the entity's net
worth, cash flows, earnings, and credit ratings. Receivables are generally
not collateralized. Historical credit losses incurred on trade receivables
by the Company have been insignificant.
The Company's revenues are predominantly derived from the sale of natural
gas and management estimates that over 85% of the value of the Company's
properties are derived from natural gas reserves.
Energy Financial Instruments - BFC uses energy financial instruments and
long-term user contracts to minimize its risk of price changes in the spot
and fixed price natural gas and crude oil markets. Energy risk management
products used include commodity futures and options contracts, fixed-price
swaps, and basis swaps. Pursuant to Company guidelines BFC is to engage in
these activities only as a hedging mechanism against price volatility
associated with pre-existing or anticipated gas or crude oil sales in order
to protect profit margins. As of June 30, 1999, BFC has financial and
physical contracts which hedge 5.1 bcf (billion cubic feet) of production
through December 2001.
The difference between the current market value of the hedging contracts
and the original market value of the hedging contracts was an unfavorable
$894,000 as of June 30, 1999. These amounts are not reflected in the
accompanying financial statements. In the event energy financial
instruments do not qualify for hedge accounting, the difference between the
current market value and the original contract value would be currently
recognized in the statement of operations. In the event that the energy
financial instruments are terminated prior to the delivery of the item
being hedged, the gains and losses at the time of the termination are
deferred until the period of physical delivery. Such deferrals were
immaterial in all periods presented.
6. Financial Instruments:
SFAS Nos. 107 and 127 require certain entities to disclose the fair value
of certain financial instruments in their financial statements.
Accordingly, management's best estimate is that the carrying amount of
cash, receivables, notes payable, accounts payable, undistributed revenue,
and accrued expenses approximates fair value of these instruments.
26
<PAGE>
7. Management Retention Bonuses and Employment Contracts:
The Company has accrued compensation as of June 30, 1999 of $164,000 in
accordance with a management retention program approved by the bankruptcy
court. The Company has also entered into certain employment contracts with
key employees that provide for certain benefits to the employees upon
termination without cause.
8. Subsequent Event:
During the first quarter, BPC engaged a financial advisor to pursue various
strategic opportunities. BPC is considering all options including the
continued operation of all its subsidiaries or the sale of the entire
Company or any part thereof. No adjustment to the financial statements has
been made.
27
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
On February 17, 2000 Carbon Energy (Carbon) completed its offer to exchange
shares of Carbon stock on a share for share basis for shares of CEC Resources
Ltd. (CEC) stock, resulting in over 97% of CEC's shareholders exchanging CEC
shares for Carbon shares. For the purpose of the management discussion and
analysis of the results of operations, the three months ended June 30, 2000 and
the period February 18, 2000 through June 30, 2000 are compared to CEC's
activity for the same periods in 1999. The discussions of the U.S. operations
compare the results of Carbon's 100% owned subsidiary Bonneville Fuels
Corporation (BFC) for the three and six month periods ended June 30, 1999 and
2000.
Three months ended June 30, 2000, compared to three months ended June 30, 1999
(second quarter).
<TABLE>
<CAPTION>
United States Canada
Three Months Ended Three Months Ended
June 30, June 30,
----------------------------------------- -----------------------------------------
2000 1999 Change 2000 1999 Change
------------- ------------- ------- ------------ ------------- -------
(Dollars in thousands, except (Dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Natural gas $ 1,843 $ 2,352 -22% $ 1,255 $ 802 56%
Oil and Liquids 406 301 35% 348 228 53%
------------- ------------- ------------- -------------
Total 2,249 2,653 -15% 1,603 1,030 56%
Sales volumes:
Natural gas (MMcf) 771 1,232 -37% 478 442 8%
Oil and Liquids (Bbl) 17,245 18,836 -8% 16,215 17,013 -5%
Average price received:
Natural gas (Mcf) $ 2.39 $ 1.91 25% $ 2.62 $ 1.81 45%
Oil and Liquids (Bbl) 23.53 15.97 47% 21.49 13.38 61%
Direct lifting costs $ 339 $ 545 -38% $ 209 $ 122 71%
Average direct lifting costs/Mcfe 0.39 0.41 -5% 0.36 0.22 64%
Other production costs 451 465 -3% 227 68 234%
Gas marketing, transportation and other
revenue $ 892 $ 2,544 -65% $ - $ - 0%
Gas and electrical marketing expense 841 2,359 -64% - - 0%
General and administrative, net 433 356 22% 322 406 -21%
Depreciation, depletion and amortization 905 726 25% 462 412 12%
Exploration and impairment expense - 455 -100% - - 0%
Interest expense, net 210 91 131% 55 29 89%
</TABLE>
Revenues for oil, and gas sales of BFC for the second quarter of 2000 were $2.2
million, a 15% decrease from the prior year period. The decrease was due
primarily to production declines in the Permian basin on new wells connected in
1998 and 1999, to properties located in the San Juan basin subject to a tax
credit agreement where the Company was not entitled to sales proceeds from these
properties for the three months ended June 30, 2000 (see "Financial Condition
and Capital Resources"), and to natural production declines in all basins.
28
<PAGE>
Revenues for oil, liquids and gas sales of CEC for the second quarter of 2000
were $1.6 million, a 56% increase from the prior year period. The increase was
due primarily to an increase in natural gas production and higher oil, liquids
and gas prices.
BFC's average production for the second quarter of 2000 was 190 barrels of oil
per day and 8.5 million cubic feet (MMcf) of gas per day, a decrease of 35% on a
Mcf equivalent (Mcfe) basis where one barrel of oil is equal to six Mcf of gas.
The decrease was primarily attributed to production declines in the Permian
basin on new wells connected in 1998 and 1999, to properties located in the San
Juan basin subject to a tax credit agreement where the Company was not entitled
to sales proceeds from these properties for the three months ended June 30, 2000
(see "Financial Condition and Capital Resources"), and to natural production
declines in all basins that average approximately 8% annually. During the
quarter, 4 gross wells and 3.1 net wells were drilled compared to 3 gross wells
and 2.5 net wells drilled during the second quarter of 1999. Subsequent to the
second quarter of 2000, the Company connected six gas wells in the Uinta basin
and completed two workovers and one new well in the Permian basin. The Company
estimates that these new projects will increase BFC's average production by
approximately 2.5 MMcfe per day
CEC's average production for the second quarter 2000 was 178 barrels of oil and
liquids per day and 5.3 MMcf of gas per day, an increase of 6% on an Mcfe basis
from the same period in 1999. The increase was primarily attributed to
acquisitions, successful well workovers and optimization of the Company's
compressor facilities. CEC did not have any drilling activity for the second
quarter 2000 or the similar period in 1999.
Average oil prices received by BFC increased 47% from $15.97 per barrel in the
second quarter of 1999 to $23.53 in the second quarter of 2000. The average oil
price includes hedge losses of $59,000 for the second quarter of 2000. There was
no oil hedge activity for the similar period in 1999. Average natural gas prices
received by BFC increased 25% from $1.91 per Mcf for the second quarter of 1999
to $2.39 per Mcf in 2000. The average natural gas price includes hedge losses of
$541,000 for the second quarter of 2000 and hedge gains of $36,000 for the
similar period in 1999.
Average oil and liquids prices received by CEC increased 61% from $13.38 per
barrel for the second quarter of 1999 to $21.49 for the same period in 2000. The
average price includes hedge losses of $35,000 for the second quarter of 2000.
There was no oil hedge activity for the similar period in 1999. Average natural
gas prices received by CEC increased 45% from $1.81 per Mcf for the second
quarter of 1999 to $2.62 for the same period in 2000. The average natural gas
price includes hedge losses of $168,000 for the second quarter of 2000 compared
to a $1,000 loss for the same period in 1999.
Direct lifting costs incurred by BFC were $339,000 or $.39 per Mcfe for the
second quarter of 2000 compared to $545,000 or $.41 per Mcfe for 1999. The
decrease was related to workover expenses incurred during the second quarter of
1999 and prior period charges for gas processing fees billed to BFC in 1999.
Other production costs incurred by BFC consisting of production taxes and
overhead, were $451,000 for the second quarter of 2000 compared to $465,000 for
the similar period in 1999. The decrease was attributable to lower severance
taxes due to reduced production, partially offset by an increase in oil and gas
prices.
29
<PAGE>
Direct lifting costs incurred by CEC were $209,000 or $.36 per Mcfe for the
second quarter of 2000 compared to $122,000 or $.22 per Mcfe for 1999. The
increase was primarily due to credits received by the Company in 1999 for gas
processing fees related to prior periods.
Other production costs incurred by CEC consisting of net crown and other royalty
expense were $227,000 for the second quarter of 2000 compared to $68,000 for the
similar period in 1999. The increase was attributable to a rise in net crown
royalties due to higher oil and gas prices.
Exploration and impairment expense was recorded by the Company's predecessor,
BFC, under the successful efforts method of accounting and consists primarily of
unsuccessful drilling and geological and geophysical costs. Effective as of the
date of the acquisition of BFC, Carbon utilizes the full cost method of
accounting. Under this method, all exploration costs associated with continuing
efforts to acquire or review prospects and outside geological and seismic
consulting work are capitalized.
General and administrative expenses incurred by BFC, net of third party
reimbursements for the second quarter of 2000 were $433,000 compared to $356,000
for the same period in 1999. The increase was due to costs related to a change
in the location of administrative offices of the Company and reporting, printing
and regulatory filings relating to the Company being a publicly held company in
2000.
General and administrative expenses incurred by CEC for second quarter 2000 were
$322,000, a $84,000 or 21% decrease from the same period in 1999. The decrease
was primarily due to lower professional fees, contracted services and allocated
overhead for U.S. corporate services.
Interest and other expenses incurred by BFC, rose to $210,000 in the second
quarter of 2000, a $119,000 or 131% increase from the prior year period.
Interest expense increased as a result of higher average debt balances on the
Company's debt. The average interest rate for the second quarter of 2000 was
8.1% compared to 6.7% for the similar period in 1999.
Interest and other expenses incurred by CEC, rose to $55,000 for the second
quarter 2000, a $26,000 increase from the similar period in 1999. Interest
expense increased as a result of higher average debt balances on the Company's
debt.
Depreciation, depletion and amortization (DD&A) of oil and gas assets are
determined based upon the units of production method. This expense is typically
dependent upon historical capitalized costs incurred to find, develop and
recover oil and gas reserves; however, the Company's current DD&A rate is
determined primarily by the purchase price the Company allocated to oil and gas
properties in connection with its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
30
<PAGE>
DD&A expense for BFC for the second quarter of 2000 was $905,000 an increase of
$179,000 or 25% from the 1999 level. Depletion expense was $1.03 per Mcfe for
the second quarter of 2000 compared to $.54 per Mcfe in 1999. The increase was
primarily driven by the increased property costs recorded as a result of the
acquisition of BFC.
DD&A expense for CEC for the second quarter 2000 was $462,000 an increase of
$50,000 or 12% from the 1999 level. The increase resulted primarily from
increased production. Depletion expense was $.80 per Mcfe for the second quarter
of 2000 compared to $.76 per Mcfe for the same period in 1999.
31
<PAGE>
Results of Operations
Six months ended June 30, 2000, compared to six months ended June 30, 2000 for
BFC and the period February 18 through June 30, 2000 compared to the period
February 18 through June 30, 1999 for CEC.
<TABLE>
<CAPTION>
Canada
United States For the Period from
Six Months Ended February 18 through
June 30, June 30,
----------------------------------------- -----------------------------------------
2000 1999 Change 2000 1999 Change
------------- ------------- ------- ------------ ------------- -------
(Dollars in thousands, except (Dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Natural gas $ 3,869 $ 4,110 -6% $ 1,808 $ 1,049 72%
Oil and Liquids 810 450 80% 542 301 80%
------------- ------------- ------------- -------------
Total 4,679 4,560 3% 2,350 1,350 74%
Sales volumes:
Natural gas (MMcf) 1,616 2,121 -24% 704 586 20%
Oil and Liquids (Bbl) 33,497 33,684 -1% 23,921 24,295 -2%
Average price received:
Natural gas (Mcf) $ 2.39 $ 1.94 24% $ 2.57 $ 1.79 43%
Oil and Liquids (Bbl) 24.18 13.36 81% 22.66 12.36 83%
Direct lifting costs $ 742 $ 857 -13% $ 317 $ 187 70%
Average direct lifting costs/Mcfe 0.41 0.37 11% 0.37 0.26 42%
Other production costs 874 822 6% 315 94 235%
Gas marketing, transportation and other
revenue $ 2,425 $ 10,168 -76% $ - $ - 0%
Gas and electrical marketing expense 2,318 9,742 -76% - - 0%
General and administrative, net 871 792 10% 435 573 -24%
Depreciation, depletion and amortization 1,850 1,213 53% 667 550 21%
Exploration and impairment expense - 699 -100% - - 0%
Interest expense, net 382 203 88% 78 33 135%
</TABLE>
Revenues for oil and gas sales of BFC for the first six months of 2000 were $4.7
million, a 3% increase from the prior year period. The increase was due
primarily to increased oil and gas prices partially offset by production
declines in the Permian basin on new wells connected in 1998 and 1999, to
properties located in the San Juan basin subject to a tax credit agreement where
the Company was not entitled to sales proceeds from these properties for the six
months ended June 30, 2000 (see "Financial Condition and Capital Resources"),
and to natural declines in all basins.
Revenues for oil, liquids and gas sales of CEC for the period February 18
through June 30, 2000 were $2.4 million, a 74% increase from the prior year
period. The increase was due primarily to increased natural gas production and
higher oil, liquids and gas prices.
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BFC's average production for the first six months of 2000 was 184 barrels of oil
per day and 8.9 million cubic feet (MMcf) of gas per day, a decrease of 22% on a
Mcf equivalent (Mcfe) basis where one barrel of oil is equal to six Mcf of gas.
The decrease was primarily attributed to production declines in the Permian
basin on new wells connected in 1998 and 1999, to properties located in the San
Juan basis subject to a tax credit agreement where the Company was not entitled
to sales proceeds from these properties for the six months ended June 30, 2000
(see "Financial Condition and Capital Resources"), and to natural declines in
all basins that average approximately 8% annually. During the six months ended
June 30, 2000, 8 gross wells and 5.7 net wells were drilled compared to 5 gross
wells and 3.4 net wells drilled during the same period in 1999. Subsequent to
the first six months of 2000, the Company connected six gas wells in the Uinta
basin and completed two workovers and one new well in the Permian basin. The
Company estimates that these new projects will increase BFC's average production
by approximately 2.5 MMcfe per day
CEC's average production for the period February 18 through June 30, 2000 was
177 barrels of oil and liquids per day and 5.2 MMcf of gas per day, an increase
of 16% on an Mcfe basis from the same period in 1999. The increase was primarily
attributed to acquisitions, successful well workovers and optimization of the
Company's compressor facilities. CEC did not have any drilling activity for the
period February 18 through June 30, 1999 and 2000.
Average oil prices received by BFC increased 81% from $13.36 per barrel in the
first six months of 1999 to $24.18 in the first six months of 2000. The average
oil price includes hedge losses of $102,000 for the first six months of 2000.
There was no oil hedge activity for the similar period in 1999. Average natural
gas prices received by BFC increased 24% from $1.94 per Mcf for the first six
months of 1999 to $2.39 per Mcf in 2000. The average natural gas price includes
hedge losses of $402,000 for the first six months of 2000 and hedge gains of
$342,000 for the similar period in 1999.
Average oil and liquids prices received by CEC increased 83% from $12.36 per
barrel for the period from February 18 through June 30, 1999 to $22.66 for the
same period in 2000. The average price includes hedge losses of $35,000 for the
period February 18 through June 30, 2000. There was no oil hedge activity for
the similar period in 1999. Average natural gas prices received by CEC increased
43% from $1.79 per Mcf for the period from February 18 through June 30, 1999 to
$2.57 for the same period in 2000. The average natural gas price includes hedge
loss of $158,000 for the period February 18 through June 30, 2000 compared to a
$21,000 gain for the same period in 1999.
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Direct lifting costs incurred by BFC were $742,000 or $.41 per Mcfe for the
first six months of 2000 compared to $857,000 or $.37 per Mcfe for the same
period in 1999. The decrease was related to workover expenses incurred during
the first six months of 1999 and prior period charges for gas processing fees
billed to BFC in 1999. The increase in direct lifting costs for the first six
months of 2000 on a Mcfe basis were due to lower production on a per well basis.
Other production costs incurred by BFC consisting of production taxes and
overhead were $874,000 for the first six months of 2000 compared to $822,000 for
the similar period in 1999. The increase was attributable to higher severance
taxes due to increased oil and gas prices partially offset by a reduction in
production.
Direct lifting costs incurred by CEC were $317,000 or $.37 Mcfe for the period
February 18 through June 30, 2000 compared to $187,000 or $.26 per Mcfe for the
same period in 1999. The increase was primarily due to credits received by the
Company in 1999 for gas processing fees related to prior periods.
Other production costs incurred by CEC consisting of net crown and other royalty
expense was $315,000 for the period February 18 through June 30, 2000 compared
to $94,000 for the same period in 1999. The increase was attributable to a rise
in net crown royalties due to higher oil and gas prices.
Exploration and impairment expense was recorded by the Company's predecessor,
BFC, under the successful efforts method of accounting and consists primarily of
unsuccessful drilling and geological and geophysical costs. Effective as of the
date of the acquisition of BFC, Carbon utilizes the full cost method of
accounting. Under this method, all exploration costs associated with continuing
efforts to acquire or review prospects and outside geological and seismic
consulting work are capitalized.
General and administrative expenses incurred by BFC, net of overhead
reimbursements for the first six months of 2000 were $871,000 compared to
$792,000 for the same period in 1999. The increase was due to costs related to a
change in the location of administrative offices of the Company and reporting,
printing and regulatory filings relating to the Company being a publicly held
company in 2000.
General and administrative expenses incurred by CEC for the period February 18
through June 30, 2000 were $435,000, a $138,000 or 24% decrease from the same
period in 1999. The decrease was primarily due to lower professional fees,
contracted services, and allocated overhead from U.S. corporate services.
Interest and other expenses incurred by BFC, rose to $382,000 in the first six
months of 2000, a $179,000 or 88% increase from the prior year period. Interest
expense increased as a result of higher average debt balances on the Company's
debt. The average interest rate for the first six months was 7.9% compared to
7.0% in the first six months of 1999.
Interest and other expenses incurred by CEC, rose to $78,000 for the period
February 18 through June 30, 2000, a $45,000 increase from the similar period in
1999. Interest expense increased as a result of higher average debt balances on
the Company's debt.
Depreciation, depletion and amortization (DD&A) of oil and gas assets are
determined based upon the units of production method. This expense is typically
dependent upon historical capitalized costs incurred to find, develop and
recover oil and gas reserves; however, the Company's current DD&A rate is
determined primarily by the purchase price the Company allocated to oil and gas
properties in connection with its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
DD&A expense for BFC for the first six months of 2000 was $1,850,000 an increase
of $637,000 or 53% from the 1999 level. Depletion expense was $1.02 per Mcfe for
the first six months of 2000 compared to $.52 per Mcfe in 1999. The increase was
primarily attributable to increased property costs recorded as a result of the
acquisition of BFC.
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DD&A expense for CEC for the period from February 18 through June 30, 2000 was
$667,000 an increase of $117,000 or 21% from the 1999 level. The increase
resulted primarily from increased production. Depletion expense was $.79 per
Mcfe for the period February 18 through June 30, 2000 compared to $.75 per Mcfe
for the same period in 1999.
Financial Condition and Capital Resources
At June 30, 2000, Carbon had $54.9 million of assets. Total capitalization was
$46.6 million, of which 67% was represented by stockholders' equity and 33% by
debt. During the six months ended June 30, 2000, net cash used by operations was
$551,000, as compared to $1.5 million used in the first six months of 1999 for
the Company's predecessor BFC. Excluding changes in working capital, net cash
provided by operating activities for the Company for the six months ended June
30, 2000 was $2.7 million compared to $1.7 million for the Company's predecessor
BFC for the same period in 1999. At June 30, 2000, there were no significant
commitments for capital expenditures. The Company anticipates 2000 capital
expenditures, exclusive of acquisitions, to approximate $8.0 million. The level
of these and other future expenditures is largely discretionary, and the amount
of funds devoted to any particular activity may increase or decrease
significantly, depending on available opportunities and market conditions. The
Company plans to finance its ongoing development, acquisition and exploration
expenditures using internal cash flow and bank borrowings. In addition, joint
ventures or future public and private offerings of debt or equity securities may
be utilized.
U.S. Facility
The Company has an oil and gas reserve-based line-of-credit with U.S. Bank, N.A.
The facility had a borrowing base of $15.9 million with outstanding borrowings
of $12.8 million at June 30, 2000. Letters of credit totaling $1.5 million were
issued at June 30, 2000 which reduces the amount available for borrowings. The
facility is secured by certain U.S. oil and gas properties of the Company and is
scheduled to convert to a term note on July 1, 2001. This term is scheduled to
have a maturity date of either the economic half life of the Company's remaining
U.S. based reserves on the date of conversion or July 1, 2006, whichever is
earlier. The facility bears interest at a rate equal to LIBOR plus 1.75% or U.S.
Bank, N.A. Prime, depending on the option of the Company. The rate was
approximately 8.4% at June 30, 2000. The borrowing base is based upon the
lender's evaluation of the Company's proved oil and gas reserves, generally
determined semi-annually.
The credit agreement contains various covenants which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is also
required to maintain certain financial ratios.
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Credit Facility
The Company also has an accounts receivable-based credit facility which includes
a revolving line-of-credit with U.S. Bank, N.A. which provides for borrowings
and letters of credit up to $500,000. There were no outstanding borrowings or
letters of credit under this facility at June 30, 2000. This facility bears
interest at U.S. Bank, N.A. Prime (9.5% at June 30, 2000). This facility is
collateralized by certain trade receivables of the Company and has a maturity
date of July 1, 2001.
Canadian Facility
The facility with the Canadian Imperial Bank of Commerce (CIBC), has a borrowing
base of approximately $4.5 million with outstanding borrowings of $2.6 million
at June 30, 2000. The Canadian facility is secured by the Canadian oil and gas
properties of the Company. The revolving phase of the Canadian facility will
expire on December 31, 2000. If the revolving commitment is not renewed, the
loan will be converted into a term loan and will be reduced by way of
consecutive monthly payments over a period not to exceed 36 months. The Canadian
facility bears interest at the CIBC Prime rate plus 3/4%. The rate was
approximately 8.25% at June 30, 2000.
The Canadian facility contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness, sell
properties, or merge with another entity.
The agreement with CIBC also contains a $3.0 million swap facility that provides
at the Company's request and subject to market availability, interest rate swaps
and forward rate agreements to provide fixed or floating rate funding for part
or all of the production loan, commodity swaps covering a portion of the
Company's oil and gas production, forward exchange contracts and firm gas
purchase and sales transactions.
During 1995, BFC entered into an agreement to sell 99% of its interest in 14
coal gas wells located in New Mexico that qualified for IRC section 29 tax
credits. Under the terms of the agreement BFC is to receive 99% of the net cash
flow on the properties until certain cumulative production levels have been
reached, at which time the purchaser will receive 100% of the net cash flow
until a subsequent production level is reached. Upon reaching the second target,
100% of the cash flows will revert to BFC for substantially the remaining life
of the properties. The first production level was reached in January 2000. Due
to these contractual agreements, BFC will not be entitled to sales proceeds or
be obligated for the cost of operations on these properties until an additional
235,000 Mcf has been produced. The Company estimates this will take
approximately fifteen months. During this 15 month period, the Company will
still be entitled to receive tax credit benefits estimated to be $150,000.
Carbon's primary cash requirements will be to finance acquisitions, exploration
and development expenditures, repayment of debt, and general working capital
needs. However, future cash flow is subject to a number of variables including
the level of production and oil and natural gas prices and there can be no
assurance that operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures or that
increased capital expenditures will not be undertaken. Carbon believes that
available borrowings under its credit agreements, projected operating cash flows
and the cash on hand will be sufficient to cover its working capital, capital
expenditures, planned development activities and debt service requirements for
the next 12 months. In connection with consummating any significant acquisition,
additional debt or equity financing will be required, which may or may not be
available on terms that are acceptable to the Company.
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Certain Factors That May Affect Future Results
Statements that are not historical facts contained in this report are
forward-looking statements that involve risks and uncertainties that could cause
actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as future
capital, development and exploration expenditures, drilling of wells, reserve
estimates (including estimates of future net revenues associated with such
reserves and the present value of such future net revenues), future production
of oil and natural gas, business strategies, expansion and growth of the
Company's operations, cash flow and anticipated liquidity, prospect development
and property acquisition, obtaining financial or industry partners for prospect
or program development, or marketing of oil and natural gas. Although the
Company believes that the expectation reflected in the forward-looking
statements and the assumptions upon which such forward-looking statements are
based are reasonable it can give no assurance that such expectation and
assumptions will prove to be correct. Factors that could cause actual results to
differ materially (Cautionary Disclosures) are described, among other places, in
the Marketing, Competition, and Regulation sections of the Company's 1999 Form
10-K and under "Management's Discussion and Analysis of Financial Condition and
Results of Operations." These factors include, but are not limited to general
economic conditions, the market price of oil and natural gas, the risks
associated with exploration, the Company's ability to find, acquire, market,
develop and produce new properties, operating hazards attendant to the oil and
natural gas business, uncertainties in the estimation of proved reserves and in
the projection of future rates of production and timing of development
expenditures, the strength and financial resources of the Company's competitors,
the Company's ability to find and retain skilled personnel, climatic conditions,
labor relations, availability and cost of material and equipment, environmental
risks, the results of financing efforts, and regulatory developments. All
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Disclosures.
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Year 2000 Issues
The conversion from calendar year 1999 to 2000 occurred without any disruption
in the Company's operations and information systems nor has the Company been
made aware of any Year 2000 issues occurring at third parties with which Carbon
has relations. The Company will continue to monitor any Year 2000 issues, both
internally and with third parties of business importance to the Company such as
its natural gas purchasers, gathering system and plant operators, downstream
pipeline operators, equipment and service providers, operators of its oil and
gas properties, financial institutions, and vendors providing payroll and
medical benefits and services. The Company believes that the most serious effect
to the Company would be delays in receiving payments for oil and gas sold to its
purchasers which could have a material adverse effect upon the results of
operations and financial conditions of the Company. This monitoring will be
ongoing and encompassed in normal operations.
Market and Commodity Risk
Interest Rate Risk
Market risk is estimated as the potential change in the fair value of interest
sensitive instruments resulting from an immediate hypothetical change in
interest rates. The sensitivity analysis presents the change in the fair value
of these instruments and changes in the Company's earnings and cash flows
assuming an immediate one percent change in floating interest rates. As the
Company presently has only floating rate debt, interest rate changes would not
affect the fair value of these floating rate instruments but would impact future
earnings and cash flows, assuming all other factors are held constant. The
carrying amount of the Company's floating rate debt approximates its fair value.
At June 30, 2000, the Company had $12.8 million of floating rate debt through
its facility with U.S. Bank, NA, and $2.6 million through its facility with
CIBC. Assuming constant debt levels, earnings and cash flow impacts for the next
twelve month period from June 30, 2000 due to a one percent change in interest
rates would be approximately $128,000 before taxes for the facility with the
U.S. bank and $26,000 before taxes for the facility with the Canadian bank.
Foreign Currency Risk
The Canadian dollar is the functional currency of CEC and is subject to foreign
currency exchange rate risk on cash flows related to sales, expenses, financing
and investing transactions. The Company has not entered into any foreign current
forward contracts or other similar financial investments to manage this risk.
Commodity Price Risk
Oil and gas commodity markets are influenced by global as well as regional
supply and demand. World wide political events can also impact commodity prices.
The Company uses certain financial instruments in an attempt to manage commodity
price risk. The Company attempts to manage these risks by minimizing its
commodity price exposure through the use of derivative contracts as described in
Note 1 to the June 30, 2000 financial statements of Carbon and Note 5 to the
June 30, 1999 financial statements of BFC. These tools include, but are not
limited to commodity futures and option contracts, fixed-price swaps, basis
swaps, and term sales contracts. Gains and losses on these contracts are
deferred and recognized in income as an adjustment to oil and gas sales revenue
during the period in which the physical product to which the contract relates to
is actually sold.
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The following tables summarize the Company's derivative financial instrument
position on its natural gas and oil production as of June 30, 2000.
BFC Contracts CEC Contracts
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtu per MMBtu Year MMBtu per MMBtu
----- --------- ----------- ----- ------- -----------
2000 1,204,000 $ 2.41 2000 476,000 $ 2.32
2001 1,543,000 $ 2.36 2001 304,000 $ 2.35
--------- -------
2,747,000 780,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
----- --------- ----------- ----- ------- -----------
2000 24,000 $ 20.73 2000 18,000 $ 25.37
As of June 30, 2000, the Company would have been required to pay $5,053,000 and
$1,495,000 to exit the BFC and CEC contracts, respectively.
In addition, the Company utilizes collars that establish a price between a floor
and ceiling to hedge natural gas and oil prices. As of June 30, 2000 CEC had the
following natural gas collars in place:
Average Average
Floor Ceiling
Year MMBtu per MMBtu per MMBtu
-------------- ------------- ---------------- ---------------
2000 58,000 $ 3.38 $ 4.70
2001 85,000 $ 3.38 $ 4.70
As of June 30, 2000, the Company would have received $3,000 upon exiting the
contracts.
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In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, ("SFAS 133") "Accounting for Derivative
Instruments and Hedging Activities". SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement, and requires
that a Company must formally document, designate, and assess the effectiveness
of transactions that receive hedge accounting. SFAS 133, as amended, is
effective for all fiscal quarters of fiscal years beginning after June 15, 2000.
The Company has not yet quantified the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of, or method of,
adoption of SFAS 133. However, SFAS 133 could increase volatility in earnings
and other comprehensive income.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of inflation,
factors unique to the oil and natural gas industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and natural gas prices. Although it is particularly difficult to estimate
future prices of oil and natural gas, price fluctuations have had, and will
continue to have, a material effect on the Company.
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PART II - OTHER INFORMATION
Items 1 - 5. Not applicable
Item 6. (a) Exhibits
27 - Financial Data Schedule*
(b) No reports on Form 8-K were filed by the registrant during the quarter ended
June 30, 2000.
*Filed herewith
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CARBON ENERGY CORPORATION
Registrant
Date: August 14, 2000 By /s/ Patrick R. McDonald
------------------ ---------------------------------------
President and Chief Executive Officer
Date: August 14, 2000 By /s/ Kevin D. Struzeski
------------------ ---------------------------------------
Treasurer and Chief Financial Officer
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