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 March 31, 2001
----------------------------------------
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number: 1-15639
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CARBON ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
Colorado 84-1515097
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1700 Broadway, Suite 1150, Denver, CO 80290
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(Address of principal executive offices) (Zip Code)
(303) 863-1555
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(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 May 14, 2001
--------------------------------- ---------------------------------------
Common stock, no par value 6,088,592 shares
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited)
MARCH 31, DECEMBER 31,
2001 2000
------------- -------------
ASSETS
Current assets:
Cash $ - $ 21,000
Current portion of employee trust 632,000 683,000
Accounts receivable, trade 7,076,000 6,129,000
Accounts receivable, other 572,000 337,000
Amounts due from broker 2,463,000 3,871,000
Prepaid expenses and other 369,000 701,000
------------- -------------
Total current assets 11,112,000 11,742,000
------------- -------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 6,830,000 6,576,000
Proved properties 46,740,000 49,547,000
Furniture and equipment 435,000 398,000
------------- -------------
54,005,000 56,521,000
Less accumulated depreciation, depletion and amortization (7,446,000) (6,152,000)
------------- -------------
Property and equipment, net 46,559,000 50,369,000
------------- -------------
Deposits and other assets 364,000 369,000
------------- -------------
Total assets $ 58,035,000 $ 62,480,000
============= =============
The accompanying notes are an integral part of these financial statements.
2
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS - (CONTINUED)
(unaudited)
MARCH 31, DECEMBER 31,
2001 2000
------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 7,103,000 $ 9,583,000
Accrued production taxes payable 532,000 637,000
Income taxes payable 681,000 228,000
Undistributed revenue 1,967,000 1,561,000
Derivative liability 3,954,000 -
------------- -------------
Total current liabilities 14,237,000 12,009,000
------------- -------------
Long-term debt 10,432,000 15,082,000
Deferred income taxes 1,928,000 2,984,000
Minority interest 24,000 170,000
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
6,033,917 shares and 6,021,626 shares outstanding
at March 31, 2001 and December 31, 2000, respectively 31,561,000 31,495,000
Retained earnings 1,981,000 965,000
Accumulated other comprehensive income (2,128,000) (225,000)
------------- -------------
Total stockholders' equity 31,414,000 32,235,000
------------- -------------
Total liabilities and stockholders' equity $ 58,035,000 $ 62,480,000
============= =============
The accompanying notes are an integral part of these financial statements.
3
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
THREE MONTHS ENDED
MARCH 31,
---------------------------------
2001 2000
------------- -------------
Revenues:
Oil and gas sales $ 8,794,000 $ 3,177,000
Marketing and other, net 687,000 56,000
------------- -------------
9,481,000 3,233,000
Expenses:
Oil and gas production costs 2,546,000 1,022,000
Depreciation, depletion and amortization
expense 1,388,000 1,150,000
General and administrative expense, net 1,096,000 551,000
Interest expense, net 186,000 195,000
------------- -------------
Total operating expenses 5,216,000 2,918,000
Minority interest 22,000 3,000
------------- -------------
Income before income taxes 4,243,000 312,000
Income taxes:
Current 719,000 58,000
Deferred 998,000 24,000
------------- -------------
Total taxes 1,717,000 82,000
------------- -------------
Net income before cumulative effect of
accounting change 2,526,000 230,000
Cumulative effect of accounting change, net of tax (1,510,000) -
------------- -------------
Net income $ 1,016,000 $ 230,000
============= =============
Earnings per share:
Basic $ 0.17 $ 0.04
Diluted 0.16 0.04
Average number of common shares outstanding (in thousands):
Basic 6,026 5,237
Diluted 6,246 5,274
The accompanying notes are an integral part of these financial statements.
4
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 2001
(unaudited)
ACCUMULATED
COMMON STOCK OTHER
------------------------- RETAINED COMPREHENSIVE
SHARES AMOUNT EARNINGS INCOME TOTAL
--------- ------------ ------------ ------------- ------------
Balances, December 31, 2000 6,021,626 $ 31,495,000 $ 965,000 $ (225,000) $ 32,235,000
Comprehensive income:
Net income before cumulative effect
of accounting change - - 2,526,000 - 2,526,000
Cumulative effect of accounting change,
net of tax - - (1,510,000) (2,768,000) (4,278,000)
Currency translation adjustment - - - (378,000) (378,000)
Reclassification adjustment for settled contracts - - - 727,000 727,000
Changes in fair value of outstanding hedging
positions - - - 516,000 516,000
------------
Total comprehensive income (887,000)
------------
Common stock issued 6,666 36,000 - - 36,000
Vesting of restricted stock grants 5,625 30,000 - - 30,000
--------- ------------ ------------ ------------- ------------
Balances, March 31, 2001 6,033,917 $ 31,561,000 $ 1,981,000 $(2,128,000) $ 31,414,000
========= ============ ============ ============= ============
The accompanying notes are an integral part of these financial statements.
5
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(unaudited)
THREE MONTHS ENDED
MARCH 31,
---------------------------------------
2001 2000
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Cash flows from operating activities:
Net income before cumulative effect
of accounting change $ 2,526,000 $ 230,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 1,388,000 1,150,000
Deferred income tax 998,000 -
Minority interest 22,000 3,000
Employee stock grants 30,000 -
Changes in operating assets and liabilities net of
effects of acquisition:
Decrease (increase) in:
Accounts receivable (1,222,000) 456,000
Amounts due from broker 1,408,000 (932,000)
Employee trust 51,000 332,000
Prepaid expenses and other 330,000 (235,000)
Increase (decrease) in:
Accounts payable and accrued expenses (1,674,000) (1,486,000)
Undistributed revenue 465,000 (21,000)
------------- ------------
Net cash provided by (used in) operating activities 4,322,000 (503,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (6,335,000) (1,520,000)
Cash received from San Juan property sale 6,758,000 -
Acquisition of CEC Resources - (199,000)
Capital expenditures for support equipment (24,000) (83,000)
------------- ------------
Net cash provided by (used in) investing activities 399,000 (1,802,000)
Cash flows from financing activities:
Proceeds from note payable 19,227,000 2,722,000
Principal payments on note payable (23,745,000) (1,163,000)
Proceeds from issuance of common stock 36,000 55,000
CEC share repurchase (203,000) -
------------- ------------
Net cash provided by (used in) financing activities (4,685,000) 1,614,000
------------- ------------
Effect of exchange rate changes on cash (57,000) (7,000)
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Net decrease in cash (21,000) (698,000)
Cash, beginning of period 21,000 995,000
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Cash, end of period $ - $ 297,000
============= ============
Supplemental cash flow information:
Cash paid for interest $ 255,000 $ 196,000
Cash paid for taxes 263,000 -
The accompanying notes are an integral part of these financial statements.
6
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
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 for exchange. This
acquisition closed on February 17, 2000 and was also 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 core 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 core areas in Canada include the Carbon Field area of 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 March 31, 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.
AMOUNTS DUE FROM BROKER - This account generally represents net cash
margin deposits held by a brokerage firm for the Company's futures
accounts.
7
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.
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 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. The current portion of 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 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.
8
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 gas to end users which is produced from
the Company's properties and/or acquired from third parties.
INCOME TAXES - The Company accounts for income taxes under the liability
method which requires recognition of deferred tax assets and liabilities for
the expected future tax consequences of events that have been included in the
financial statements or tax returns. Under this method, deferred tax assets
and liabilities are determined based on the difference between the financial
statement and tax basis of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse.
HEDGING TRANSACTIONS - The Company 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. It
is the policy of the Company that the Risk Management Committee approves 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 related 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.
In June 1998, the Financial Accounting Standards Board issue SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded on the balance sheet as either an asset or
liability measured at its fair value. It also requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company must
formally document, designate and assess the effectiveness of transactions
that receive hedge accounting treatment. SFAS No. 133 is effective for all
fiscal quarters of fiscal years beginning after June 15, 2000.
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 liabilities for
principle (derivative loss) $ 1.5
During the first quarter of 2001, net hedging losses of $1.2 million
($727,000 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 $956,000 ($516,000 after tax). As of
March 31, 2001, the Company had net unrealized hedging losses of $2.5 million
($1.5 million 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 March 31, 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 680,000 $ 2.17 $ (2,068) 2001 275,000 $ 2.21 $ (752)
Collars:
CEC Contracts
------------------------------------------------------------------
Derivative
Average Average Asset/
Floor Ceiling (Liability)
Year MMBtu per MMBtu per MMBtu (thousands)
---- ------ ----------- ------------- ---------------
2001 203,00 $ 4.51 $ 5.70 $ 4
10
With the adoption of FAS 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 March 31, 2001.
Swaps:
BFC Contracts
------------------------------------------------------------------
Weighted Derivative
Average Asset/
Fixed Price (Liability)
Year MMBtu per MMBtu (thousands)
----- ------- -------------- -------------
2001 428,000 $ 2.04 $ (1,138)
During the first quarter of 2001, payments of $827,000 were made to the
counterparty of this contract. The fair market value of this contract
increased by $621,000 and was recognized as other income.
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 $378,000 for the three months ended March 31, 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 quarters ended March 31, 2001 and 2000.
Three Months Ended March 31,
--------------------------------
2001 2000
----------- ---------
(in thousands)
Net income $ 1,016 $ 230
Other comprehensive income (loss), net of tax:
Currency translation adjustment (378) (7)
Cumulative effect of changes in
accounting principle - January 1, 2001 (2,768) -
Reclassification adjustment for settled contracts 727 -
Changes in fair value of outstanding hedging positions 516 -
----------- ---------
Other comprehensive income (loss) (1,903) (7)
=========== =========
Comprehensive income (loss) $ (887) $ 223
=========== =========
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 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. 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.
THREE MONTHS
ENDED
MARCH 31, 2000
----------------
(unaudited)
Total revenue $ 5,424,000
Net income $ 348,000
Earnings per share:
Basic $ 0.06
Diluted $ 0.06
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
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 $16.1 million with outstanding borrowings of $7.7 million at March 31,
2001. 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
13
1.75% or Wells Fargo Bank West Prime, at the option of the Company. The
Company's average borrowing rate was approximately 7.2% at March 31, 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 - The facility with the Canadian Imperial Bank of Commerce
(CIBC), has a borrowing base of approximately $4.4 million with outstanding
borrowings of $2.7 million at March 31, 2001. The Canadian facility is secured
by the Canadian oil and gas properties of the Company. The revolving phase of
the Canadian facility expired on December 31, 2000 and the Company is currently
in negotiations with CIBC to extend the revolving phase to October 2001.
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 April 2002 at the earliest. As such, no amounts under the CEC
facility have been classified as current in the March 31, 2001 balance sheet.
The Canadian facility bears interest at the CIBC Prime rate plus 3/4%. The rate
was approximately 7.5% at March 31, 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 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. The Company currently
utilizes the swap facility to hedge its Canadian production.
14
5. 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.
Three Months Three Months
Ended Ended
March 31, 2001 March 31, 2001 Consolidated
United States Canada Totals
------------------- ------------------ -----------------
Oil and gas sales $ 3,801,000 $ 4,993,000 $ 8,794,000
Marketing and other, net 687,000 - 687,000
------------------- ------------------ -----------------
Total revenues 4,488,000 4,993,000 9,481,000
Oil and gas production costs 843,000 1,703,000 2,546,000
Depreciation and depletion 737,000 651,000 1,388,000
General and administrative expense, net 620,000 476,000 1,096,000
Interest expense, net 132,000 54,000 186,000
------------------- ------------------ -----------------
Total operating expenses 2,332,000 2,884,000 5,216,000
Minority interest in net income - 22,000 22,000
Income taxes 809,000 908,000 1,717,000
------------------- ------------------ -----------------
Net income before cumulative effect
of accounting change 1,347,000 1,179,000 2,526,000
Cumulative effect of accounting change, net of tax (1,510,000) - (1,510,000)
------------------- ------------------ -----------------
Net income (loss) $ (163,000) $ 1,179,000 $ 1,016,000
=================== ================== =================
------------------- ------------------ -----------------
Total assets $ 39,496,000 $ 18,539,000 $ 58,035,000
=================== ================== =================
15
For the Period
Three Months from February 18
Ended through
March 31, 2000 March 31, 2000 Consolidated
United States Canada Totals
------------------ ------------------ ------------------
Oil and gas sales $ 2,430,000 $ 747,000 $ 3,177,000
Marketing and other, net 56,000 - 56,000
------------------ ------------------ ------------------
Total revenues 2,486,000 747,000 3,233,000
Oil and gas production costs 826,000 196,000 1,022,000
Depreciation and depletion 945,000 205,000 1,150,000
General and administrative expense, net 438,000 113,000 551,000
Interest expense, net 172,000 23,000 195,000
------------------ ------------------ ------------------
Total operating expenses 2,381,000 537,000 2,918,000
Minority interest in net income - 3,000 3,000
Income taxes - 82,000 82,000
------------------ ------------------ ------------------
Net income $ 105,000 $ 125,000 $ 230,000
================== ================== ==================
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
The following table shows comparative revenue, sales, volumes, average sales
prices, expenses and the percentage change between periods for the three months
ended March 31, 2001 and 2000 for the Company's United States operations
conducted through BFC. The Company's Canadian operations were established in
February 2000 through an exchange offer of Carbon shares for shares of CEC
Resources. The following table shows comparative pro forma revenue, sales,
volumes, average sales prices, expenses and the percentage change between
periods as if the acquisition of CEC occurred on January 1, 2000.
United States Canada (1)
Three Months Ended Three Months Ended
March 31, March 31,
-------------------------------------- --------------------------------------
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 $ 3,179 $ 2,026 57% $ 4,411 $ 1,030 328%
Oil and liquids 622 404 54% 582 367 59%
Marketing and other, net 687 56 1127% - - n/a
------------- ---------- ----------- ------------
Total revenues 4,488 2,486 81% 4,993 1,397 257%
Sales volumes:
Natural gas (MMcf) 607 845 -28% 795 445 79%
Oil and liquids (Bbl) 21,490 16,252 32% 21,914 15,284 43%
Average price received:
Natural gas (Mcf) $ 5.24 $ 2.40 118% $ 5.55 $ 2.31 140%
Oil and liquids (Bbl) 28.94 24.86 16% 26.56 24.01 11%
Direct lifting costs $ 291 $ 411 -29% $ 526 $ 188 180%
Average direct lifting costs/Mcfe 0.40 0.44 -9% 0.57 0.35 63%
Other production costs 552 415 33% 1,177 167 605%
General and administrative, net $ 620 $ 438 42% $ 476 $ 227 110%
Depreciation, depletion and amortization 737 945 -22% 651 409 59%
Interest expense, net 132 172 -23% 54 44 23%
Income tax 809 - n/a 908 140 549%
------------------------
(1) Volumetric sales figures for Canadian activities are presented net
before royalty interests.
Revenues for oil and gas sales of BFC for the first quarter of 2001 were $3.8
million, a 56% 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.
17
Revenues for oil, liquids and gas sales of CEC for the first quarter of 2001
were $5.0 million, a 257% 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 first quarter of 2001 was 239 barrels of oil
per day and 6.7 million cubic feet (MMcf) of gas per day, a decrease of 22%
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 50% of the decrease in U.S. natural
gas production compared to 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 the successful
drilling activities conducted during the fourth quarter of 2000 and the first
quarter of 2001 in the Permian Basin, partially offset by natural production
declines. During the first quarter of 2001, 9 gross wells and 5.3 net wells
were drilled compared to 4 gross wells and 2.6 net wells in 2000.
CEC's average production for the first quarter of 2001 was 243 barrels of oil
and liquids per day and 8.9 MMcf of gas per day, an increase of 72% 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 quarter of 2001, 3 gross and net
wells were drilled. CEC did not have any drilling activity during the
comparable period in 2000.
Average oil prices realized by BFC increased 16% from $24.86 per barrel for
first quarter of 2000 to $28.94 for 2001. The average oil price includes hedge
losses of $43,000 for the first quarter of 2000. There was no oil hedge activity
for 2001. Average natural gas prices realized by BFC increased 118% from $2.40
per Mcf for the first quarter of 2000 to $5.24 for 2001. The average natural gas
price includes hedge losses of $529,000 for the first quarter of 2001 compared
to hedge gains of $100,000 for 2000.
Average oil and liquids prices realized by CEC increased 11% from $24.01 per
barrel for the first quarter of 2000 to $26.56 for 2001. The average oil price
includes hedge losses of $16,000 for the first quarter of 2000. There was no oil
hedge activity for 2001. Average natural gas prices realized by CEC increased
140% from $2.31 per Mcf for the first quarter of 2000 to $5.55 for 2001. The
average natural gas price includes hedge losses of $720,000 for the first
quarter of 2001 compared to hedge losses of $17,000 for 2000.
Marketing and other revenue realized by BFC was $687,000 for the first quarter
of 2001, compared to $56,000 for 2000. This increase was due to mark-to-market
gains of $621,000 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 133, 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 $291,000 or $.40 per Mcfe for the
first quarter of 2001 compared to $411,000 or $.44 per Mcfe for 2000. The per
Mcfe decrease was primarily due to well workovers in the Permian and Piceance
Basins performed in 2000.
18
Other production costs incurred by BFC consisting of production taxes and
overhead, were $552,000 for the first quarter of 2001 compared to $415,000 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 $526,000 or $.57 per Mcfe for the
first quarter of 2001 compared to $188,000 or $.35 per Mcfe for 2000. The
increase was primarily due to increased compression costs, increases in chemical
costs to optimize new production and a prior period adjustment for gas
processing fees.
Other production costs incurred by CEC consisting of net Crown and other royalty
expense were $1.2 million for the first quarter of 2001 compared to $167,000 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 incurred by BFC net of overhead
reimbursements, increased 42% from $438,000 for the first quarter of 2000 to
$620,000 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 overhead formerly billed on the Company's
San Juan Basin properties which were sold in January 2001.
General and administrative expenses incurred by CEC net of overhead
reimbursements, increased 110% from $227,000 for the first quarter of 2000 to
$476,000 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 23% from $172,000 for the first
quarter of 2000 to $132,000 for 2001. The decrease was due primarily to the
proceeds received from the divestiture of the Company's San Juan Basin
properties.
Interest expense incurred by CEC increased 23% from $44,000 for the first
quarter of 2000 to $54,000 for 2001. The increase was due primarily to
increased borrowings for drilling and development activity.
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 incurred by BFC decreased 22% from $945,000 for the first quarter
of 2000 to $737,000 for 2001. The decrease was due primarily to decreased
production. DD&A expense was $1.00 per Mcfe for the first quarters of 2001 and
2000.
19
DD&A expense incurred by CEC increased 59% from $409,000 for the first quarter
of 2000 to $651,000 for 2001. The increase was due primarily to increased
production. DD&A expense was $.76 per Mcfe for the first quarter of 2000
compared to $.70 per Mcfe for 2001.
Income tax expense incurred by BFC was $809,000 for the first quarter of 2001,
an effective tax rate of 38%. BFC did not record a provision for income taxes
for the first quarter of 2000.
Income tax expense incurred by CEC was $908,000 for the first quarter of
2001, an effective tax rate of 43% compared to $140,000 and an effective tax
rate of 39% for 2000.
FINANCIAL CONDITION AND CAPITAL RESOURCES
At March 31, 2001, Carbon had $58.0 million of assets. Total capitalization
was $41.8 million, consisting of 75% of stockholders' equity and 25% 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 $16.1 million with outstanding borrowings of $7.7 million at March 31,
2001. 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 7.2% at
March 31, 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 - The facility with the Canadian Imperial Bank of Commerce
(CIBC), has a borrowing base of approximately $4.4 million with outstanding
borrowings of $2.7 million at March 31, 2001. The Canadian facility is secured
by the Canadian oil and gas properties of the Company. The revolving phase of
the Canadian facility expired on December 31, 2000 and the Company is currently
in negotiations with CIBC to extend the revolving phase to October 2001.
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 April 2002 at the earliest. As such, no amounts under the CEC
facility have been classified as current in the March 31, 2001 balance sheet.
The Canadian facility bears interest at the CIBC Prime rate plus 3/4%. The rate
was approximately 7.5% at March 31, 2001.
20
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. The Company currently
utilizes the swap facility to hedge its Canadian production.
For the three months ended March 31, 2001, net cash provided by operating
activities was $4.3 million compared to net cash used in operating activities
of $503,000 in 2000. The increase is due primarily to increases in net income
and non-cash charges to net income in 2001 compared to 2000. Net cash
provided by investing activities was $399,000 for the three months ended
March 31, 2001 compared to net cash used in investing activities of $1.8
million for 2000. Included in the cash provided by investing activities for
the three months ended March 31, 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. The proceeds initially were used to
repay debt.
Carbon's primary cash requirements will be to finance acquisitions, exploration
and development expenditures, repay debt, and for 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. 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 $19.5 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.
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 however, whether
any financing can be accomplished on terms that are acceptable to the Company.
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
21
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
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 March 31, 2001, the Company had $7.7 million of floating rate debt through
its facility with Wells Fargo Bank West and $2.7 million through its facility
with CIBC. Assuming constant debt levels, earnings and cash flow impacts for the
next twelve month period from March 31, 2001 due to a one percent change in
interest rates would be approximately $77,000 before taxes for the facility with
Wells Fargo Bank West and $27,000 before taxes for the facility with the CIBC.
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.
22
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. It is the policy of the Company
that the Risk Management Committee approves 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 related 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 March 31, 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 680,000 $ 2.17 $ (2,068) 2001 275,000 $ 2.21 $ (752)
Collars:
CEC Contracts
-----------------------------------------------------------------------------
Derivative
Average Average Asset/
Floor Ceiling (Liability)
Year MMBtu per MMBtu per MMBtu (thousands)
------ ----------- ------------- ------------ ---------------
2001 203,000 $ 4.51 $ 5.70 $ 4
23
With the adoption of FAS 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 March 31, 2001.
Swaps:
BFC Contracts
----------------------------------------------------------------
Weighted Derivative
Average Asset/
Fixed Price (Liability)
Year MMBtu per MMBtu (thousands)
------- --------- ------------- -----------------
2001 428,000 $ 2.04 $ (1,138)
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.
24
PART II - OTHER INFORMATION
ITEM 1. Not applicable.
ITEM 2. Changes in Securities and Use of Proceeds
During the quarter ended March 31, 2001, the Company issued
6,666 shares of its common stock upon the exercise of
outstanding options held by officers or employees of its
subsidiaries. The exercise prices for these options resulted in
aggregate proceeds to the Company of $36,000 in cash. The Company
believes that these sales of common stock were exempt under
Section 4(2) of the Securities Act of 1933 and Rule 506 of
Regulation D.
ITEMS 3 - 5. Not applicable
ITEM 6. (a) Exhibits
(b) No reports on Form 8-K were filed by the registrant during the
quarter ended March 31, 2001.
25
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: May 15, 2001 By /s/ Patrick R. McDonald
------------------------------------------
President and Chief Executive Officer
Date: May 15, 2001 By /s/ Kevin D. Struzeski
------------------------------------------
Treasurer and
Chief Financial Officer
26