UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
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
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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
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(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 latest practicable date.
Class Outstanding at August 10, 2001
-------------------------- ------------------------------
Common stock, no par value 6,105,592 shares
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands)
JUNE 30, DECEMBER 31,
2001 2000
----------- ------------
(unaudited)
ASSETS
Current assets:
Cash $ - $ 21
Current portion of employee trust 640 683
Accounts receivable, trade 5,063 6,129
Accounts receivable, other 654 337
Amounts due from broker 707 3,871
Prepaid expenses and other 952 701
---------- ----------
Total current assets 8,016 11,742
---------- ----------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 7,576 6,576
Proved properties 51,367 49,547
Furniture and equipment 879 398
---------- ----------
59,822 56,521
Less accumulated depreciation, depletion and amortization (8,985) (6,152)
---------- ----------
Property and equipment, net 50,837 50,369
---------- ----------
Deposits and other assets 286 369
---------- ----------
Total assets $ 59,139 $ 62,480
========== ==========
The accompanying notes are an integral part of these financial statements.
2
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands except share data)
JUNE 30, DECEMBER 31,
2001 2000
----------- ------------
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 4,700 $ 9,583
Accrued production taxes payable 549 637
Income taxes payable 1,352 228
Undistributed revenue 1,575 1,561
Derivative liability 1,035 -
---------- ------------
Total current liabilities 9,211 12,009
---------- ------------
Long-term debt 12,618 15,082
Deferred income taxes 2,866 2,984
Minority interest 27 170
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
6,063,142 shares and 6,021,626 shares outstanding
at June 30, 2001 and December 31, 2000, respectively 31,715 31,495
Retained earnings 3,285 965
Accumulated other comprehensive income (583) (225)
---------- ------------
Total stockholders' equity 34,417 32,235
---------- ------------
Total liabilities and stockholders' equity $ 59,139 $ 62,480
========== ============
The accompanying notes are an integral part of these financial statements.
3
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands except per share data)
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ----------------
2001 2000 2001 2000
------ ------ ------- ------
(unaudited)
Revenues:
Oil and gas sales $6,325 $3,852 $15,119 $7,029
Marketing and other, net 565 51 1,252 107
------ ------ ------- ------
6,890 3,903 16,371 7,136
Expenses:
Oil and gas production costs 1,835 1,226 4,381 2,248
Depreciation, depletion and amortization 1,448 1,367 2,836 2,517
General and administrative, net 1,218 755 2,314 1,306
Interest, net 224 265 410 460
------ ------ ------- ------
Total operating expenses 4,725 3,613 9,941 6,531
Minority interest 3 4 25 7
------ ------ ------- ------
Income before income taxes 2,162 286 6,405 598
Income taxes:
Current 769 107 1,488 165
Deferred 89 61 1,087 85
------ ------ ------- ------
Total taxes 858 168 2,575 250
------ ------ ------- ------
Net income before cumulative effect of
change in accounting principle 1,304 118 3,830 348
Cumulative effect of change in accounting principle,
net of tax - - (1,510) -
------ ------ ------- ------
Net income $1,304 $ 118 $ 2,320 $ 348
====== ====== ======= ======
Earnings per share:
Basic $ 0.22 $ 0.02 $ 0.38 $ 0.06
Diluted 0.21 0.02 0.37 0.06
Average number of common shares outstanding:
Basic 6,048 6,011 6,037 5,624
Diluted 6,336 6,054 6,291 5,662
The accompanying notes are an integral part of these financial statements.
4
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2001
(in thousands)
ACCUMULATED
COMMON STOCK OTHER
---------------- RETAINED COMPREHENSIVE
SHARES AMOUNT EARNINGS INCOME TOTAL
------ ------- -------- ------------- -------
Balances, December 31, 2000 6,022 $31,495 $ 965 $ (225) $32,235
Comprehensive income:
Net income before cumulative effect
of change in accounting principle - - 3,830 - 3,830
Cumulative effect of change in accounting principle,
net of tax - (1,510) (2,768) (4,278)
Currency translation adjustment - - - (43) (43)
Reclassification adjustment for settled contracts - - - 1,093 1,093
Changes in fair value of outstanding hedge positions - - - 1,360 1,360
-------
Total comprehensive income 1,962
-------
Common stock issued 30 157 - - 157
Vesting of restricted stock grants 11 63 - - 63
------ ------- -------- ------------- -------
Balances, June 30, 2001 (unaudited) 6,063 $31,715 $ 3,285 $ (583) $34,417
====== ======= ======== ============= =======
The accompanying notes are an integral part of these financial statements.
5
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
SIX MONTHS ENDED
JUNE 30,
--------------------------------------
2001 2000
--------------------------------------
(unaudited)
Cash flows from operating activities:
Net income $ 2,320 $ 348
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 2,836 2,517
Change in fair market value of derivatives (1,116) -
Deferred income tax 1,087 -
Cumulative effect of change in accounting principle 1,510 -
Minority interest 25 7
Vesting of restricted stock grants 63 57
Changes in operating assets and liabilities net of effects of
acquisition:
Decrease (increase) in:
Accounts receivable 1,135 769
Amounts due from broker 3,164 (2,372)
Employee trust 43 561
Prepaid expenses and other 6 (249)
Increase (decrease) in:
Accounts payable and accrued expenses (3,620) (2,240)
Undistributed revenue 32 258
------------ -----------
Net cash provided by (used in) operating activities 7,485 (344)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (11,256) (3,833)
Cash received from San Juan property sale 6,758 -
Acquisition of CEC Resources - (144)
Capital expenditures for support equipment (464) (145)
------------ -----------
Net cash used in investing activities (4,962) (4,122)
Cash flows from financing activities:
Proceeds from notes payable 30,796 6,080
Principal payments on notes payable (33,227) (2,314)
Proceeds from issuance of common stock 157 55
CEC share repurchase (203) -
------------ -----------
Net cash provided by (used in) financing activities (2,477) 3,821
------------ -----------
Effect of exchange rate changes on cash (67) (207)
------------ -----------
Net decrease in cash (21) (852)
Cash, beginning of period 21 995
------------ -----------
Cash, end of period $ - $ 143
============ ===========
Supplemental cash flow information:
Cash paid for interest $ 538 $ 499
Cash paid for taxes 384 11
-------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
6
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS:
NATURE OF OPERATION - 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 to exchange. The offer
to exchange closed on February 17, 2000 and was accounted for as a purchase.
In November 2000, CEC initiated an offer to purchase shares of CEC stock that
were not owned by Carbon. The offer was completed in February 2001 with the
acquisition of approximately 34,000 of the 39,000 shares of CEC stock that
were not owned by Carbon. Carbon currently owns 99.7% of the stock of CEC.
Collectively, Carbon, CEC, BFC and its subsidiaries are referred to as the
Company. Carbon is an independent oil and gas company engaged in the
exploration, development and production of natural gas and crude oil in the
United States and Canada. The Company's exploration and production areas in
the United States include the Piceance Basin in Colorado, the Uintah Basin in
Utah, the Permian Basin in New Mexico and Texas and the Hugoton Basin in
Southwest Kansas. The Company's exploration and production areas in Canada
include Central Alberta and Southeast Saskatchewan.
The unaudited financial statements presented herein have been prepared pursuant
to the rules and regulations of the Securities and Exchange Commission ("SEC").
The statements do not include certain information and note disclosures required
by generally accepted accounting principles for complete financial statements.
The accompanying consolidated financial statements of the Company should be read
in conjunction with the consolidated financial statements and notes thereto
included in the Company's Annual Report on Form 10-K, for the year ended
December 31, 2000, as filed with the SEC. The statements reflect all adjustments
which, in the opinion of management, are necessary to fairly present the
Company's financial position at June 30, 2001 and the results of operations and
cash flows for the periods presented.
All amounts are presented in U.S. dollars unless otherwise stated.
2. SIGNIFICANT ACCOUNTING PRINCIPLES:
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 99.7% 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.
7
AMOUNTS DUE FROM BROKER - This account represents net cash margin deposits held
by a brokerage firm for the Company's derivative 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 oil and gas 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 and costs 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 capitalized 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 may be used to
satisfy obligations to persons who have been, or will be, terminated as a
result of the Company's acquisition of BFC. The employee trust is expected to
be disbursed or returned to the Company by October 31, 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
8
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 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 to end users gas 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 from time to time uses certain financial
instruments in an attempt to reduce exposure to the market fluctuations in
the price of oil and natural gas. The Company's general strategy is to hedge
price and location risk of a portion of the Company's production with swap,
collar, futures, and floor and ceiling arrangements. The Company generally
enters into hedges for delivery into one of several pipelines located near
producing regions of the Company. Pursuant to Company guidelines, the Company
is to engage in these activities only as a hedging mechanism. The Company has
a Risk Management Committee to administer its production hedging program and
approve all production hedging transactions. Gains or losses from financial
instruments that qualify for hedge accounting treatment are recognized as an
adjustment to sales revenue when the transactions being hedged are finalized.
Gains or losses from financial instruments that do not qualify for hedge
accounting treatment are recognized currently as other income or expense. The
cash flows from these instruments are included in operating activities in the
consolidated statements of cash flows.
The Company follows Statement of Financial Accounting Standards (SFAS) No.
133, "Accounting for Derivative Instruments and Hedging Activities" which
provides 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 treatment. SFAS No. 133 became effective for the Company on
January 1, 2001.
9
The table below sets forth the financial statement impact to the Company of
recording derivative instruments designated as hedges and derivative instruments
not designated as hedges upon the adoption of SFAS No. 133 on January 1, 2001.
Amount
(millions)
----------
Balance Sheet:
Derivative liability $ (7.2)
Deferred tax asset 2.9
Cumulative effect of a change in accounting principle (other comprehensive loss) 2.8
Statement of Operations:
Cumulative effect of a change in accounting principle (derivative loss) $ 1.5
During the first six months of 2001, net hedging losses of $1.9 million ($1.1
million after tax) were transferred from other comprehensive income and the
change in the fair market value of outstanding derivative liabilities for
contracts designated as hedges decreased by $2.4 million ($1.4 million after
tax). As of June 30, 2001, the Company had net unrealized hedging losses of
$764,000 ($315,000 after tax). The Company expects to reclassify these losses to
earnings during the next twelve month period.
The table below sets forth BFC's and CEC's derivative financial instrument
positions that qualify for hedge accounting treatment on its natural gas
production as of June 30, 2001.
Futures and swaps:
BFC Contracts CEC Contracts
--------------------------------------------------------- ----------------------------------------------------
Weighted Derivative Weighted Derivative
Average Asset/ Average Asset/
Fixed Price (Liability) Fixed Price (Liability)
Year MMBtu per MMBtu (thousands) Year MMBtu per MMBtu (thousands)
------------------------------------------------------------------------------------------------------------------
2001 370,000 $ 2.18 $ (786) 2001 158,000 $ 2.29 $ (25)
Collars:
CEC Contracts
----------------------------------------------------------------------------
Derivative
Average Average Asset/
Floor Ceiling (Liability)
Year MMBtu per MMBtu per MMBtu (thousands)
----------- ------------ --------------- --------------- --------------
2001 123,000 $ 4.45 $ 5.62 $ 171
10
With the adoption of SFAS No. 133, the Company has a derivative contract that
no longer qualifies for hedge accounting treatment. The table below sets
forth the position of this contract as of June 30, 2001:
Swaps:
BFC Contracts
-----------------------------------------------------------
Weighted Derivative
Average Asset/
Fixed Price (Liability)
Year MMBtu per MMBtu (thousands)
-----------------------------------------------------------
2001 246,000 $ 2.04 $ (167)
During the first six months of 2001, payments of $1.3 million were made to the
counterparty of this contract. The fair market value of this contract increased
by $1.1 million and was recognized as other income.
During the first six months of 2001, the Company entered into Permian Basin
basis swaps that do not qualify for hedge accounting treatment. The value of
these contracts were $67,000 as of June 30, 2001. At June 30, 2001, basis
swaps covering 290,000 MMBtu were outstanding and expire on or before
October 31, 2001.
FOREIGN CURRENCY TRANSLATION - Foreign currency transactions and financial
statements are translated in accordance with SFAS No. 52 "Foreign Currency
Translation". The Company uses the U.S. dollar as its functional currency,
except for CEC, which uses the Canadian dollar. Assets and liabilities related
to the operations of CEC are generally translated at current exchange rates, and
related translation adjustments are reported as a component of accumulated other
comprehensive income in the statement of stockholders' 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 U.S. dollar, the
Company reported a non cash currency translation loss of $43,000 for the six
months ended June 30, 2001.
11
COMPREHENSIVE INCOME - The Company follows the provisions of SFAS No. 130,
"Reporting Comprehensive Income." Comprehensive income includes net income and
certain items recorded directly to shareholders' equity and classified as other
comprehensive income. The following table sets forth the calculation of
comprehensive income for the six months ended June 30, 2001 and 2000.
Six Months Ended June 30,
----------------------------
2001 2000
--------- --------
(in thousands)
Net income $ 2,320 $ 348
Other comprehensive income (loss), net of tax:
Currency translation adjustment (43) (130)
Cumulative effect of changes in
accounting principle - January 1, 2001 (2,768) -
Reclassification adjustment for settled contracts 1,093 -
Changes in fair value of outstanding hedge positions 1,360 -
--------- --------
Other comprehensive income (loss) (358) (130)
--------- --------
Comprehensive income (loss) $ 1,962 $ 218
========= ========
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.
12
3. ACQUISITION AND DISPOSITION OF ASSETS:
ACQUISITION OF CEC RESOURCES LTD. - On February 17, 2000, Carbon completed
the acquisition of approximately 97% of the stock of CEC. An offer to
exchange shares of Carbon stock for shares of 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. As stated in Note 1 to the
financial statements, in February 2001, CEC acquired approximately 34,000 of
the 39,000 shares of CEC stock that were not owned by Carbon. Carbon
currently owns 99.7% of the stock of CEC.
The following unaudited pro forma information presents a summary of the
consolidated results of operations as if the acquisition had occurred at January
1, 2000.
SIX MONTHS
ENDED
JUNE 30, 2000
--------------
(unaudited)
Total revenue $ 7,786,000
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 January 1, 2000, or future
results of operations of the consolidated entities.
DISPOSITION OF OIL AND GAS ASSETS - In January 2001, the Company closed the
sale of its entire working interest and related leasehold rights in the San
Juan Basin, receiving net proceeds of approximately $6.8 million. The
proceeds were used to repay amounts outstanding under the Company's credit
facilities and to finance the Company's exploration and development program.
4. LONG-TERM DEBT:
UNITED STATES 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 $17.8 million with outstanding borrowings of $10.3 million at June 30,
2001. The borrowing base is subject to a $500,000 per month reduction schedule
through November 1, 2001, at which time the borrowing base will be $15.3
million. 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 October 1, 2006,
13
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
Company's average borrowing rate was approximately 5.9% at June 30, 2001. 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 - In June 2001, the Company secured an increase in the
borrowing base of the facility with the Canadian Imperial Bank of Commerce
(CIBC) to approximately $9.2 million from approximately $4.3 million.
Outstanding borrowings against the facility were $2.3 million at June 30, 2001.
The Canadian facility is secured by the Canadian oil and gas properties of the
Company. The revolving phase of the Canadian facility expires on August 31, 2001
and the Company is currently in negotiations with CIBC to extend the revolving
phase to April 1, 2002. However, there can be no guarantee that the Company will
be able to successfully negotiate such an extension. 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. However,
subject to possible changes in the borrowing base, CIBC has agreed that it will
not require the Company to make any principal payments under the term loan
section of the facility until July 2002 at the earliest. As such, no amounts
under the Canadian facility have been classified as current in the June 30, 2001
balance sheet. The Canadian facility bears interest at the CIBC Prime rate plus
0.5%. The rate was approximately 6.75% at June 30, 2001.
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 provides for $3.5 million of credit for
commodity swaps covering a portion of the Company's oil and gas production,
forward exchange contracts and firm gas purchase and sales transactions. The
Company currently utilizes the swap facility to hedge its Canadian production
(See Note 2).
14
5. BUSINESS AND GEOGRAPHICAL SEGMENTS:
Segment information has been prepared in accordance with SFAS No. 131,
"Disclosures about Segments of an Enterprise and Related Information". 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.
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, 2001 JUNE 30, 2001
------------------------------------- --------------------------------------
United United
States Canada Total States Canada Total
-------- --------- -------- ------- ------- --------
Revenues:
Oil and gas sales $ 2,469 $ 3,856 $ 6,325 $ 6,270 $ 8,849 $ 15,119
Marketing and other, net 565 - 565 1,252 - 1,252
-------- --------- -------- ------- ------- --------
3,034 3,856 6,890 7,522 8,849 16,371
Expenses:
Oil and gas production costs 976 859 1,835 1,819 2,562 4,381
Depreciation, depletion and amortization 804 644 1,448 1,541 1,295 2,836
General and administrative, net 767 451 1,218 1,387 927 2,314
Interest, net 185 39 224 317 93 410
-------- --------- -------- ------- ------- --------
Total operating expenses 2,732 1,993 4,725 5,064 4,877 9,941
Minority interest - 3 3 - 25 25
-------- --------- -------- ------- ------- --------
Income before income taxes 302 1,860 2,162 2,458 3,947 6,405
Income taxes 113 745 858 922 1,653 2,575
-------- --------- -------- ------- ------- --------
Net income before cumulative effect of
change in accounting principle 189 1,115 1,304 1,536 2,294 3,830
Cumulative effect of change in accounting
principle, net of tax - - - (1,510) - (1,510)
-------- --------- -------- ------- ------- --------
Net income $ 189 $ 1,115 $ 1,304 $ 26 $ 2,294 $ 2,320
======== ========= ======== ======= ======= ========
Total assets $ 39,938 $ 19,201 $ 59,139 $ 39,938 $ 19,201 $ 59,139
======== ========= ======== ======= ======= ========
15
SIX
MONTHS FEB. 18
ENDED THROUGH
THREE MONTHS ENDED JUNE 30, JUNE 30,
JUNE 30, 2000 2000 2000
------------------------------------ -----------------------------------
United United
States Canada Total States Canada Total
------- ------- ------- ------- ------- -------
Revenues:
Oil and gas sales $ 2,249 $ 1,603 $ 3,852 $ 4,679 $ 2,350 $ 7,029
Marketing and other, net 51 - 51 107 - 107
------- ------- ------- ------- ------- -------
2,300 1,603 3,903 4,786 2,350 7,136
Expenses:
Oil and gas production costs 790 436 1,226 1,616 632 2,248
Depreciation, depletion and amortization 905 462 1,367 1,850 667 2,517
General and administrative, net 433 322 755 871 435 1,306
Interest, net 210 55 265 382 78 460
------- ------- ------- ------- ------- -------
Total operating expenses 2,338 1,275 3,613 4,719 1,812 6,531
Minority interest - 4 4 - 7 7
------- ------- ------- ------- ------- -------
Income before income taxes (38) 324 286 67 531 598
Income taxes - 168 168 - 250 250
------- ------- ------- ------- ------- -------
Net income $ (38) $ 156 $ 118 $ 67 $ 281 $ 348
======= ======= ======= ======= ======= =======
------- ------- ------- ------- ------- -------
Total assets $40,599 $14,269 $54,868 $40,599 $14,269 $54,868
======= ======= ======= ======= ======= =======
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
The following table and the discussion that follows present comparative
revenue, sales, volumes, average sales prices, expenses and the percentage
change between periods for the three months ended June 30, 2001 and 2000 (second
quarter) for the Company's United States operations conducted through BFC and
the Company's Canadian operations conducted through CEC.
United States Canada (1)
Three Months Ended Three Months Ended
June 30, June 30,
--------------------------------------- ---------------------------------------
2001 2000 Change 2001 2000 Change
---------- ------------ ------------- -------------- ----------- --------
(Dollars in thousands, except (Dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
Revenues:
Natural gas $ 1,949 $ 1,843 6% $ 3,364 $ 1,255 168%
Oil and liquids 520 406 28% 492 348 41%
Marketing and other, net 565 51 1008% - - n/a
--------- ------------- ---------- ----------
Total revenues 3,034 2,300 32% 3,856 1,603 141%
Sales volumes:
Natural gas (MMcf) 662 771 -14% 801 478 68%
Oil and liquids (Bbl) 19,533 17,245 13% 20,615 16,215 27%
Equivalent production (MMcfe 6:1) 779 874 -11% 925 575 61%
Daily sales volumes:
Natural gas (MMcf) 7.3 8.5 -14% 8.8 5.3 66%
Oil and liquids (Bbl) 215 190 13% 227 178 28%
Equivalent production (MMcfe 6:1) 8.6 9.6 -10% 10.2 6.3 62%
Average price received:
Natural gas (Mcf) $ 2.94 $ 2.39 23% $ 4.20 $ 2.63 60%
Oil and liquids (Bbl) 26.62 23.54 13% 23.87 21.46 11%
Direct lifting costs $ 489 $ 339 44% $ 271 $ 209 30%
Average direct lifting costs/Mcfe 0.63 0.39 62% 0.29 0.36 -19%
Other production costs 487 451 8% 588 227 159%
General and administrative, net 767 433 77% 451 322 40%
Depreciation, depletion and amortization 804 905 -11% 644 462 39%
Interest expense, net 185 210 -12% 39 55 -29%
Income tax 113 - n/a 745 168 343%
-------------------------
(1) Volumetric sales figures for Canadian activities are presented net before
royalty interests.
Revenues from oil and gas sales of BFC for the second quarter of 2001 were $2.5
million, a 10% increase from 2000. The increase was due primarily to increased
oil and gas prices partially
17
offset by natural production declines in all operating areas and the
divestiture in January 2001 of the Company's entire working interests and
related leasehold rights in the San Juan Basin.
Revenues from oil, liquids and gas sales of CEC for the second quarter of 2001
were $3.9 million, a 141% increase from the prior year period. The increase was
due primarily to increased oil, liquid and gas production and higher oil,
liquids and gas prices.
BFC's average production for the second quarter of 2001 was 215 barrels of
oil per day and 7.3 million cubic feet (MMcf) of gas per day, a decrease of
10% from the same period in 2000 on a Mcf equivalent (Mcfe) basis where one
barrel of oil is equal to six Mcf of gas. In January 2001, the Company
divested its entire working interests and related leasehold rights in the San
Juan Basin. This accounted for substantially all of the decrease in U.S.
natural gas production compared to the second quarter of 2000. The increase
in oil production was due to successful drilling activities conducted during
2001 in the Permian Basin, partially offset by natural production declines.
During the second quarter of 2001, BFC participated in the drilling of 6
gross wells and 2.5 net wells compared to 4 gross wells and 3.1 net wells in
2000.
CEC's average production for the second quarter of 2001 was 227 barrels of
oil and liquids per day and 8.8 MMcf of gas per day, an increase of 62% on an
Mcfe basis from the same period in 2000. The increase was due primarily to
successful drilling and recompletion activities in the Carbon and Rowley
areas of Central Alberta. During the second quarter of 2001, CEC participated
in the drilling of 2 gross and 2 net wells. CEC did not have any drilling
activity during the comparable period in 2000.
Average oil prices realized by BFC increased 13% from $23.54 per barrel for
the second quarter of 2000 to $26.62 for 2001. The average oil price includes
hedge losses of $59,000 for the second quarter of 2000. There was no oil
hedge activity for 2001. Average natural gas prices realized by BFC increased
23% from $2.39 per Mcf for the second quarter of 2000 to $2.94 for 2001. The
average natural gas price includes hedge losses of $757,000 for the second
quarter of 2001 compared to hedge losses of $541,000 for 2000.
Average oil and liquids prices realized by CEC increased 11% from $21.46 per
barrel for the second quarter of 2000 to $23.87 for 2001. The average oil price
includes hedge losses of $35,000 for the second quarter of 2000. There was no
oil hedge activity for 2001. Average natural gas prices realized by CEC
increased 60% from $2.63 per Mcf for the second quarter of 2000 to $4.20 for
2001. The average natural gas price includes hedge losses of $202,000 for the
second quarter of 2001 compared to hedge losses of $168,000 for 2000.
Marketing and other revenue realized by BFC was $565,000 for the second
quarter of 2001, compared to $51,000 for 2000. This increase was primarily
due to mark-to-market gains of $451,000 on a derivative contract that no
longer qualified for hedge accounting treatment upon the adoption of SFAS No.
133 on January 1, 2001. In conjunction with the adoption of SFAS No. 133 on
January 1, 2001, the Company recorded a derivative loss (net of tax) of $1.5
million as the cumulative effect of a change in accounting principle related
to this derivative contract.
Direct lifting costs incurred by BFC were $489,000 or $.63 per Mcfe for the
second quarter of 2001 compared to $339,000 or $.39 per Mcfe for 2000. The
increase was primarily
18
due to well workovers and equipment repairs in the Permian and Piceance
Basins performed in the second quarter of 2001.
Other production costs incurred by BFC consisting of production taxes and
overhead, were $487,000 for the second quarter of 2001 compared to $451,000 for
2000. The increase was primarily due to higher severance taxes due to higher
prices, partially offset by declines in gas production.
Direct lifting costs incurred by CEC were $271,000 or $.29 per Mcfe for the
second quarter of 2001 compared to $209,000 or $.36 per Mcfe for 2000.
Other production costs incurred by CEC consisting of net Crown and other royalty
expense were $588,000 for the second quarter of 2001 compared to $227,000 for
2000. The increase was due to a rise in net Crown royalties due to higher oil
and gas prices and increased production.
General and administrative expenses net of overhead reimbursements incurred
by BFC increased 77% from $433,000 for the second quarter of 2000 compared
to $767,000 for 2001. The increase was primarily due to personnel additions
and consulting costs in conjunction with the Company's higher level of
capital expenditures, salary increases, and a reduction in overhead
reimbursements as a result of the sale of the Company's San Juan Basin
properties.
General and administrative expenses net of overhead reimbursements incurred
by CEC increased 40% from $322,000 for the second quarter of 2000 to
$451,000 for 2001. The increase was primarily due to personnel additions and
consulting costs in conjunction with the Company's higher level of capital
expenditures and salary increases.
Interest expense incurred by BFC decreased 12% from $210,000 for the second
quarter of 2000 to $185,000 for 2001. The decrease was due primarily to a
reduction in debt as a result of proceeds received from the divestiture of
the Company's San Juan Basin properties, decreased margin deposits related to
the Company's derivative position, and a decline in interest rates, partially
offset by increased funding requirements for capital expenditures.
Interest expense incurred by CEC decreased 29% from $55,000 for the second
quarter of 2000 to $39,000 for 2001. The decrease was due primarily to a
reduction in debt as a result of increased cashflow from operating activities
and a decline in interest rates, partially offset by increased funding
requirements for capital expenditures.
Depreciation, depletion and amortization (DD&A) of the Company's oil and gas
assets is determined based upon the units of production method. This expense
is typically based on the 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 its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
19
DD&A expense incurred by BFC decreased 11% from $905,000 for the second
quarter of 2000 to $804,000 for 2001. The decrease was due primarily to
decreased production. DD&A expense was $1.03 per Mcfe for the second quarter
of 2001 compared to $1.04 for 2000.
DD&A expense incurred by CEC increased 39% from $462,000 for the second quarter
of 2000 to $644,000 for 2001. The increase was due primarily to increased
production. DD&A expense was $.70 per Mcfe for the second quarter of 2001
compared to $.80 per for 2000.
Income tax expense incurred by BFC was $113,000 for the second quarter of 2001,
an effective tax rate of 38%. BFC did not record a provision for income taxes
for the second quarter of 2000.
Income tax expense incurred by CEC was $745,000 for the second quarter of 2001,
an effective tax rate of 40% compared to $168,000 and an effective tax rate of
51% for 2000.
20
The following table and the discussion that follows present comparative
revenue, sales, volumes, average sales prices, expenses and the percentage
change between periods for the six months ended June 30, 2001 and 2000. The
Company's Canadian operations were established in February 2000 through an
exchange offer of Carbon shares for shares of CEC. The following table is a
pro forma presentation, as if the acquisition of CEC occurred on January 1,
2000.
United States Canada (1)
Six Months Ended Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2001 2000 Change 2001 2000 Change
--------- -------- -------- --------- -------- ---------
(Dollars in thousands, except (Dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
Revenues:
Natural gas $ 5,127 $ 3,869 33% $ 7,775 $ 2,281 241%
Oil and liquids 1,143 810 41% 1,074 719 49%
Marketing and other, net 1,252 107 1070% - - n/a
--------- -------- --------- --------
Total revenues 7,522 4,786 57% 8,849 3,000 195%
Sales volumes:
Natural gas (MMcf) 1,270 1,616 -21% 1,596 923 73%
Oil and liquids (Bbl) 41,023 33,497 22% 42,529 31,499 35%
Equivalent production (MMcfe 6:1) 1,516 1,817 -17% 1,851 1,112 66%
Daily sales volumes:
Natural gas (MMcf) 7.0 8.9 -21% 8.8 5.1 73%
Oil and liquids (Bbl) 227 184 23% 235 173 36%
Equivalent production (MMcfe 6:1) 8.4 10.0 -16% 10.2 6.1 67%
Average price received:
Natural gas (Mcf) $ 4.04 $ 2.39 69% $ 4.87 $ 2.47 97%
Oil and liquids (Bbl) 27.86 24.18 15% 25.25 22.83 11%
Direct lifting costs $ 780 $ 742 5% $ 796 $ 397 101%
Average direct lifting costs/Mcfe 0.51 0.41 24% 0.43 0.36 19%
Other production costs 1,039 874 19% 1,766 394 348%
General and administrative, net 1,387 871 59% 927 549 69%
Depreciation, depletion and
amortization 1,541 1,850 -17% 1,295 871 49%
Interest expense, net 317 382 -17% 93 99 -6%
Income tax 922 - n/a 1,653 308 437%
---------------------------
(1) Volumetric sales figures for Canadian activities are presented net before
royalty interests.
Revenues from oil and gas sales of BFC for the first six months of 2001 were
$6.3 million, a 34% increase from 2000. The increase was due primarily to
increased oil and gas prices partially offset by natural production declines in
all operating areas and the divestiture in January 2001 of the Company's entire
working interests and related leasehold rights in the San Juan Basin.
Revenues from oil, liquids and gas sales of CEC for the first six months of 2001
were $8.8 million, a 195% increase from the prior year period. The increase was
due primarily to increased oil, liquid and gas production and higher oil,
liquids and gas prices.
21
BFC's average production for the first six months of 2001 was 227 barrels of
oil per day and 7.0 million cubic feet (MMcf) of gas per day, a decrease of
16% from the same period in 2000 on a Mcf equivalent (Mcfe) basis where one
barrel of oil is equal to six Mcf of gas. In January 2001, the Company
divested its entire working interests and related leasehold rights in the San
Juan Basin. This accounted for more than 60% of the decrease in U.S. natural
gas production compared to the first six months of 2000. The remainder of the
decline is primarily due to production declines in all areas. The decrease in
natural gas production was partially offset by successful drilling activity
in the Piceance Basin. The increase in oil production was due to successful
drilling activities conducted during 2001 in the Permian Basin, partially
offset by natural production declines. During the first six months of 2001,
BFC participated in the drilling of 15 gross wells and 7.8 net wells compared
to 8 gross wells and 5.7 net wells in 2000.
CEC's average production for the first six months of 2001 was 235 barrels of
oil and liquids per day and 8.8 MMcf of gas per day, an increase of 67% on an
Mcfe basis from the same period in 2000. The increase was due primarily to
successful drilling and recompletion activities in the Carbon and Rowley
areas of Central Alberta. During the first six months of 2001, CEC
participated in the drilling of 5 gross and 5 net wells. CEC did not have any
drilling activity during the comparable period in 2000.
Average oil prices realized by BFC increased 15% from $24.18 per barrel for
first six months of 2000 to $27.86 for 2001. The average oil price includes
hedge losses of $102,000 for the first six months of 2000. There was no oil
hedge activity for 2001. Average natural gas prices realized by BFC increased
69% from $2.39 per Mcf for the first six months of 2000 to $4.04 for 2001.
The average natural gas price includes hedge losses of $1.3 million for the
first six months of 2001 compared to hedge losses of $402,000 for 2000.
Average oil and liquids prices realized by CEC increased 11% from $22.83 per
barrel for the first six months of 2000 to $25.25 for 2001. The average oil
price includes hedge losses of $51,000 for the first six months of 2000.
There was no oil hedge activity for 2001. Average natural gas prices realized
by CEC increased 97% from $2.47 per Mcf for the first six months of 2000 to
$4.87 for 2001. The average natural gas price includes hedge losses of
$921,000 for the first six months of 2001 compared to hedge losses of
$185,000 for 2000.
Marketing and other revenue realized by BFC was $1.3 million for the first
six months of 2001, compared to $107,000 for 2000. This increase was
primarily due to mark-to-market gains of $1.1 million on a derivative
contract that no longer qualified for hedge accounting treatment upon the
adoption of SFAS No. 133 on January 1, 2001. In conjunction with the adoption
of SFAS No. 133 on January 1, 2001, the Company recorded a derivative loss
(net of tax) of $1.5 million as the cumulative effect of a change in
accounting principle related to this derivative contract.
Direct lifting costs incurred by BFC were $780,000 or $.51 per Mcfe for the
first six months of 2001 compared to $742,000 or $.41 per Mcfe for 2000. The per
Mcfe increase was primarily due to well workovers and equipment repairs in the
Permian and Piceance Basins performed in 2001.
22
Other production costs incurred by BFC consisting of production taxes and
overhead, were $1.0 million for the first six months of 2001 compared to
$874,000 for 2000. The increase was primarily due to higher severance taxes due
to higher prices, partially offset by declines in gas production.
Direct lifting costs incurred by CEC were $796,000 or $.43 per Mcfe for the
first six months of 2001 compared to $397,000 or $.36 per Mcfe for 2000.
Other production costs incurred by CEC consisting of net Crown and other royalty
expense were $1.8 million for the first six months of 2001 compared to $394,000
for 2000. The increase was due to a rise in net Crown royalties due to higher
oil and gas prices and increased production.
General and administrative expenses net of overhead reimbursements incurred
by BFC increased 59% from $871,000 for the first six months of 2000 to $1.4
million for 2001. The increase was primarily due to personnel additions and
consulting costs in conjunction with the Company's higher level of capital
expenditures, salary increases, and a reduction in overhead reimbursements as
a result of the sale of the Company's San Juan Basin properties.
General and administrative expenses net of overhead reimbursements incurred
by CEC increased 69% from $549,000 for the first six months of 2000 to
$927,000 for 2001. The increase was primarily due to personnel additions and
consulting costs in conjunction with the Company's higher level of capital
expenditures and salary increases.
Interest expense incurred by BFC decreased 17% from $382,000 for the first
six months of 2000 to $317,000 for 2001. The decrease was due primarily to
a reduction in debt as a result of proceeds received from the divestiture
of the Company's San Juan Basin properties, decreased margin deposits related
to the Company's derivative position and a decrease in interest rates,
partially offset by increased funding requirements for capital expenditures.
Interest expense incurred by CEC decreased 6% from $99,000 for the first six
months of 2000 to $93,000 for 2001. The decrease was due primarily to a
reduction in debt as a result of increased cash flow from operating
activities and a decline in interest rates, partially offset by increased
funding requirements for capital expenditures.
Depreciation, depletion and amortization (DD&A) of the Company's oil and gas
assets is determined based upon the units of production method. This expense
is typically based on the 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 its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
DD&A expense incurred by BFC decreased 17% from $1.9 million for the first six
months of 2000 to $1.5 million for 2001. The decrease was due primarily to
decreased production. DD&A expense was $1.02 per Mcfe for the first six months
of 2001 and 2000.
23
DD&A expense incurred by CEC increased 49% from $871,000 for the first six
months of 2000 to $1.3 million for 2001. The increase was due primarily to
increased production. DD&A expense was $.70 per Mcfe for the first six months of
2001 compared to $.78 for 2000.
Income tax expense incurred by BFC was $922,000 for the first six months of
2001, an effective tax rate of 38%. BFC did not record a provision for income
taxes for the first six months of 2000.
Income tax expense incurred by CEC was $1.7 million for the first six months of
2001, an effective tax rate of 42% compared to $308,000 and an effective tax
rate of 45% for 2000.
CAPITAL RESOURCES AND LIQUIDITY
At June 30, 2001, Carbon had $59.1 million of assets. Total capitalization was
$47.0 million, consisting of 73% of stockholders' equity and 27% of debt.
UNITED STATES 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 $17.8 million with outstanding borrowings of $10.3 million at June 30,
2001. The borrowing base is subject to a $500,000 per month reduction schedule
through November 1, 2001, at which time the borrowing base will be $15.3
million. 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 October 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 Company's average borrowing rate was approximately 5.9% at
June 30, 2001. 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 - In June 2001, the Company secured an increase in the
borrowing base of the facility with the Canadian Imperial Bank of Commerce
(CIBC) to approximately $9.2 million from approximately $4.3 million.
Outstanding borrowings against the facility were $2.3 million at June 30, 2001.
The Canadian facility is secured by the Canadian oil and gas properties of the
Company. The revolving phase of the Canadian facility expires on August 31, 2001
and the Company is currently in negotiations with CIBC to extend the revolving
phase to April 1, 2002. However, there can be no guarantee that the Company will
be able to successfully negotiate such an extension. 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. However,
subject to possible changes in the borrowing base, CIBC has agreed that it
24
will not require the Company to make any principal payments under the term
loan section of the facility until July 2002 at the earliest. As such, no
amounts under the Canadian facility have been classified as current in the
June 30, 2001 balance sheet. The Canadian facility bears interest at the CIBC
Prime rate plus 0.5%. The rate was approximately 6.75% at June 30, 2001.
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 provides for $3.5 million of credit for
commodity swaps covering a portion of the Company's oil and gas production,
forward exchange contracts and firm gas purchase and sales transactions. The
Company currently utilizes the swap facility to hedge its Canadian production.
For the six months ended June 30, 2001, net cash provided by operating
activities was $7.5 million compared to net cash used in operating activities
of $344,000 in 2000. The increase is due primarily to increases in net income
and non-cash charges to net income and a decline in margin deposit
requirements for the Company's derivate accounts in 2001 compared to 2000.
Net cash used in investing activities was $5.0 for the six months ended June
30, 2001 compared to net cash used in investing activities of $4.1 million
for 2000. Included in the cash provided by investing activities for the six
months ended June 30, 2001, was $6.8 million in proceeds related to the
disposition of the Company's entire working interests and related leasehold
rights in the San Juan Basin.
Carbon's primary cash requirements will be to finance development and
exploration expenditures, finance acquisitions, repay debt, and for general
working capital needs. 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. In January
2001, Carbon closed the sale of its entire working interests and related
leasehold rights in the San Juan Basin. The proceeds from the sale after
adjustments were $6.8 million. The Company anticipates that capital
expenditures, exclusive of acquisitions (if any) or divestitures will
approximate $22.0 million in 2001. Carbon believes that available borrowings
under its credit agreements, the proceeds from the sale of San Juan
properties, projected operating cash flows and 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.
If necessary, 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 however,
whether any financing can be accomplished on terms that are acceptable to the
Company.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which addresses financial accounting and
reporting for business combinations. SFAS No. 141 is effective for all
business combinations initiated after June 30, 2001 and for all business
combinations accounted for under the purchase method initiated before but
completed after June 30, 2001. The adoption of SFAS No. 141 is not expected
to have a material impact on the Company's financial position or results of
oeprations.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which addresses financial accounting and reporting for goodwill and
other intangible assets. SFAS No. 142 is effective for fiscal years beginning
after December 15, 2001, and applies to all goodwill and other intangibles
recognized in the financial statements at that date. The adoption of SFAS No.
142 is not expected to have a material impact on the Company's financial
position or results of operations.
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,
25
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, Government
Regulation, Environmental Regulation and Operating Hazards sections of the
Company's 2000 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
The Company has risk exposure to interest rate volatility on its outstanding
debt. The sensitivity analysis that follows 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, 2001, the Company had $10.3 million
of floating rate debt through its facility with Wells Fargo Bank West and
$2.3 million through its facility with CIBC. Assuming constant debt levels,
earnings and cash flow impacts for the next twelve month period from June 30,
2001 due to a one percent change in interest rates would be approximately
$103,000 before taxes for the facility with Wells Fargo Bank West and $23,000
before taxes for the facility with the CIBC.
26
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. Worldwide political events can also impact commodity
prices. The Company from time to time uses certain financial instruments in
an attempt to reduce exposure to the market fluctuations in the price of oil
and natural gas. The Company's general strategy is to hedge price and
location risk of a portion of the Company's production with swap, collar,
futures, and floor and ceiling arrangements as described in Note 2 to the
financial statements. The Company generally enters into hedges for delivery
into one of several pipelines located near producing regions of the Company.
Pursuant to Company guidelines, the Company is to engage in these activities
only as a hedging mechanism. The Company has a Risk Management Committee to
administer its production hedging program and approve all production hedging
transactions. Gains or losses from financial instruments that qualify for
hedge accounting treatment are recognized as an adjustment to sales revenue
when the transactions being hedged are finalized. Gains or losses from
financial instruments that do not qualify for hedge accounting treatment are
recognized currently as other income or expense. The cash flows from such
agreements are included in operating activities in the consolidated
statements of cash flows.
The table below sets forth BFC's and CEC's derivative financial instrument
positions that qualify for hedge accounting treatment on its natural gas
production as of June 30, 2001.
Futures and Swaps:
BFC Contracts CEC Contracts
-------------------------------------------------------- ----------------------------------------------------
Weighted Derivative Weighted Derivative
Average Asset/ Average Asset/
Fixed Price (Liability) Fixed Price (Liability)
Year MMBtu per MMBtu (thousands) Year MMBtu per MMBtu (thousands)
---- ------- ----------- ----------- ---- ------- ----------- -----------
2001 370,000 $ 2.18 $ (786) 2001 158,000 $ 2.29 $ (25)
27
Collars:
CEC Contracts
----------------------------------------------------------------------------
Derivative
Average Average Asset/
Floor Ceiling (Liability)
Year MMBtu per MMBtu per MMBtu (thousands)
--------- --------- --------- --------- -----------
2001 123,000 $ 4.45 $ 5.62 $ 171
With the adoption of SFAS No. 133 on January 1, 2001, the Company has a
derivative contract that no longer qualifies for hedge accounting treatment.
The table below sets forth the position of this contract as of June 30, 2001.
Swaps:
BFC Contracts
-------------------------------------------------------------
Weighted Derivative
Average Asset/
Fixed Price (Liability)
Year MMBtu per MMBtu (thousands)
---------- -------- ----------- -----------
2001 246,000 $ 2.04 $ (167)
During the first six months of 2001, the Company entered into Permian Basin
basis swap contracts that do not qualify for hedge accounting treatment. The
value of these contracts were $67,000 as of June 30, 2001. At June 30, 2001,
basis swaps covering 290,000 MMBtu were outstanding and expire on or before
October 31, 2001.
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.
28
PART II - OTHER INFORMATION
ITEM 1-3 Not applicable
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On June 14, 2001, the Company held its 2001 Annual Meeting of Shareholders.
At that meeting, the six existing directors were nominated and re-elected as
directors of the Company. These six persons constitute all members of the
Board of Directors of the Company. These directors and the votes for and
withheld for each of them were as follows:
For Withheld Broker Non-Votes
-------- -------- ----------------
Patrick R. McDonald 6,042,052 0 21,467
Cortlandt S. Dietler 6,042,052 0 21,467
David H. Kennedy 6,042,052 0 21,467
Bryan H. Lawrence 6,042,052 0 21,467
Peter A. Leidel 6,042,052 0 21,467
Harry A. Trueblood, Jr. 6,042,052 0 21,467
In addition, at the 2001 Annual Meeting, the Company's shareholders ratified
the selection of Arthur Andersen LLP as independent auditors for 2001. The
votes at the 2001 Annual Meeting with respect to this ratification were as
follows:
For Against Abstained Broker Non-Votes
-------- ------- --------- ----------------
6,011,986 12,361 65 21,467
ITEM 5. Not applicable
ITEM 6. (a) Exhibits
10.1 - Credit agreement dated as of May 18, 2001 between CEC
Resources Ltd. and Canadian Imperial Bank of Commerce *
(b) No reports on Form 8-K were filed by the registrant during the
quarter ended June 30, 2001.
*Filed herewith
29
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, 2001 By /s/ Patrick R. McDonald
-------------------------------------
President and Chief Executive Officer
Date: August 14, 2001 By /s/ Kevin D. Struzeski
-------------------------------------
Treasurer and
Chief Financial Officer
30