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 September 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 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
---- -----
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the
Class Outstanding at November 7, 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>
September 30, December 31,
2000 1999
-------------- -------------
ASSETS (unaudited)
<S> <C> <C>
Current assets:
Cash $ 529,000 $ 995,000
Current portion of employee trust 55,000 881,000
Accounts receivable, trade 3,323,000 2,286,000
Accounts receivable, other 261,000 69,000
Amounts due from broker 3,311,000 1,250,000
Prepaid expenses and other 679,000 107,000
-------------- -------------
Total current assets 8,158,000 5,588,000
-------------- -------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 7,597,000 7,879,000
Proved properties 43,802,000 25,020,000
Furniture and equipment 334,000 214,000
-------------- -------------
51,733,000 33,113,000
Less accumulated depreciation, depletion and amortization (4,567,000) (627,000)
-------------- -------------
Property and equipment, net 47,166,000 32,486,000
-------------- -------------
Other assets:
Deferred acquisition costs - 310,000
Deposits and other 347,000 245,000
Employee trust 652,000 669,000
-------------- -------------
Total other assets 999,000 1,224,000
-------------- -------------
Total assets $ 56,323,000 $ 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>
September 30, December 31,
2000 1999
-------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY (unaudited)
<S> <C> <C>
Current liabilities:
Accounts payable and accrued expenses $ 3,834,000 $ 4,391,000
Accrued production taxes payable 508,000 367,000
Income taxes payable 217,000 -
Undistributed revenue 1,022,000 598,000
-------------- ------------
Total current liabilities 5,581,000 5,356,000
-------------- ------------
Long term debt 16,660,000 9,100,000
Other long term liabilities 118,000 527,000
Deferred income taxes 2,579,000 -
Commitments and contingencies (Note 5)
Minority interest 11,000 -
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
6,017,459 shares and 4,510,000 shares outstanding
at September 30, 2000 and December 31, 1999, respectively 31,303,000 24,806,000
Retained earnings (accumulated deficit) 29,000 (491,000)
Currency translation adjustment 42,000 -
-------------- ------------
Total stockholders' equity 31,374,000 24,315,000
-------------- ------------
Total liabilities and stockholders' equity $ 56,323,000 $ 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 Nine Months
Ended Ended
September 30, 2000 September 30, 2000
------------------- ------------------
(unaudited) (unaudited)
<S> <C> <C>
Revenues:
Oil and gas sales $ 4,384,000 $ 11,413,000
Gas marketing and transportation 709,000 3,012,000
Other 86,000 208,000
------------------- ------------------
5,179,000 14,633,000
Expenses:
Oil and gas production costs 1,578,000 3,826,000
Gas marketing transportation and other 816,000 3,134,000
Depreciation, depletion and amortization expense 1,517,000 4,034,000
General and administrative expense, net 748,000 2,054,000
Interest expense, net 323,000 783,000
------------------- ------------------
Total operating expenses 4,982,000 13,831,000
Minority interest 4,000 11,000
------------------- ------------------
193,000 791,000
Income taxes:
Current 75,000 240,000
Deferred (54,000) 31,000
------------------- ------------------
Net income $ 172,000 $ 520,000
=================== ==================
Earings per share:
Basic $ 0.03 $ 0.09
Diluted 0.03 0.09
Average number of common shares
outstanding (in thousands):
Basic 6,015 5,755
Diluted 6,075 5,801
</TABLE>
The accompanying notes are an integral part of these financial statements.
4
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Nine Months Ended September 30, 2000
(Unaudited)
<TABLE>
<CAPTION>
Retained
Common Stock Earnings 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 1,507,459 6,497,000 - - 6,497,000
Currency translation adjustment - - - 42,000 42,000
Net income - - 520,000 - 520,000
------------ ------------------ ---------------- ------------------ ------------------
Balances, September 30, 2000 6,017,459 $ 31,303,000 $ 29,000 $ 42,000 $ 31,374,000
============ ================== ================ ================== ==================
</TABLE>
The accompanying notes are an integral part of these financial statements.
5
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Nine Months
Ended
September 30, 2000
------------------------
(unaudited)
<S> <C>
Cash flows from operating activities:
Net income $ 520,000
Adjustments to reconcile net income to net cash
provided by opertating activities:
Depreciation, depletion and amortization expense 4,034,000
Deferred income tax 31,000
Minority interest 11,000
Employee stock grants 87,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable (350,000)
Amounts due from broker (2,062,000)
Prepaid expenses and other (675,000)
Other assets (43,000)
Increase (decrease) in:
Accounts payable and accrued expenses (1,020,000)
Undistributed revenue 552,000
------------------------
Net cash provided by operating activities 1,085,000
Cash flows from investing activities:
Capital expenditures for oil and gas properties (6,397,000)
Acquisition of CEC Resources (146,000)
Capital expenditures for support equipment (121,000)
------------------------
Net cash used in investing activities (6,664,000)
Cash flows from financing activities:
Proceeds from note payable 23,621,000
Principal payments on note payable (18,563,000)
Proceeds from issuance of common stock 55,000
------------------------
Net cash provided by financing activities 5,113,000
------------------------
Net decrease in cash (466,000)
Cash, beginning of period 995,000
------------------------
Cash, end of period $ 529,000
========================
Supplemental cash flow information:
Cash paid for interest $ 1,017,000
Cash paid for taxes 46,000
The Company acquired 97.5% of the common stock 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 September 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.
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.
7
<PAGE>
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 September 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).
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.
8
<PAGE>
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 September 30,
2000 these obligations were $772,000 and $265,000 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 September 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 522,000 $ 2.49 2000 183,000 $ 2.46
2001 1,543,000 $ 2.36 2001 391,000 $ 2.71
--------- -------
2,065,000 574,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
------ --------- ----------- ----- ------- -----------
2000 12,000 $ 20.14 2000 9,000 $ 25.37
As of September 30, 2000, the Company would have been required to pay $5,044,000
and $1,306,000 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 September 30, 2000 CEC
had the following natural gas collars in place:
Average Average
Floor Ceiling
Year MMBtu per MMBtu per MMBtu
----------- ---------- ------------ ------------
2000 58,000 $ 3.50 $ 4.86
2001 85,000 $ 3.50 $ 4.86
As of September 30, 2000, the Company would have been required to pay $31,000
upon exiting these contracts.
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). In June 1999, the FASB issued SFAS 137
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of SFAS 133," which deferred SFAS 133's effective date to fiscal
years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
which amended SFAS 133. SFAS 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) to be recorded in the balance sheet as
either an asset or liability at its fair value. The accounting for changes in
the fair value of a derivative depends on the intended use of the derivative and
the resulting designation.
The Company will adopt SFAS 133 effective January 1, 2001. If the Company's
derivative financial instruments qualify for special hedge accounting treatment
under SFAS 133, changes in fair value will be recognized in other comprehensive
income (a component of stockholders' equity) until settled, when the resulting
gains and losses will be recorded in earnings. Any hedge ineffectiveness will be
charged currently to earnings. The Company has not yet quantified the impacts of
adopting SFAS 133 on its financial statements. The affect on the Company's
earnings and other comprehensive income as a result of the adoption of SFAS 133
will vary from period to period and will be dependent upon prevailing oil and
gas prices, the volatility of forward prices for such commodities, the volumes
of production hedged and the time period covered by such hedges.
10
<PAGE>
Foreign Currency Translation - The functional currency of CEC 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
$42,000 for the nine months ended September 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 in existence for only 17
days during September 1999, the pro forma information presented is for the nine
month period ending September 30, 2000 only.
Nine Months
Ended
September 30, 2000
----------------------
(unaudited)
Total revenue $ 15,283,000
Net income $ 613,000
Earnings per share:
Basic $ 0.11
Diluted $ 0.11
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 September 30, 2000:
U.S. facility $13,899,000
Canadian facility 2,761,000
-------------------
16,660,000
Current portion -
-------------------
Long term $16,660,000
===================
U.S. Facility
The Company moved its credit facility from U.S. Bank National Association to
Wells Fargo Bank West, National Association in the third quarter of 2000.
The facility is an oil and gas reserve-based line-of-credit and had a borrowing
base of $16.9 million with outstanding borrowings of $13.9 million at September
30, 2000. 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 October 1, 2002. This
facility is scheduled to have a maturity date of either the economic half life
of the Company's remaining U.S. based reserves on the last day of the revolving
period, or July 1, 2006, whichever is earlier. The facility bears interest at a
rate equal to LIBOR plus 1.75% or Wells Fargo Bank West Prime, at the option of
the Company. The rate was approximately 9.5% at September 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.
Canadian Facility
The facility with the Canadian Imperial Bank of Commerce (CIBC), has a borrowing
base of approximately $4.4 million with outstanding borrowings of $2.8 million
at September 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 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 September 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.
13
<PAGE>
The agreement with CIBC also contains a $3.0 million swap facility that provides
at the Company's request and subject to market availability, 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 September 30, 2000 have been $888,000 for employees who were terminated
or had their employment contracts terminated. Subsequent to September 30, 2000,
additional distributions in the amount of $55,000 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 are 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 nine month period ended September 30, 2000. Any remaining
amounts in the trust will revert to the Company upon expiration of the trust.
5. Commitments and Contingencies:
Office Lease - The Company entered into various lease agreements, which provide
for total minimum rental commitments as follows:
U.S. Canada
------------ -----------
2000 - Remainder of year $ 49,000 $ 19,000
2001 197,000 86,000
2002 203,000 86,000
2003 208,000 79,000
2004 212,000 -
------------ -----------
$ 869,000 $270,000
============ ===========
14
<PAGE>
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 is
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 nine months ended September 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 Company granted 10,000 shares of restricted stock during the
nine months ended September 30, 2000. The shares vest ratably over 36 months.
The Company recognized compensation expense of $30,000 and $87,000 for the third
quarter and first nine 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:
Nine Months
Ended
September 30, 2000
----------------------
(in thousands)
Tax expense at 35% of income before income
taxes $ 276
Change in the valuation allowance against
deferral tax asset (27)
Tax expense of higher effective rate on
Canadian income 29
Canadian resource allowance (309)
Canadian Crown payments (net of Alberta
Royalty Tax Credit) not deductible
for tax purposes 269
Other 33
----------------------
$ 271
======================
The net deferred tax liability by geographic area is comprised of the following:
<TABLE>
<CAPTION>
September 30, 2000
-------------------------------------------------
United States Canada Total
--------------- --------------- ---------------
(in thousands)
<S> <C> <C> <C>
Federal net operating loss carryforward $ (1,731) $ - $ (1,731)
Property and equipment 1,628 2,620 4,248
Other (18) (41) (59)
Valuation allowance 121 - 121
-------------- --------------- ---------------
Net deferred tax liability $ - $ 2,579 $ 2,579
============== =============== ===============
</TABLE>
As of September 30, 2000, the Company had a net operating loss carryforward for
federal income tax purpose of $4,947,000 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 are reached,
at which time the counterparty will receive 100% of the net cash flow until the
second production level is reached. Upon reaching the second level, 100% of the
cash flows will revert to BFC for substantially the remaining life of the
properties.
Upon review of the agreement, it was discovered that both production levels had
been reached prior to 2000. According to the agreement, the counter party was to
have received 100% of the net cash flows for the period approximating December
1998 through early November 1999. Net cash flows for this period were $178,000.
Substantially all of the adjustment relates to periods prior to October 29,
1999, the date that Carbon acquired BFC. This adjustment was recorded as an
increase to the purchase price of BFC by Carbon of $178,000 and as a liability
to the counter party to the agreement, included in accounts payable and accrued
expenses.
BFC had been crediting the account of the counter party for 100% of the net cash
flow on the related properties from January 2000 until it was discovered that
the second production level had been reached. BFC has adjusted its records to
recognize oil and gas sales income, severance taxes, and operating expenses for
the periods from January through June 2000. The adjustments relating to the
first and second quarters of 2000 were made in the third quarter of 2000. The
adjustment was to increase oil and gas sales by $255,000, severance taxes by
$20,000, and lease operating expenses by $56,000.
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
September 30, 2000 September 30, 2000
United Consolidated
States Canada Totals
----------------------- ----------------------- -----------------
<S> <C> <C> <C>
Oil and gas sales $ 2,785,000 $ 1,599,000 $ 4,384,000
Gas marketing, transportation, and other 795,000 - 795,000
----------------------- ----------------------- -----------------
Total revenues 3,580,000 1,599,000 5,179,000
Oil and gas production costs 1,024,000 554,000 1,578,000
Gas marketing, transportation, and other 745,000 71,000 816,000
Depreciation and depletion 1,079,000 438,000 1,517,000
General and administrative, net 452,000 296,000 748,000
Interest expense, net 270,000 53,000 323,000
----------------------- ----------------------- -----------------
Total operating expenses 3,570,000 1,412,000 4,982,000
Minority interest in net income - 4,000 4,000
Income tax - 21,000 21,000
----------------------- ----------------------- -----------------
Net income $ 10,000 $ 162,000 $ 172,000
======================= ======================= =================
----------------------- ----------------------- -----------------
Total assets $ 41,591,000 $ 14,732,000 $ 56,323,000
======================= ======================= =================
</TABLE>
18
<PAGE>
<TABLE>
<CAPTION>
For the period
from
Nine Months February 18
Ended through
September 30, 2000 September 30, 2000
United Consolidated
States Canada Totals
----------------------- ----------------------- -----------------
<S> <C> <C> <C>
Oil and gas sales $ 7,464,000 $ 3,949,000 $ 11,413,000
Gas marketing, transportation, and other 3,220,000 3,220,000
----------------------- ----------------------- -----------------
Total revenues 10,684,000 3,949,000 14,633,000
Oil and gas production costs 2,640,000 1,186,000 3,826,000
Gas marketing, transportation, and other 3,063,000 71,000 3,134,000
Depreciation and depletion 2,929,000 1,105,000 4,034,000
General and administrative, net 1,323,000 731,000 2,054,000
Interest expense, net 652,000 131,000 783,000
----------------------- ----------------------- -----------------
Total operating expenses 10,607,000 3,224,000 13,831,000
Minority interest in net income - 11,000 11,000
Income tax - 271,000 271,000
----------------------- ----------------------- -----------------
Net income $ 77,000 $ 443,000 $ 520,000
======================= ======================= =================
----------------------- ----------------------- -----------------
Total assets $ 41,591,000 $ 14,732,000 $ 56,323,000
======================= ======================= =================
</TABLE>
10. Subsequent Event:
On November 13, 2000, the Company signed an agreement to sell its San Juan Basin
properties for $7.5 million subject to certain conditions. The effective date of
the sale is September 1, 2000 and the expected closing date is January 5, 2001.
19
<PAGE>
For comparative purposes, Carbon is required to present unaudited statements of
income for the three and nine month periods ended September 30, 1999 and the
unaudited statement of cash flow for the nine month period ended September 30,
1999 and the accompanying notes to these financial statements for BFC, the
predecessor company to Carbon. The acquisition for BFC by Carbon closed on
October 29, 1999.
BONNEVILLE FUELS CORPORATION
STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended Ended
September 30, 1999 September 30, 1999
----------------------- ----------------------
(unaudited) (unaudited)
<S> <C> <C>
Revenues:
Oil and gas sales $ 2,170,000 $ 6,730,000
Gas marketing and transportation 1,109,000 11,059,000
Other 247,000 465,000
----------------------- ----------------------
3,526,000 18,254,000
----------------------- ----------------------
Expenses:
Oil and gas production costs 772,000 2,451,000
Gas marketing and transportation costs 1,267,000 11,009,000
Depreciation, depletion and amortization expense 576,000 1,789,000
General and administrative expense, net 193,000 985,000
Exploration expense 42,000 681,000
Impairment expense 0 60,000
Interest expense, net 143,000 346,000
----------------------- ----------------------
2,993,000 17,321,000
----------------------- ----------------------
533,000 933,000
Income taxes:
Current 0 0
Deferred 0 0
----------------------- ----------------------
0 0
----------------------- ----------------------
Net income $ 533,000 $ 933,000
======================= ======================
</TABLE>
The accompanying notes are an integral part of these financial statements.
20
<PAGE>
BONNEVILLE FUELS CORPORATION
STATEMENT OF CASH FLOW
<TABLE>
<CAPTION>
Nine Months
ended
September 30, 1999
-----------------------
(unaudited)
<S> <C>
Cash flows from operating activities:
Net income (loss) $ 933,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 1,775,000
Amortization of loan costs 14,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable, trade 2,759,000
Amounts due from broker (1,226,000)
Prepaid expenses and other 42,000
Increase (decrease) in:
Accounts payable and accrued expenses (5,132,000)
Undistributed revenue 101,000
-----------------------
Net cash used in operating activities (734,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (4,691,000)
Other net property and equipment (1,000)
Other assets 38,000
-----------------------
Net cash used in investing activities (4,654,000)
Cash flows from financing activities:
Proceeds from note payable 9,750,000
Principal payments on note payable (6,800,000)
-----------------------
Net cash provided by (used in) financing activities 2,950,000
Net increase (decrease) in cash and equivalents (2,438,000)
Cash, beginning of year 2,742,000
-----------------------
Cash, end of year $ 304,000
=======================
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. BFC 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. From time to time the Company also purchases
and resells electricity.
These financial statements are prepared in accordance with generally accepted
accounting principles and require the use of management's estimates. These
statements contain all adjustments (consisting only of normal recurring
accruals) which, in the opinion of management, are necessary to present fairly
the results of its operations and of its cash flows for the periods presented.
The results of operations for interim periods are not necessarily indicative of
the results to be expected for the full year.
Principles of Consolidation - The consolidated financial statements include the
accounts of BFC and its four wholly owned subsidiaries. All significant
inter-company 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.
22
<PAGE>
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 $150,000 and $-0-, for the periods ended
September 30, 1999 and 1998, respectively.
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. The impairment is
included as a reduction of gross oil and gas properties in the accompanying
balance sheets. In the first nine months of 1999, the Company incurred
impairment cost of $60,000. In 1998, the Company recorded impairment cost of
$1,858,000. Factors causing the impairment of oil and gas properties were the
decline in oil prices worldwide and re-assessment of reserve values on certain
producing properties in 1998, and re-assessment of reserve values on a drilling
venture in 1999.
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.
Revenue Recognition - The Company recognizes revenue for oil and gas production
upon delivery of the commodity to the purchaser.
The Company records sales and 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).
Undistributed Revenue - Represents amounts due to other owners of jointly owned
oil and gas properties for their revenue from the properties.
Energy Marketing Arrangements - In 1998, BFC entered into an agreement to manage
certain natural gas contracts of an unrelated entity. For contracts under which
BFC takes title to the gas which services these contracts, BFC records all
revenue, expense, receivables and payables associated with the contracts. In
contracts where title is not taken, BFC records only the margin associated with
the transaction. This agreement was terminated at the end of April 1999.
23
<PAGE>
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 natural gas sales resulting from production credited to the
Company in excess of its revenue interest share. Under this method, all proceeds
from 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 were a separate taxpayer.
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.
Contingent Liabilities - The Company accrued a liability in the amount of
$250,000 for well connect fees in the nine months ended September 30, 1999. The
estimated liability arose as a result of a 1997 well connect agreement as it was
determined in the current year that a liability under this agreement was
reasonably possible.
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.
24
<PAGE>
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
$16,556,667 on September 30, 1999. Outstanding borrowings amounted to
$8,800,000, with interest at a variable rate that approximated 7.2% at September
30, 1999. The Company has issued letters of credit totaling $2,250,000, which
reduce the amount available for borrowing under 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.
25
<PAGE>
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. There were no borrowings under this facility at September 30, 1999.
This facility bears interest at prime (8.25% at September 30, 1999). This
facility is collateralized by certain trade receivables of BFC and has a
maturity date of July 2, 2001.
The credit agreement contains various covenants which, prohibit or limit the
Company'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 non-cancellable operating
lease. Total rental expense was approximately $110,000 and $100,000 for the
periods ended September 30, 1999 and 1998, respectively. Beginning in 1998, the
Company has a new lease agreement, which provides for total minimum rental
commitments of:
1999 (balance of year) $ 37,000
2000 153,000
2001 159,000
2002 166,000
-------------
$ 515,000
=============
26
<PAGE>
4. Income Taxes:
The components of the net deferred tax asset are as follows:
December 31,
1998
---------------
Excess of tax basis over book basis of oil and gas properties $ 1,873,000
---------------
Deferred tax asset 1,873,000
Less valuation allowance (1,873,000)
---------------
Net deferred tax asset $ -
===============
The Company has not accrued an income tax liability for the nine months ending
September 30, 1999 due to the availability of intangible drilling costs, which
will essentially eliminate taxable net income.
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 asset.
5. Concentrations of Credit Risk and Price Risk Management:
Concentrations of Credit Risk - Substantially all of the Company's accounts
receivable at September 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.
Management estimates that over 85% of the value of the Company's properties is
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 option 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 September 30, 1999 and 1998, BFC has financial and physical
contracts which hedge 4.4 bcf (billion cubic feet) and 5.5 bcf of production,
respectively, through December 2001.
27
<PAGE>
The difference between the current market value of the hedging contracts and the
original market value of the hedging contracts was an unfavorable $1,755,000 and
a favorable $48,000 as of September 30, 1999 and 1998, respectively. 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 requires 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, undistributed revenue, and accrued expenses approximates fair
value of these instruments. See Note 5 for a discussion regarding the fair value
of energy financial instruments.
7. Subsequent Event:
On October 29, 1999, Carbon Energy Corporation acquired BFC in its entirety. The
purchase price for all of the stock of BFC was $23,581,000 plus debt, net of
working capital, of approximately $6,500,000 that remains BFC.
28
<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 financial condition and results of operations, the three months
ended September 30, 2000 and the period February 18, 2000 through September 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 nine month
periods ended September 30, 1999 and 2000.
Three months ended September 30, 2000, compared to three months ended September
30, 1999 (third quarter).
<TABLE>
<CAPTION>
United States Canada
Three Months Ended Three Months Ended
September 30, September 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 $ 2,364 $ 1,832 29% $ 1,308 $ 697 88%
Oil and Liquids 421 338 25% 291 205 42%
----------- ---------- ---------- -----------
Total 2,785 2,170 28% 1,599 902 77%
Sales volumes:
Natural gas (MMcf) 912 1,007 (9%) 453 387 17%
Oil and Liquids (Bbl) 17,666 16,216 9% 17,910 11,518 55%
Average price received:
Natural gas (Mcf) $ 2.59 $ 1.82 42% $ 2.89 $ 1.80 61%
Oil and Liquids (Bbl) 23.83 20.84 14% 16.25 17.80 (9%)
Direct lifting costs $ 434 $ 411 4% $ 217 $ 155 40%
Average direct lifting costs/Mcfe 0.43 0.37 62% 0.39 0.34 15%
Other production costs 590 361 64% 337 95 255%
Gas marketing, transportation
and other revenue $ 795 $ 1,356 (41%) $ - $ - 0%
Gas and electrical marketing expense 745 1,267 (41%) - - 0%
General and administrative, net 452 193 134% 296 276 7%
Depreciation, depletion and amortization 1,079 576 87% 438 401 9%
Exploration and impairment expense - 42 (100%) - - 0%
Interest expense, net 270 143 89% 53 66 (19%)
</TABLE>
Revenues for oil, and gas sales of BFC for the third quarter of 2000 were $2.8
million, a 28% increase from the prior year period. The increase was due
primarily to increased oil and gas prices and adjustments for properties subject
to tax credit agreements (See Note 8 to the Financial Statements of Carbon)
partially offset by production declines in the Permian Basin on new wells
connected in 1998 and 1999.
29
<PAGE>
Revenues for oil, liquids and gas sales of CEC for the third quarter of 2000
were $1.6 million, a 77% increase from the prior year period. The increase was
due primarily to increased oil, liquid and gas production and higher gas prices.
BFC's average production for the third quarter of 2000 was 192 barrels of oil
per day and 10.0 million cubic feet (MMcf) of gas per day, a decrease of 8% 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. The decline was partially offset
by recognizing 84,000 Mcf of production attributable to the first and second
quarters of 2000 on certain properties subject to section 29 tax credits (see
Note 8 to the Financial Statements of Carbon). During the quarter, six gross
wells and 1.1 net wells were drilled compared to one gross well and .6 net wells
drilled during the third quarter of 1999.
CEC's average production for the third quarter 2000 was 195 barrels of oil and
liquids per day and 4.9 Mcf of gas per day, an increase of 22% 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 third
quarter 2000 nor for the similar period in 1999.
Average oil prices received by BFC increased 14% from $20.84 per barrel in the
third quarter of 1999 to $23.83 in the third quarter of 2000. The average oil
price includes hedge losses of $126,000 for the third quarter of 2000. There was
no oil hedge activity for the similar period in 1999. Average natural gas prices
received by BFC increased 42% from $1.82 per Mcf for the third quarter of 1999
to $2.59 per Mcf in 2000. The average natural gas price includes hedge losses of
$903,000 for the third quarter of 2000 compared to a $250,000 loss for the same
period in 1999.
Average oil and liquids prices received by CEC decreased 9% from $17.80 per
barrel for the third quarter of 1999 to $16.25 for the same period in 2000. The
average price includes hedge losses of $58,000 for the third quarter of 2000.
There was no oil hedge activity for the similar period in 1999. Average natural
gas prices received by CEC increased 61% from $1.80 per Mcf for the third
quarter of 1999 to $2.89 for the same period in 2000. The average natural gas
price includes hedge losses of $384,000 for the third quarter of 2000 compared
to a $126,000 loss for the same period in 1999.
Direct lifting costs incurred by BFC were $434,000 or $.43 per Mcfe for the
third quarter of 2000 compared to $411,000 or $.37 per Mcfe for 1999. The per
Mcfe increase was related to operating approximately the same number of wells
with lower production per well. Compared to the same period in 1999, BFC has
seen an increase in well service costs due to vendor price increases. This
increase was partially offset by well workover expenses incurred during the
third quarter of 1999.
Other production costs incurred by BFC consisting of production taxes and
overhead, were $595,000 for the third quarter of 2000 compared to $362,000 for
the similar period in 1999. The increase was attributable to higher severance
taxes due to higher prices, partially offset by a decrease in oil and gas
production.
30
<PAGE>
Direct lifting costs incurred by CEC were $217,000 or $.39 per Mcfe for the
third quarter of 2000 compared to $155,000 or $.34 per Mcfe for 1999.
Other production costs incurred by CEC consisting of net crown and other royalty
expense were $337,000 for the third quarter of 2000 compared to $95,000 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 third quarter of 2000 were $452,000 compared to $193,000
for the same period in 1999. In the third quarter of 1999, BFC reversed $60,000
of incentive accruals due to the pending sale of the company to Carbon. For
2000, the increase was primarily due to a lower amount of corporate overhead
allocated to production and other operations compared to the same period in
1999, costs for reporting, printing and regulatory filings relating to the
Company being a publicly held company in 2000 and increased consulting and
travel and entertainment expenses.
General and administrative expenses incurred by CEC for third quarter 2000 were
$296,000, a $20,000 or 7% increase from the same period in 1999. The increase
was primarily due to higher allocated overhead for U.S. corporate services.
Interest and other expenses incurred by BFC, rose to $270,000 in the third
quarter of 2000, a $127,000 or 89% increase from the prior year period. Interest
expense increased as a result of higher average debt balances on the Company's
debt and higher interest rates. The average interest rate for the third quarter
of 2000 was 8.4% compared to 7.0% for the similar period in 1999.
Interest and other expenses incurred by CEC, decreased to $53,000 for the third
quarter 2000, a $13,000 decrease from the similar period in 1999. Interest
expense decreased as a result of lower 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.
31
<PAGE>
DD&A expense for BFC for the third quarter of 2000 was $1,079,000 an increase of
$503,000 or 87% from the 1999 level. DD&A expense was $1.06 per Mcfe for the
third quarter of 2000 compared to $.52 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 third quarter 2000 was $438,000 an increase of
$37,000 or 9% from the 1999 level. The increase resulted primarily from
increased production. DD&A expense was $.78 per Mcfe for the third quarter of
2000 compared to $.88 per Mcfe for the same period in 1999.
Results of Operations
Nine months ended September 30, 2000, compared to nine months ended September
30, 1999 for BFC and the period February 18 through September 30, 1999 compared
to the period February 18 through September 30, 1999 for CEC.
<TABLE>
<CAPTION>
United States For the Period from
Nine Months Ended February 18 through
September 30, September 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 $ 6,233 $ 5,942 5% $ 3,116 $ 1,746 78%
Oil and Liquids 1,231 788 56% 833 506 65%
----------- ---------- ---------- -----------
Total 7,464 6,730 11% 3,949 2,252 75%
Sales volumes:
Natural gas (MMcf) 2,528 3,128 (19%) 1,157 973 19%
Oil and Liquids (Bbl) 51,163 49,900 3% 41,831 35,813 17%
Average price received:
Natural gas (Mcf) $ 2.47 $ 1.90 30% $ 2.69 $ 1.79 50%
Oil and Liquids (Bbl) 24.06 15.79 52% 19.91 14.13 41%
Direct lifting costs $ 1,176 $ 1,172 0% $ 534 $ 342 56%
Average direct lifting costs/Mcfe 0.41 0.34 21% 0.38 0.29 31%
Other production costs 1,464 1,279 14% 652 189 245%
Gas marketing, transportation
and other revenue $ 3,220 $ 11,524 (72%) $ - $ - 0%
Gas and electrical marketing expense 3,063 11,009 (72%) - - 0%
General and administrative, net 1,323 985 34% 731 849 (14%)
Depreciation, depletion and amortization 2,929 1,789 64% 1,105 951 16%
Exploration and impairment expense - 741 (100%) - - 0%
Interest expense, net 652 346 88% 131 99 32%
</TABLE>
Revenues for oil and gas sales of BFC for the first nine months of 2000 were
$7.5 million, an 11% 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.
32
<PAGE>
Revenues for oil, liquids and gas sales of CEC for the period February 18
through September 30, 2000 were $3.9 million, a 75% increase from the prior year
period. The increase was due primarily to increased oil, liquids and gas
production and higher oil, liquids and gas prices.
BFC's average production for the first nine months of 2000 was 187 barrels of
oil per day and 9.2 million cubic feet (MMcf) of gas per day, a decrease of 17%
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. During the nine months ended
September 30, 2000, 14 gross wells and 6.8 net wells were drilled compared to 7
gross wells and 5.0 net wells drilled during the same period in 1999.
CEC's average production for the period February 18 through September 30, 2000
was 185 barrels of oil and liquids per day and 5.1 MMcf of gas per day, an
increase of 19% 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 September 30, 1999 and 2000.
Average oil prices received by BFC increased 52% from $15.79 per barrel in the
first nine months of 1999 to $24.06 in the first nine months of 2000. The
average oil price includes hedge losses of $228,000 for the first nine months of
2000. There was no oil hedge activity for the similar period in 1999. Average
natural gas prices received by BFC increased 30% from $1.90 per Mcf for the
first nine months of 1999 to $2.47 per Mcf in 2000. The average natural gas
price includes hedge losses of $1,305,000 for the first nine months of 2000 and
hedge gains of $92,000 for the similar period in 1999.
Average oil and liquids prices received by CEC increased 41% from $14.13 per
barrel for the period from February 18 through September 30, 1999 to $19.91 for
the same period in 2000. The average price includes hedge losses of $93,000 for
the period February 18 through September 30, 2000. There was no oil hedge
activity for the similar period in 1999. Average natural gas prices received by
CEC increased 50% from $1.79 per Mcf for the period from February 18 through
September 30, 1999 to $2.69 for the same period in 2000. The average natural gas
price includes hedge loss of $542,000 for the period February 18 through
September 30, 2000 compared to a $104,000 loss for the same period in 1999.
Direct lifting costs incurred by BFC were $1,176,000 or $.41 per Mcfe for the
first nine months of 2000 compared to $1,172,000 or $.34 per Mcfe for the same
period in 1999. The per Mcfe increase was related to operating approximately the
same number of wells with lower production per well. Compared to the same period
in 1999, BFC has seen an increase in well service costs due to vendor price
increases. This increase was partially offset by well workover expenses incurred
during 1999.
33
<PAGE>
Other production costs incurred by BFC consisting of production taxes and
overhead were $1,464,000 for the first nine months of 2000 compared to
$1,279,000 for the similar period in 1999. The increase was primarily due 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 $534,000 or $.38 Mcfe for the period
February 18 through September 30, 2000 compared to $342,000 or $.29 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 $652,000 for the period February 18 through September 30, 2000
compared to $189,000 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 nine months of 2000 were $1,323,000 compared to
$985,000 for the same period in 1999. In 1999, BFC reversed $95,000 of incentive
accruals due to pending sale of the company to Carbon. For 2000, the increase
was primarily due to a lower amount of corporate overhead allocated to
production and other operations compared to the same period in 1999, costs
related to a change in the location of administrative office of the Company and
costs for 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 September 30, 2000 were $731,000, a $118,000 or 14% 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 $652,000 in the first nine
months of 2000, a $306,000 or 88% increase from the prior year period. Interest
expense increased primarily as a result of higher average debt balances on the
Company's debt. The average interest rate for the first nine months was 8.0%
compared to 6.8% in the first nine months of 1999.
Interest and other expenses incurred by CEC, rose to $131,000 for the period
February 18 through September 30, 2000, a $32,000 increase from the similar
period in 1999. Interest expense increased primarily as a result of higher
average debt balances on the Company's debt.
34
<PAGE>
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 nine months of 2000 was $2,929,000 an
increase of $1,140,000 or 64% from the 1999 level. DD&A expense was $1.03 per
Mcfe for the first nine 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.
DD&A expense for CEC for the period from February 18 through September 30, 2000
was $1,105,000 an increase of $154,000 or 16% from the 1999 level. The increase
resulted primarily from increased production. DD&A expense was $.78 per Mcfe for
the period February 18 through September 30, 2000 compared to $.80 per Mcfe for
the same period in 1999.
Financial Condition and Capital Resources
At September 30, 2000, Carbon had $56.3 million of assets. Total capitalization
was $48.0 million, of which 65% was represented by stockholders' equity and 35%
by debt. During the nine months ended September 30, 2000, net cash provided by
operations was $1,085,000 as compared to $734,000 used in the first nine 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 nine months
ended September 30, 2000 was $4.7 million compared to $2.7 million for the
Company's predecessor BFC, for the same period in 1999. At September 30, 2000,
there were no significant commitments for capital expenditures. The Company
anticipates 2000 capital expenditures, exclusive of acquisitions, to approximate
$11 million which reflects additional anticipated fourth quarter projects for
CEC. 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.
On November 13, 2000, the Company signed an agreement to sell its San Juan Basin
properties for $7.5 million subject to certain conditions. The effective date of
the sale is September 1, 2000 and the expected closing date is January 5, 2001.
Production from the properties is approximately 1.7 MMcfe per day after
royalties net to the Company's interest. The Company expects to use the proceeds
from the sale to continue to develop its acreage position in the Piceance Basin
of Colorado and the Uintah Basin of Utah.
U.S. Facility
The Company moved its credit facility from U.S. Bank National Association to
Wells Fargo Bank West, National Association in the third quarter of 2000.
The facility is an oil and gas reserve-based line-of-credit and had a borrowing
base of $16.9 million with outstanding borrowings of $13.9 million at September
30, 2000. 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 October 1, 2002. This
facility is scheduled to have a maturity date of either the economic half life
of the Company's remaining U.S. based reserves on the last day of the revolving
period, or July 1, 2006, whichever is earlier. The facility bears interest at a
rate equal to LIBOR plus 1.75% or Wells Fargo Bank West Prime, at the option of
the Company. The rate was approximately 9.5% at September 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.
35
<PAGE>
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.
Canadian Facility
The facility with the Canadian Imperial Bank of Commerce (CIBC), has a borrowing
base of approximately $4.4 million with outstanding borrowings of $2.8 million
at September 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 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 September 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, commodity swaps
covering a portion of the Company's oil and gas production, forward exchange
contracts and firm gas purchase and sales transactions.
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. Nevertheless, Carbon will explore outside funding
opportunities including equity or additional debt financings for use in
expanding Carbon's operations or in consummating any significant acquisition,
Carbon does not know whether any financing can be accomplished on terms that are
acceptable to the Company.
36
<PAGE>
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.
Item 3. Quantitative and Qualitative Disclosures about Market 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 September 30, 2000, the Company had $13.9 million of floating rate debt
through its facility with Wells Fargo Bank West, and $2.8 million through its
facility with CIBC. Assuming constant debt levels, earnings and cash flow
impacts for the next twelve month period from September 30, 2000 due to a one
percent change in interest rates would be approximately $139,000 before taxes
for the facility with the U.S. bank and $28,000 before taxes for the facility
with the Canadian bank.
37
<PAGE>
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
currency 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 September 30, 2000 financial statements of Carbon and Note 5 to
the September 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.
The following tables summarize the Company's derivative financial instrument
position on its natural gas and oil production as of September 30, 2000:
BFC Contracts CEC Contracts
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtu per MMBtu Year MMBtu per MMBtu
------ --------- ----------- ----- ------- -----------
2000 522,000 $ 2.49 2000 183,000 $ 2.46
2001 1,543,000 $ 2.36 2001 391,000 $ 2.71
--------- -------
2,065,000 574,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
------ --------- ----------- ----- ------- -----------
2000 12,000 $ 20.14 2000 4 9,000 $ 25.37
As of September 30, 2000, the Company would have been required to pay $5,044,000
and $1,306,000 to exit the BFC and CEC contracts, respectively.
38
<PAGE>
In addition, the Company utilizes collars that establish a price between a floor
and ceiling to hedge natural gas and oil prices. As of September 30, 2000 CEC
had the following natural gas collars in place:
Average Average
Floor Ceiling
Year MMBtu per MMBtu per MMBtu
----------- ---------- ------------ ------------
2000 58,000 $ 3.50 $ 4.86
2001 85,000 $ 3.50 $ 4.86
As of September 30, 2000, the Company would have been required to pay $31,000
upon exiting these contracts.
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards 133, "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133). In June 1999, the FASB issued SFAS 137
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of SFAS 133," which deferred SFAS 133's effective date to fiscal
years beginning after June 15, 2000. In June 2000, the FASB issued SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities,"
which amended SFAS 133. SFAS 133 establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) to be recorded in the balance sheet as
either an asset or liability at its fair value. The accounting for changes in
the fair value of a derivative depends on the intended use of the derivative and
the resulting designation.
The Company will adopt SFAS 133 effective January 1, 2001. If the Company's
derivative financial instruments qualify for special hedge accounting treatment
under SFAS 133, changes in fair value will be recognized in other comprehensive
income (a component of stockholders' equity) until settled, when the resulting
gains and losses will be recorded in earnings. Any hedge ineffectiveness will be
charged currently to earnings. The Company has not yet quantified the impacts of
adopting SFAS 133 on its financial statements. The affect on the Company's
earnings and other comprehensive income as a result of the adoption of SFAS 133
will vary from period to period and will be dependent upon prevailing oil and
gas prices, the volatility of forward prices for such commodities, the volumes
of production hedged and the time period covered by such hedges.
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.
39
<PAGE>
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: November 14, 2000 By /s/ Patrick R. McDonald
--------------------------------------
President and Chief Executive Officer
Date: November 14, 2000 By /s/ Kevin D. Struzeski
--------------------------------------
Treasurer and
Chief Financial Officer
40
<PAGE>
PART II - OTHER INFORMATION
Items 1 - 5. Not applicable
Item 6. (a) Exhibits
10.1 - Credit agreement dated as of September 22, 2000
between Bonneville Fuels Corporation and Wells Fargo
Bank West, National Association.*
10.2 Financing commitment dated as of September 15, 2000
between CEC Resources Ltd. and Canadian Imperial Bank
of Commerce.*
27 - Financial Data Schedule*
(b) No reports on Form 8-K were filed by the registrant
during the quarter ended September 30, 2000.
*Filed herewith
41
