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, 2000
------------------------------------
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to ______________________
Commission File Number: 1-15639
------------------------------------
CARBON ENERGY CORPORATION
--------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Colorado 84-1515097
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1700 Broadway, Suite 1150, Denver, CO 80290
- ---------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
(303) 863-1555
---------------------------------------------------------------------
(Registrant's telephone number, including area code)
Not Applicable
----------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at May 10, 2000
- -------------------------- -------------------------------
Common stock, no par value 6,042,826 shares
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
2000 1999
-------------------- --------------------
ASSETS (unaudited)
------
Current assets:
Cash $ 297,000 $ 995,000
Current portion of employee trust 580,000 881,000
Accounts receivable, trade 2,553,000 2,286,000
Accounts receivable, other 654,000 69,000
Amounts due from broker 2,182,000 1,250,000
Prepaid expenses and other 341,000 107,000
-------------------- --------------------
Total current assets 6,607,000 5,588,000
-------------------- --------------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 8,156,000 7,879,000
Proved properties 38,764,000 25,020,000
Furniture and equipment 297,000 214,000
-------------------- --------------------
47,217,000 33,113,000
-------------------- --------------------
Less accumulated depreciation, depletion and amortization (1,779,000) (627,000)
Property and equipment, net 45,438,000 32,486,000
-------------------- --------------------
Other assets:
Deferred acquisition costs - 310,000
Deposits and other 246,000 245,000
Employee trust 638,000 669,000
-------------------- --------------------
Total other assets 884,000 1,224,000
-------------------- --------------------
Total assets $ 52,929,000 $ 39,298,000
==================== ====================
The accompanying notes are an integral part of these financial statements.
2
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS - (continued)
March 31, December 31,
2000 1999
-------------------- --------------------
LIABILITIES AND STOCKHOLDERS' EQUITY (unaudited)
------------------------------------
Current liabilities:
Accounts payable and accrued expenses $ 4,321,000 $ 4,391,000
Accrued production taxes payable 350,000 367,000
Income taxes payable 72,000 -
Undistributed revenue 577,000 598,000
-------------------- --------------------
Total current liabilities 5,320,000 5,356,000
-------------------- --------------------
Long-term debt 13,258,000 9,100,000
Other long-term liabilities 450,000 527,000
Deferred income taxes 2,614,000 -
-------------------- --------------------
Total long-term liabilities 16,322,000 9,627,000
-------------------- --------------------
Commitments and contingencies (Note 5)
Minority interest 150,000 -
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
6,007,736 shares and 4,510,000 shares outstanding 31,405,000 24,806,000
at March 31, 2000 and December 31, 1999 respectively
Accumulated deficit (261,000) (491,000)
Currency translation adjustment (7,000) -
-------------------- --------------------
Total stockholders' equity 31,137,000 24,315,000
-------------------- --------------------
Total liabilities and stockholders' equity $ 52,929,000 $ 39,298,000
==================== ====================
The accompanying notes are an integral part of these financial statements.
3
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
Three Months
Ended
March 31, 2000
--------------------
(unaudited)
Revenues:
Oil and gas sales $ 3,177,000
Gas marketing and transportation 1,485,000
Other 48,000
--------------------
4,710,000
Expenses:
Oil and gas production costs 1,022,000
Gas marketing and transportation costs 1,477,000
Depreciation, depletion and amortization expense 1,150,000
General and administrative expense, net 551,000
Interest expense, net 195,000
--------------------
Total operating expenses 4,395,000
Minority interest in net income 3,000
--------------------
Income before income taxes 312,000
Income taxes:
Current 58,000
Deferred 24,000
--------------------
Net income $ 230,000
====================
Earnings per share:
Basic $ .04
Diluted .04
Average number of common shares
outstanding (in thousands):
Basic 5,237
Diluted 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, 2000
Currency
Common Stock Accumulated Translation
---------------------------------
Shares Amount Deficit Adjustment Total
-------------- ---------------- ----------------- ------------------- --------------
Balances, December 31, 1999 4,510,000 $ 24,806,000 $ (491,000) - $ 24,315,000
Issuance of common stock 1,497,736 6,599,000 - - 6,599,000
Currency translation adjustment - - - $ (7,000) (7,000)
Net income - - 230,000 - 230,000
-------------- ---------------- ----------------- ------------------- ----------------
Balances, March 31, 2000 6,007,736 $ 31,405,000 $ (261,000) $ (7,000) $ 31,137,000
============== ================ ================= =================== =================
The accompanying notes are an integral part of these financial statements.
5
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
Three Months
Ended
March 31, 2000
--------------------
(unaudited)
Cash flows from operating activities:
Net income $ 230,000
Adjustments to reconcile net income to net cash
used in operating activities:
Depreciation, depletion and amortization expense 1,150,000
Currency translation adjustment (7,000)
Minority interest 3,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable 456,000
Amounts due from broker (932,000)
Employee trust 332,000
Prepaid expenses and other (234,000)
Other assets (1,000)
Increase (decrease) in:
Accounts payable and accrued expenses (1,486,000)
Undistributed revenue (21,000)
--------------------
Net cash used in operating activities (510,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (1,520,000)
Acquisition of CEC Resources (199,000)
Capital expenditures for support equipment (83,000)
--------------------
Net cash used in investing activities (1,802,000)
Cash flows from financing activities:
Proceeds from note payable, net of repayments 2,722,000
Principal payments on note payable (1,163,000)
Proceeds from issuance of common stock 55,000
--------------------
Net cash provided by financing activities 1,614,000
--------------------
Net decrease in cash (698,000)
Cash, beginning of period 995,000
--------------------
Cash, end of period $ 297,000
====================
Supplemental cash flow information:
Cash paid for interest $ 196,000
====================
The Company acquired 97.5% of the interest of CEC Resources in the period (Note 2).
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 and Significant Accounting Policies:
Carbon Energy Corporation (Carbon) was incorporated in September 1999 under the
laws of the State of Colorado to facilitate the acquisition of Bonneville Fuels
Corporation (BFC) and subsidiaries. The acquisition of BFC closed on October
29, 1999 and was accounted for as a purchase. In February 2000, Carbon completed
an offer to exchange shares of Carbon for shares of CEC Resources, Ltd. (CEC),
an Alberta, Canada company. Over 97% of the shareholders of CEC accepted the
offer for exchange. This acquisition closed on February 17, 2000 and was also
accounted for as a purchase as further described in Note 2. Collectively,
Carbon, CEC, BFC and its subsidiaries are referred to as the Company. The
Company's operations currently consist of the acquisition, exploration,
development, and production of oil and natural gas properties located primarily
in Colorado, Kansas, New Mexico, Utah, and the Canadian provinces of Alberta and
Saskatchewan.
The financial statements included herein have been prepared in conformity with
generally accepted accounting principles. The statements are unaudited but
reflect all adjustments which, in the opinion of the management, are necessary
to fairly present the Company's financial position at March 31, 2000 and the
results of operations and cash flows for the three month period ended March 31,
2000. The results of operations for interim periods are not necessarily
indicative of results to be expected for the full year.
All amounts are presented in U.S. dollars unless otherwise stated.
Principles of Consolidation - The consolidated financial statements include the
accounts of Carbon and its subsidiaries all of which are wholly owned, except
CEC in which the Company owns approximately 97% of the equity. All significant
intercompany transactions and balances are eliminated.
Cash Equivalents - The Company considers all highly liquid instruments with
original maturities of three months or less when purchased to be cash
equivalents.
Amounts Due From Broker - This account generally represents net cash margin
deposits held by a brokerage firm for the Company's futures accounts.
Property and Equipment - The Company follows the full cost method of accounting
for its oil and gas properties, all of which are located in the continental
United States and Canada. Under this method of accounting, all costs incurred
in the acquisition, exploration and development of properties (including costs
of surrendered and abandoned leaseholds, delay
7
lease rentals, dry holes and direct overhead related to exploration and
development activities) are capitalized.
Capitalized costs are depleted using the units of production method based on
proved reserves of oil and gas. For purposes of this calculation, oil and gas
reserves are converted to a common unit of measure on the basis of six thousand
cubic feet of gas to one barrel of oil. A reserve is provided for the estimated
future cost of site restoration, dismantlement and abandonment activities as a
component of depletion. Investments in unproved properties are recorded at the
lower of cost or fair market value and are not depleted pending the
determination of the existence of proved reserves.
Pursuant to full cost accounting rules, capitalized costs less related
accumulated depletion and deferred income taxes may not exceed the sum of (1)
the present value of future net revenue from estimated production of proved oil
and gas reserves using a 10% discount factor and unescalated oil and gas prices
as of the end of the period; plus (2) the cost of properties not being
amortized, if any; plus (3) the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less (4)
related income tax effects. The costs reflected in the accompanying financial
statements do not exceed this limitation.
Proceeds from disposal of interests in oil and gas properties are accounted for
as adjustments of capitalized costs with no gain or loss recognized, unless such
adjustment would significantly alter the rate of depletion.
Buildings, transportation and other equipment are depreciated on the straight-
line method with lives ranging from three to seven years.
Employee Trust - The employee trust represents amounts which will be used to
satisfy obligations to persons who have been, or will be, terminated as a result
of the Company's acquisition of BFC (see Note 4). The current portion of the
employee trust is expected to be disbursed by March 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.
The Company records sales and the related cost of sales on gas and electricity
marketing transactions using the accrual method of accounting (i.e., the
transaction is recorded when the commodity is purchased and/or delivered).
8
The Company's gas marketing contracts are generally month-to-month and provide
that the Company will sell gas to end users, which is produced from the
Company's properties and/or acquired from third parties.
Income Taxes - The Company accounts for income taxes under the liability method
which requires recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns. Under this method, deferred tax assets and
liabilities are determined based on the difference between the financial
statement and tax basis of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse.
Hedging Transactions - The Company periodically enters into commodity futures
and option contracts, fixed price swaps and basis swaps as hedges of commodity
prices associated with the production of oil and gas and with the purchase of
natural gas.
Pursuant to Company guidelines, the Company is to engage in these activities
only as a hedging mechanism against price volatility associated with gas or
crude oil sales in order to protect realized price levels. Changes in the
market value of futures, forwards, and swap contracts are not recognized until
the related production occurs or until the related gas purchase takes place.
Realized gains or losses from any positions which are closed early are deferred
and recorded as an asset or liability in the accompanying balance sheet, until
the related production, purchase or sale takes place. In the event energy
financial instruments do not qualify for hedge accounting, the difference
between the current market value and the original contract value would be
currently recognized in the statement of operations. Gains and losses incurred
on these contracts are included in oil and gas revenue or in gas marketing costs
in the accompanying statement of operations.
Upon the acquisition of BFC and CEC the Company assumed open hedge contracts
that when marked to market reflected an obligation of $1,733,000 and $539,000
respectively. These obligations were recorded as a liability. At March 31,
2000 these obligations were $1,231,000 and $523,000 for BFC and CEC,
respectively. These liabilities will decline as the contracts expire or if the
Company exits the position. The recorded liabilities related to hedge
positions that will mature within the next twelve months are included as current
liabilities. The following tables summarize BFC's and CEC's derivative
financial instrument positions on its natural gas and oil production as of March
31, 2000:
9
BFC Contracts CEC Contracts
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtus per MMBtu Year MMBtus per MMBtu
---- --------- ------------ ------ ---------- ------------
2000 1,842,500 $ 2.37 2000 783,000 $ 2.36
2001 1,543,000 $ 2.36 2001 304,000 $ 2.37
--------- ----------
3,385,500 1,087,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
---- --------- ------------ ------ ---------- ------------
2000 36,000 $ 21.47 2000 27,000 $ 22.35
As of March 31, 2000, the Company would have been required to pay $2,462,000 and
$849,000 to exit the BFC and CEC contracts, respectively.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133).
The Company is required to adopt SFAS No. 133 as of January 1, 2001, but may
implement it as of the beginning of any fiscal quarter prior to that date. SFAS
No. 133 cannot be applied retroactively. The Company has not yet quantified the
impacts of adopting SFAS No. 133 or determined the timing or methods of
adoption. However, SFAS No. 133 could increase the volatility of the Company's
earnings and comprehensive income.
Foreign Currency Translation - The functional currency of CEC, the Company's
approximately 97 percent owned Canadian subsidiary, is the Canadian dollar.
Assets and liabilities related to the Company's Canadian operations are
generally translated at current exchange rates, and related translation
adjustments are reported as a component of shareholders' equity. Income
statement accounts are translated at the average rates during the period. As a
result of the change in the value of the Canadian dollar relative to the US
dollar, the Company reported a non cash translation loss of $7,000 for the
three months ended March 31, 2000.
Earnings (Loss) Per Share - The Company uses the weighted average number of
shares outstanding in calculating earnings per share data. When dilutive,
options are included as share equivalents using the treasury stock method and
are included in the calculation of diluted per share data.
Accounting Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the amounts reported in these financial
statements and the accompanying notes. The actual results could differ from
those estimates.
10
2. Acquisition of CEC Resources Ltd.:
On February 17, 2000 Carbon completed the acquisition of approximately 97% of
the stock of CEC. An offer for exchange of Carbon stock for CEC stock resulted
in the issuance of 1,482,626 shares of Carbon stock to holders of CEC stock. The
acquisition was accounted for as a purchase.
The purchase price of $13,642,000 was comprised of the following:
Current liabilities $ 876,000
Open hedges 539,000
Deferred income taxes 2,679,000
Long term debt 2,522,000
Professional fees 508,000
Carbon common stock exchanged 6,518,000
----------------
Total purchase price $ 13,642,000
================
The following unaudited pro forma information presents a summary of the
consolidated results of operations as if the acquisition had occurred at the
beginning of the period presented. Because Carbon was not in existence at March
31, 1999, the pro forma information presented is for the three month period
ending March 31, 2000 only.
Three Months
Ended
March 31, 2000
--------------
(unaudited)
Total revenue $5,424,000
Net income $ 348,000
Earnings per share:
Basic $ .06
Dilutive .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 the beginning of the period
presented, or future results of operations of the consolidated entities.
3. Long-term Debt:
Debt consisted of the following at March 31, 2000:
U.S. facility $ 10,300
Canadian facility 2,958
---------
$ 13,258
Current portion -
---------
$ 13,258
The Company has an oil and gas asset-based line-of-credit with both a U.S. and
Canadian bank. The facility with U.S. Bank, N.A. had a borrowing base of $16.2
million with outstanding borrowings of $10.3 million at March 31, 2000. Letters
of credit totaling $1.8 million were issued at March 31, 2000 which reduces the
amount available for borrowings. The facility is secured by certain U.S. oil
and gas properties of the Company and is scheduled to have a maturity of either
the economic half life of the Company's remaining U.S. based reserves on the
date of conversion or July 1, 2001, whichever is earlier. The facility bears
interest at a rate equal to LIBOR plus 1.75% or prime, depending on the option
of the Company. The rate was approximately 7.7% at March 31, 2000. The borrowing
base is based upon the lender's evaluation of the Company's proved oil and gas
reserves, generally determined semi-annually.
The credit agreement contains various covenants which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is also
required to maintain certain financial ratios.
11
The facility with the Canadian Imperial Bank of Commerce (CIBC), had a borrowing
base of approximately $4.0 million with outstanding borrowings of $3.0 million
at March 31, 2000. The Canadian facility is secured by the Canadian oil and gas
properties of the Company. The revolving phase of the Canadian facility expired
on April 30, 2000 and is in the process of being renewed by the Company and the
bank. If the revolving commitment is not renewed, the loan would be converted
into a term loan and would be reduced by way of consecutive monthly payments
over a period not to exceed 36 months. The Canadian facility bears interest at
the Canadian prime rate plus 3/4%. The rate was approximately 7.75% at March 31,
2000.
The Canadian facility contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness, sell
properties, or merge with another entity.
The Company also has an accounts receivable-based credit facility which includes
a revolving line-of-credit with U.S. Bank, N.A. which provides for borrowings
and letters of credit up to $500,000. There were no outstanding borrowings or
letters of credit under this facility at March 31, 2000. This facility bears
interest at prime (9% at March 31, 2000). This facility is collateralized by
certain trade receivables of the Company and has a maturity date of July 1,
2001.
4. Salary Continuation Plan:
In 1999, BFC established a Salary Continuation Plan (the Plan). The Plan
provides for continuation of salary and health, dental, disability, and life
insurance benefits for a certain period of time based upon employment contracts
or length of service, if the employee is terminated within two years following
the effective date of BFC's acquisition by Carbon. The Plan was initially
funded with a deposit of $1,546,000 into an employee trust account.
Distributions through March 31, 2000 have been $357,000 for employees who were
terminated or had their employment contracts terminated. At March 31, 2000,
additional distributions in the amount of $580,000 will be made to these
employees within the next 12 months and the liabilities related to these
disbursements are included in current liabilities. The funds to meet this
obligation is included in current assets. The liabilities relating to these
employee terminations were recorded in 1999.
The employee trust account is restricted from disbursing funds except for the
payment of benefits or upon the insolvency of the Company. Trustee fees were
minimal for the period ended March 31, 2000. Any remaining amounts in the trust
will revert to the Company upon expiration of the trust.
12
5. Commitments and Contingencies:
Office Lease - The Company entered into lease agreements, which provides for
total minimum rental commitments as follows:
U.S. Canada
2000 - Remainder of year $ 145,000 $ 57,000
2001 197,000 86,000
2002 203,000 86,000
2003 208,000 79,000
2004 212,000 -
--------- --------
$ 965,000 $308,000
6. Stock Options and Award Plans:
In 1999, the Company adopted a stock option plan. All salaried employees of the
Company and its subsidiaries are eligible to receive both incentive stock
options and nonqualified stock options. Directors and consultants who are not
employees of the Company or its subsidiaries are eligible to receive non-
qualified stock options, but not incentive stock options under the plan. The
option price for the incentive stock options granted under the plan are not to
be less than 100% of the fair market value of the shares subject to the option.
The option price for the nonqualified stock options granted under the plan are
not to be less than 85% of the fair market value of the shares subject to the
options. The aggregate number of shares of common stock, which may be issued
under options granted pursuant to the plan, may not exceed 700,000 shares. A
total of 264,500 options outstanding under the CEC Incentive Share Option Plan
were exchanged for Carbon options upon the completion of the offer to exchange
shares of Carbon for shares of CEC. An additional 197,000 options were also
granted during the three months ended March 31, 2000.
The specific terms of grant and exercise is determined by the Company's Board of
Directors unless and until such time as the Board of Directors delegates the
administration of the plan to a committee. The options vest over a three year
period and expire ten years from the date of grant.
In 1999, the Company adopted a restricted stock plan for selected employees,
directors and consultants of the Company and its subsidiaries. The aggregate
number of shares of common stock which may be issued under the plan may not
exceed 300,000. The shares vest ratably over 36 months. Carbon recognized
compensation expense of $27,000 associated with the vesting of restricted stock
in the first quarter of 2000 and the Company has treated for financial
reporting purposes only vested shares as outstanding.
13
7. Income Taxes:
The income tax expense differs from amounts computed by applying the statutory
federal income tax rate for the following reasons:
Three Months
Ended
March 31, 2000
--------------
(in thousands)
Tax expense at 35% of income before income taxes $ 109
Change in the valuation allowance against deferred tax asset $ (37)
Tax expense of higher effective rate on Canadian income 20
Canadian resource allowance (53)
Canadian Crown payments (net of Alberta Royalty Tax Credit)
not deductible for tax purposes 39
Other 4
-----
$ 82
The net deferred tax liability by geographic area is comprised of the following:
March 31, 2000
--------------
United States Canada Total
------------- ------ -----
(in thousands)
Federal net operating loss carryforwards $ (615) -- $ (615)
Property and equipment 517 2,614 3,131
Other (37) (37)
Valuation allowance 135 135
-------- ----- ------
Net deferred tax liability $ -- $2,614 $2,614
======== ====== ======
As of March 31, 2000, the Company had a net operating loss carryforward for
federal income tax purpose of $1,758,000 which expires in 2020.
14
8. Major Customers:
During the three months ended March 31, 2000, revenue from two customers of the
Company represented approximately $672,000 and $539,000 of the Company's
consolidated revenues. Management believes that the loss of any individual
purchaser would not have a long-term material adverse impact on the financial
position or results of operations of the Company.
9. Properties Subject to Tax Credit Agreement:
During 1995, BFC entered into an agreement to sell 99% of its interest in 14
coal gas wells located in New Mexico that qualified for IRC section 29 tax
credits. Under the terms of the agreement BFC is to receive 99% of the net cash
flow on the properties until certain cumulative production levels have been
reached, at which time the purchaser will receive 100% of the net cash flow
until a subsequent production level is reached. Upon reaching the second target,
100% of the cash flows will revert to BFC for substantially the remaining life
of the properties. The first production level was reached in January 2000. Due
to these contractual agreements, BFC will not be entitled to sales proceeds or
be obligated for the cost of operations on these properties until an additional
235,000 mcf has been produced. The Company estimates this will take
approximately 15 months. During this 15 month period, the Company will still be
entitled to receive tax credit benefits estimated to be $150,000.
15
10. 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 were determined based upon the type of
operation in each segment and the geographical location in which each segment
operates. The segment data presented below was prepared on the same basis as
Carbon's consolidated financial statements.
For the period
from
Three Months Feb 18
Ended through
Mar 31, 2000 Mar 31, 2000
United Consolidated
States Canada Totals
------------------- ------------------- -------------------
Oil and gas sales $ 2,430,000 $ 747,000 $ 3,177,000
Gas marketing, transportation, and other 1,533,000 - 1,533,000
------------------- ------------------- -------------------
Total revenues 3,963,000 747,000 4,710,000
Oil and gas production costs 826,000 196,000 1,022,000
Gas marketing, transportation, and other 1,477,000 - 1,477,000
Depreciation and depletion 945,000 205,000 1,150,000
General and administrative, net 438,000 113,000 551,000
Interest expense, net 172,000 23,000 195,000
------------------- ------------------- -------------------
Total operating expenses 3,858,000 537,000 4,395,000
Minority interest in net income - 3,000 3,000
Income tax - 82,000 82,000
------------------- ------------------- -------------------
Net income $ 105,000 $ 125,000 $ 230,000
=================== =================== ===================
------------------- ------------------- -------------------
Property and equipment, net $ 32,675,000 $ 12,763,000 $ 45,438,000
=================== =================== ===================
16
BONNEVILLE FUELS CORPORATION
STATEMENT OF INCOME
(unaudited)
Three Months
Ended
March 31, 1999
--------------------
(unaudited)
Revenues:
Oil and gas sales $ 1,907,000
Gas marketing and transportation 7,517,000
Other 107,000
--------------------
9,531,000
--------------------
Expenses:
Oil and gas production costs 669,000
Gas marketing and transportation costs 7,383,000
Depreciation, depletion and amortization expense 487,000
General and administrative expense, net 436,000
Exploration expense 244,000
Interest expense, net 112,000
--------------------
Total operating expenses 9,331,000
Minority interest in net income
Income before income taxes 200,000
--------------------
Income taxes
Current 0
Deferred 0
--------------------
0
--------------------
NET INCOME $ 200,000
====================
The accompanying notes are an integral part of these financial statements.
17
BONNEVILLE FUELS CORPORATION
STATEMENT OF CASH FLOW
Three months
ended
March 31, 1999
-------------------
(unaudited)
Cash Flows from operating activities
Net income (loss) $ 200,000
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 487,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable, trade (23,000)
Amounts due from broker (139,000)
Prepaid expenses and other (107,000)
Other assets
Increase (decrease) in:
Accounts payable and accrued expenses (3,072,000)
Undistributed revenue 155,000
-------------------
Net cash provided by operating activities (2,499,000)
Cash flows from investing activities:
Capital expenditures for oil and gas properties (2,229,000)
Other net property and equipment (62,000)
Other assets (31,000)
-------------------
Net cash used in investing activities (2,322,000)
Cash flows from financing activities
Proceeds from note payable 2,650,000
Principal payments on note payable
-------------------
Net cash provided by (used in) financing activities 2,650,000
Net increase (decrease) in cash and equivalents (2,171,000)
Cash, beginning of year 2,742,000
Cash, end of year $ 571,000
===================
Supplemental disclosures of Cash Flow Information:
Cash paid for interest $ 103,000
====================
The accompanying notes are an integral part of these financial statements.
18
BONNEVILLE FUELS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Nature of Operations and Significant Accounting Policies:
Nature of Operation - Bonneville Fuels Corporation (BFC), a wholly owned
subsidiary of Bonneville Pacific Corporation (BPC), was incorporated in the
State of Colorado in April 1987 and began doing business in June 1987. The
Company owns four subsidiaries, Bonneville Fuels Marketing Corporation (BFMC),
Bonneville Fuels Management Corporation (BFM Corp.), Bonneville Fuels Operating
Corporation (BFO), and Colorado Gathering Corporation (CGC). Collectively,
these entities are referred to as the Company. The Company's principal
operations include exploration for and production of oil and gas reserves,
marketing of natural gas, and gathering of natural gas. The Company from time
to time also purchases and resells electricity.
Principles of Consolidation - The consolidated financial statements include the
accounts of BFC and its four wholly owned subsidiaries. All significant
intercompany transactions and balances have been eliminated in the accompanying
consolidated financial statements.
Cash Equivalents - The Company considers all highly liquid debt instruments
purchased with an original maturity of three months or less to be cash
equivalents.
Gas Marketing - the Company's marketing contracts are generally month-to-month
or up to eighteen months, and provide that the Company will sell gas to end
users which is produced from the Company's properties and acquired from third
parties.
Amounts Due from Broker - This account generally represents net cash margin
deposits held by a brokerage firm for the Company's trading accounts.
Oil and Gas Producing Activities - The Company follows the "successful efforts"
method of accounting for its oil and gas properties, all of which are located in
the continental United States. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are capitalized
when incurred, pending determination of whether the well has found proved
reserves. If an exploratory well has not found proved reserves, the costs of
drilling the well are charged to expense. The costs of development wells are
capitalized whether productive or nonproductive.
Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Depreciation and depletion of
capitalized costs for producing oil and gas properties is computed using the
units-of-production method based upon proved reserves for each field.
19
In 1997, the Company began to accrue for future plugging, abandonment, and
remediation using the negative salvage value method whereby costs are expensed
through additional depletion expense over the remaining economic lives of the
wells. Management's estimate of the total future costs to plug, abandon, and
remediate the Company's share of all existing wells, including those currently
shut in is approximately $3,500,000, net of salvage values. The total amount
expensed for this liability was $49,500 for the period ended March 31, 1999.
The Company follows Statement of Financial Accounting Standards (SFAS) No. 121,
Accounting for Impairment of Long-Lived Assets. This statement limits net
capitalized costs of proved and unproved oil and gas properties to the aggregate
undiscounted future net revenues related to each field. If the net capitalized
costs exceed the limitation, impairment is provided to reduce the carrying value
of the properties in the field to estimated actual value.
Gains and losses are generally recognized upon the sale of interests in proved
oil and gas properties based on the portion of the property sold. For sales of
partial interests in unproved properties, the Company treats the proceeds as a
recovery of costs with no gain recognized until all costs have been recovered.
Energy Marketing Arrangements - In 1998, BFC entered into an agreement to manage
certain natural gas contracts of an unrelated entity. For some contracts, BFC
takes title to the gas purchased to service these contracts prior to the sale
under the contracts. For these contracts, BFC consolidates all revenue,
expenses, receivables, and payables associated with the contracts. In contracts
where title is not taken, BFC only records the margin associated with the
transaction.
Other Property and Equipment - Depreciation of other property and equipment is
calculated using the straight-line method over the estimated useful lives
(ranging from 3 to 25 years) of the respective assets. The cost of normal
maintenance and repairs is charged to operating expenses as incurred. Material
expenditures, which increase the life of an asset, are capitalized and
depreciated over the estimated remaining useful life of the asset. The cost of
properties sold, or otherwise disposed of, and the related accumulated
depreciation or amortization is removed from the accounts, and any gains or
losses are reflected in current operations.
Deferred Loan Costs - Costs associated with the Company's note payable have been
deferred and are being amortized using the effective interest method over the
original term of the note.
Gas Balancing - the Company uses the sales method of accounting for amounts
received from the natural gas sales resulting from production credited to the
Company in excess of its revenue interest share. Under this method, all
proceeds from the production credited to the Company are recorded as revenue
until such time as the Company has produced its share of related estimated
remaining reserves. Thereafter, additional amounts received are recorded as a
liability.
20
Income Taxes - The Company accounts for income taxes under the liability method,
which required recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns. Under this method, deferred tax assets and
liabilities are determined based on the difference between the financial
statement and tax bases of assets and liabilities using enacted tax rates in
effect for the year in which the differences are expected to reverse. BPC
includes the Company's operations in its consolidated tax return. Income taxes
are allocated by BPC as if the Company was a separate taxpayer.
Accounting for Hedged Transactions - The Company periodically enters into
futures, forwards, and swap contracts as hedges of commodity prices associated
with the production of oil and gas and with the purchase and sale of natural gas
in order to mitigate the risk of market price fluctuations. Changes in the
market value of futures, forwards, and swap contracts are not recognized until
the related production occurs or until the related gas purchase or sale takes
place. Realized losses from any positions, which were closed early, are
deferred and recorded as an asses or liability in the accompanying balance
sheet, until the related production, purchase or sale takes place. Gains and
losses incurred on these contracts are included in oil and gas revenue or in gas
marketing costs in the accompanying statements of operations.
Accounting Estimates - The preparation of financial statements in conformity
with generally accepted accounting principles required management to make
estimates and assumptions that affect the amounts reported in these financial
statements and the accompanying notes. The actual results could differ from
those estimates.
Reclassifications - Certain reclassifications have been made to conform the 1999
financial statements to the presentation in 1998. These reclassifications had
no effect on net income.
2. Long -Term Debt:
The Company has an asset-based line-of-credit with a bank which provides for
borrowing up to the borrowing base (as defined). The borrowing base was
$13,200,000 at March 31, 1999. Outstanding borrowings were $7,000,000, with
interest at a variable rate that approximated 6.75% at March 31, 1999. The
Company has issued letters of credit totaling $3,100,000, which further reduces
the amount available for borrowing the base. This facility is collateralized by
certain oil and gas properties of the Company and is scheduled to convert to a
term note on July 1, 2001. This term loan is scheduled to have a maturity of
either the economic half life of the Company's remaining reserves on the date of
conversion, or July 1, 2006, whichever is earlier. The borrowing base is based
upon the lender's evaluation of BFC's proved oil and gas reserves, generally
determined semi-annually. The future minimum principal payments under the term
note will be dependent upon the bank's evaluation of the Company's reserves at
that time.
21
The Company also has an accounts receivable-based credit facility which includes
a revolving line-of-credit with the bank which provides for borrowings up to
$1,500,000. Outstanding borrowings under this facility at March 31, 1999,
amounted to $1,500.00. This facility bears interest at prime (7.75% at March
31, 1999). This facility is collateralized by certain trade receivables of BFC
and has a maturity date of July 1, 1999.
The credit agreement contains various covenants, which prohibit or limit the
subsidiary's ability to pay dividends, purchase treasury shares, incur
indebtedness, repay debt to the Parent, sell properties or merge with another
entity. Additionally, the Company is required to maintain certain financial
ratios.
3. Commitments:
Office Lease - the Company leases office space under a noncancellable operation
lease. Total rental expense was approximately $37,000 and $33,000 for the
periods ended March 31, 1999 and 1998, respectively. Beginning in 1998, the
Company has a new lease agreement, which provides for total minimum rental
commitments of:
1999 $110,000
2000 $153,000
2001 $159,000
2002 $166,000
--------
$588,000
Income Taxes:
The components of the net deferred tax assets are as follows:
December 31,
1998
-----------
Excess of tax basis over book
basis of oil and gas properties $ 1,873,000
Deferred tax assets $ 1,873,000
Less valuation allowance $(1,873,000)
Net deferred tax assets $ -
The effective tax rate of the Company differed from the Federal statutory rate
primarily due to changes in the valuation allowance on the deferred tax assets.
22
5. Concentrations of Credit Risk and Price Risk Management:
Concentrations of Credit Risk - substantially all of the Company's accounts
receivable at March 31, 1999, result from crude oil and natural gas sales and/or
joint interest billings to companies in the oil and gas industry. This
concentration of customers and joint interest owners may impact the Company's
overall credit risk, either positively or negatively, since these entities may
be similarly affected by changes in economic or other conditions. In
determining whether or not to require collateral from a customer or joint
interest owner, the Company analyzes the entity's net worth, cash flows,
earnings, and credit ratings. Receivables are generally not collateralized.
Historical credit losses incurred on trade receivables by the Company have been
insignificant.
The Company's revenues are predominantly derived from the sale of natural gas
and management estimates that over 85% of the value of the Company's properties
are derived from natural gas reserves.
Energy Financial Instruments - BFC uses energy financial instruments and long-
term user contracts to minimize its risk of price changes in the spot and fixed
price natural gas and crude oil markets. Energy risk management products used
include commodity futures and options contracts, fixed-price swaps, and basis
swaps. Pursuant to Company guidelines BFC is to engage in these activities only
as a hedging mechanism against price volatility associated with pre-existing or
anticipated gas or crude oil sales in order to protect profit margins. As of
March 31, 1999, BFC has financial and physical contracts which hedge 5.9 bcf
(billion cubic feet) of production through December 2001.
The difference between the current market value of the hedging contracts and the
original market value of the hedging contracts was an unfavorable $111,000 as of
March 31, 1999. These amounts are not reflected in the accompanying financial
statements. In the event energy financial instruments do not qualify for hedge
accounting, the difference between the current market value and the original
contract value would be currently recognized in the statement of operations. In
the event that the energy financial instruments are terminated prior to the
delivery of the item being hedged, the gains and losses at the time of the
termination are deferred until the period of physical delivery. Such deferrals
were immaterial in all periods presented.
6. Financial Instruments:
SFAS Nos. 107 and 127 require certain entities to disclose the fair value of
certain financial instruments in their financial statements. Accordingly,
management's best estimate is that the carrying amount of cash, receivables,
notes payable, accounts payable, undistributed revenue, and accrued expenses
approximates fair value of these instruments. See Note 6 for a discussion
regarding the fair value of energy financial instruments.
23
7. Management Retention Bonuses and Employment Contracts:
The Company has accrued compensation as of March 31, 1999 of $164,000 in
accordance with a management retention program approved by the bankruptcy court.
The Company has also entered into certain employment contracts with key
employees that provide for certain benefits to the employees upon termination
without cause.
8. Subsequent Event:
During the first quarter, BPC engaged a financial advisor to pursue various
strategic opportunities. BPC is considering all options including the continued
operation of all its subsidiaries or the sale of the entire Company or any part
thereof. No adjustment to the financial statements has been made.
24
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Canada
United States For the Period from
Three Months Ended February 18 through
March 31, March 31,
------------------------------------------ --------------------------------------
2000 1999 % Change 2000 1999 % Change
-------------- ---------- ----------- ------------ ----------- ----------
(Dollars in thousands, except (Dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
Revenues:
Natural gas $ 2,026 $ 1,758 15% $ 553 $ 247 124%
Oil and Liquids 404 149 171% 194 73 166%
-------------- ---------- ------------ -----------
Total 2,430 1,907 27% 747 320 133%
Sales volumes:
Natural gas (MMcf) 845 889 -5% 218 143 52%
Oil and Liquids (Bbl) 16,252 14,848 9% 7,408 7,282 2%
Average price received:
Natural gas (Mcf) $ 2.40 $ 1.98 21% $ 2.54 $ 1.73 47%
Oil and Liquids (Bbl) 24.86 10.05 147% 26.12 9.98 162%
Production costs $ 826 $ 669 23% $ 196 $ 93 111%
Average production costs/Mcfe 0.88 0.68 29% 0.75 0.50 50%
Gas and electrical marketing revenue $ 1,485 $ 7,517 -80% $ - $ -
Gas and electrical marketing expense 1,477 7,383 -80% - -
General and administrative, net 438 436 0% 113 167 -32%
Depreciation, depletion and amortization 945 487 94% 205 138 49%
Exploration expense - 244 -100% - -
Interest expense, net 172 112 54% 23 4 475%
Results of Operations
Three months ended March 31, 2000, compared to three months ended March 31,
1999.
On February 17, 2000 Carbon Energy (Carbon) completed its offer to exchange
shares of Carbon stock on a share for share basis for shares of CEC Resources
Ltd. (CEC) stock, resulting in over 97% of CEC's shareholders exchanging CEC
shares for Carbon shares. For the purpose of the management discussion and
analysis of the results of operations, Carbon's Canadian operations have been
presented in the table above for the periods February 18 through March 31, 1999
and February 18 through March 31, 2000. The discussions of the U.S. operations
compare the results of Carbon's 100% owned subsidiary Bonneville Fuels
Corporation (BFC) for the three months ended March 31, 1999 and March 31, 2000.
Revenues for oil and gas sales of BFC for the first quarter of 2000 were $2.4
million, a 27% increase from the prior year period. The increase was due
primarily to increase in oil production and higher oil and gas prices.
25
Revenues for CEC for the period February 18 through March 31, 2000 were
$747,000, a 133% increase from the prior year period. The increase was due
primarily to increase in natural gas and oil production and higher oil and gas
prices.
BFC's average production for the first quarter of 2000 was 179 barrels of oil
per day and 9.3 million cubic feet (mmcf) of gas per day, a decrease of 4% on a
mcf equivalent (mcfe) basis where one barrel of oil is equal to six mcf of gas.
The decrease was primarily attributed to properties located in the U.S. subject
to a tax credit agreement where the Company was not entitled to sales proceeds
from these properties for the three months ended March 31, 2000 (see "Financial
Condition and Capital Resources"). During the quarter, 4 gross wells and 2.57
net wells were drilled compared to 2 gross wells and .93 wells drilled during
the same three months ending March 31, 1999.
CEC's average production for the period February 18 through March 31, 2000 was
172 barrels of oil and liquids per day and 5.1 mmcf of gas per day, an increase
of 40% on an mcfe basis from the same period in 1999. The increase was
primarily attributed to acquisitions, successful well workovers and optimization
of the Company's compressor facilities. CEC did not have any drilling activity
for the period February 18 through March 31, 1999 and 2000.
Average oil prices received by BFC increased 147% from $10.05 per barrel in the
first quarter of 1999 to $24.86 in the first quarter of 2000. The average oil
price includes hedge losses of $43,000 for the first quarter of 2000. There was
no oil hedge activity for the similar period in 1999. Average natural gas
prices received by BFC increased 21% from $1.98 per mcf for the first quarter of
1999 to $2.40 per mcf in 2000. The average natural gas price includes hedge
gains of $100,000 for the first quarter of 2000 and $306,000 for the similar
period in 1999.
Average oil and liquids prices received by CEC increased 162% from $9.98 per
barrel for the period from February 18 through March 31, 1999 to $26.12 for the
same period in 2000. The average price includes hedge losses of $12,000 for the
period February 18 through March 31, 2000. There was no oil hedge activity for
the similar period in 1999. Average natural gas prices received by CEC
increased 47% from $1.73 per mcf for the period from February 18 through March
31, 1999 to $2.54 for the same period in 2000. The average natural gas price
includes hedge gains of $19,000 for the period February 18 through March 31,
2000 compared to $22,000 for the same period in 1999.
Production costs incurred by BFC, consisting of lease operating expenses and
production taxes, were $826,000 or $.88 per mcfe for the first quarter of 2000
compared to $669,000 or $.68 per mcfe for 1999. The increase in production costs
was attributable to a rise in production taxes due to higher oil and gas prices
and an increase in lease operating expenses of $108,000. The increase was
primarily attributed to well workovers in the Permian and Piceance Basins.
Direct production costs incurred by CEC, consisting of lease operating expenses,
net crown royalty, and net gas plant activity, was $196,000 or $.75 per mcfe for
the period February 18 through March 31, 2000 compared to $93,000 or $.50 per
mcfe for the similar period in 1999. The increase in production costs was
primarily attributable to a rise in net crown royalties due to higher oil and
gas prices.
26
Exploration expense was recorded by the Company's predecessor, BFC, under the
successful efforts method of accounting and consists primarily of unsuccessful
drilling and geological and geophysical costs. Effective as of the date of the
acquisition of BFC, Carbon utilizes the full cost method of accounting. Under
this method, all exploration costs associated with continuing efforts to acquire
or review prospects and outside geological and seismic consulting work are
capitalized.
General and administrative expenses incurred by BFC, net of third party
reimbursements for the first quarter of 2000 were $438,000 compared to $436,000
for the same period in 1999.
General and administrative expenses incurred by CEC for the period February 18
through March 31, 2000 totaled $113,000, a $54,000 or 32% decrease from the same
period in 1999. The decrease was primarily due to lower professional fees and
contracted services.
Interest and other expenses incurred by BFC, rose to $172,000 in the first
quarter of 2000, a $60,000 or 54% increase from the prior year period. Interest
expense increased as a result of higher average debt balances on the Company's
debt. The average interest rate for the first quarter was 7.7% compared to 6.7%
in the first quarter of 1999.
Interest and other expenses incurred by CEC, rose to $23,000 for the period
February 18 through March 31, 2000, a $19,000 increase from the similar period
in 1999. Interest expense increased as a result of higher average debt balances
on the Company's debt.
Depreciation, depletion and amortization (DD&A) of oil and gas assets are
determined based upon the units of production method. This expense is typically
dependent upon historical capitalized costs incurred to find, develop and
recover oil and gas reserves; however, the Company's current DD&A rate is
determined primarily by the purchase price the Company allocated to oil and gas
properties in connection with its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
DD&A expense for BFC for the first quarter of 2000 was $945,000 an increase of
$458,000 or 94% from the 1999 level. Depletion expense was $1.00 per mcfe for
the first quarter of 2000 compared to $.50 per mcfe in 1999. The increase was
primarily driven by the increased property costs recorded as a result of the
acquisition of BFC.
DD&A expense for CEC for the period from February 18 through March 31, 2000 was
$205,000 an increase of $67,000 or 49% from the 1999 level. The increase
resulted primarily from increased production. In addition, CEC's DD&A rate for
the period February 18 through March 31, 2000 increased compared to the similar
period in 1999 as a result of increased property costs recorded as a result of
the acquisition of CEC.
27
Financial Condition and Capital Resources
At March 31, 2000, Carbon had $53.3 million of assets. Total capitalization was
$44.6 million, of which 70% was represented by stockholders' equity and 30% by
debt. During the three months ended March 31, 2000, net cash used by operations
was $510,000, as compared to $2.5 million in the first three months of 1999 for
the Company's predecessor BFC. Excluding changes in working capital, net cash
provided by operating activities for the Company for the three months ended
March 31, 2000 was $1.4 million compared to $687,000 for the Company's
predecessor BFC for the three months ended March 31, 1999. At March 31, 2000,
there were no significant commitments for capital expenditures. The Company
anticipates 2000 capital expenditures, exclusive of acquisitions, to approximate
$7.0 million. The level of these and other future expenditures is largely
discretionary, and the amount of funds devoted to any particular activity may
increase or decrease significantly, depending on available opportunities and
market conditions. The Company plans to finance its ongoing development,
acquisition and exploration expenditures using internal cash flow and bank
borrowings. In addition, joint ventures or future public and private offerings
of debt or equity securities may be utilized.
The Company has an oil and gas asset-based line-of-credit with both a U.S. and
Canadian bank. The facility with U.S. Bank, N.A. had a borrowing base of $16.2
million with outstanding borrowings of $10.3 million at March 31, 2000. Letters
of credit totaling $1.8 million were issued at March 31, 2000 which reduces the
amount available for borrowings. The facility is secured by certain U.S. oil
and gas properties of the Company and is scheduled to have a maturity of either
the economic half life of the Company's remaining U.S. based reserves on the
date of conversion or July 1, 2001, whichever is earlier. The facility bears
interest of a rate equal to LIBOR plus 1.75% or prime, depending on the option
of the Company. The rate was approximately 7.7% at March 31, 2000. The
borrowing base is based upon the lender's evaluation of the Company's proved oil
and gas reserves, generally determined semi-annually.
The credit agreement contains various covenants which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is also
required to maintain certain financial ratios.
The Company also has an accounts receivable-based credit facility which includes
a revolving line-of-credit with U.S. Bank, N.A. which provides for borrowings
and letters of credit up to $500,000. There were no outstanding borrowings or
letters of credit under this facility at March 31, 2000. This facility bears
interest at prime (9% at March 31, 2000). This facility is collateralized by
certain trade receivables of the Company and has a maturity date of July 1,
2001.
The Company has a credit facility with the Canadian Imperial Bank of Commerce
(CIBC) which had a borrowing base of approximately $4.0 million with outstanding
borrowings of $3.0 million at March 31, 2000. The Canadian facility is secured
by the Canadian oil and gas properties of the Company. The revolving phase of
the loan expired on April 20, 2000 and is in the process of being renewed by the
Company and the bank. If the revolving commitment is not renewed, the loan would
be converted into a term loan and would be reduced by way of consecutive monthly
payments over a period
28
not to exceed 36 months. The Canadian facility bears interest at the Canadian
prime rate plus 3/4%. The rate was approximately 7.75% at March 31, 2000.
The credit agreement contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness, sell
properties, or merge with another entity.
During 1995, BFC entered into an agreement to sell 99% of its interest in 14
coal gas wells located in New Mexico that qualified for IRC section 29 tax
credits. Under the terms of the agreement BFC is to receive 99% of the net cash
flow on the properties until certain cumulative production levels have been
reached, at which time the purchaser will receive 100% of the net cash flow
until a subsequent production level is reached. Upon reaching the second target,
100% of the cash flows will revert to BFC for substantially the remaining life
of the properties. The first production level was reached in January 2000. Due
to these contractual agreements, BFC will not be entitled to sales proceeds or
be obligated for the cost of operations on these properties until an additional
235,000 mcf has been produced. The Company estimates this will take
approximately 15 months. During this 15 month period, the Company will still be
entitled to receive tax credit benefits estimated to be $150,000.
Carbon's primary cash requirements will be to finance acquisitions, exploration
and development expenditures, repayment of debt, and general working capital
needs. However, future cash flow is subject to a number of variables including
the level of production and oil and natural gas prices and there can be no
assurance that operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures or that
increased capital expenditures will not be undertaken. Carbon believes that
available borrowings under its credit agreements, projected operating cash flows
and the cash on hand will be sufficient to cover its working capital, capital
expenditures, planned development activities and debt service requirements for
the next 12 months. In connection with consummating any significant
acquisition, additional debt or equity financing will be required, which may or
may not be available on terms that are acceptable to the Company.
Certain Factors That May Affect Future Results
Statements that are not historical facts contained in this report are forward-
looking statements that involve risks and uncertainties that could cause actual
results to differ from projected results. Such statements address activities,
events or developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as future capital,
development and exploration expenditures, drilling of wells, reserve estimates
(including estimates of future net revenues associated with such reserves and
the present value of such future net revenues), future production of oil and
natural gas, business strategies, expansion and growth of the Company's
operations, cash flow and anticipated liquidity, prospect development and
property acquisition, obtaining financial or industry partners for prospect or
program development, or marketing of oil and natural gas. Although the Company
believes that the expectation reflected in the forward-looking statements and
the assumptions upon which such forward-looking statements are based are
reasonable it can give no assurance that such
29
expectation and assumptions will prove to be correct. Factors that could cause
actual results to differ materially (Cautionary Disclosures) are described,
among other places, in the Marketing, Competition, and Regulation sections of
the Company's 1999 Form 10-K and under "Management's Discussion and Analysis of
Financial Condition and Results of Operations." These factors include, but are
not limited to general economic conditions, the market price of oil and natural
gas, the risks associated with exploration, the Company's ability to find,
acquire, market, develop and produce new properties, operating hazards attendant
to the oil and natural gas business, uncertainties in the estimation of proved
reserves and in the projection of future rates of production and timing of
development expenditures, the strength and financial resources of the Company's
competitors, the Company's ability to find and retain skilled personnel,
climatic conditions, labor relations, availability and cost of material and
equipment, environmental risks, the results of financing efforts, and regulatory
developments. All written and oral forward-looking statement attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the Cautionary Disclosures.
Year 2000 Issues
The conversion from calendar year 1999 to 2000 occurred without any disruption
in the Company's operations and information systems nor has the Company been
made aware of any Year 2000 issues occurring at third parties with which Carbon
has relations. The Company will continue to monitor any Year 2000 issues, both
internally and with third parties of business importance to the Company such as
its natural gas purchasers, gathering system and plant operators, downstream
pipeline operators, equipment and service providers, operators of its oil and
gas properties, financial institutions, and vendors providing payroll and
medical benefits and services. The Company believes that the most serious
effect to the Company would be delays in receiving payments for oil and gas sold
to its purchasers which could have a material adverse effect upon the results of
operations and financial conditions of the Company. This monitoring will be
ongoing and encompassed in normal operations.
Market and Commodity Risk
Interest Rate Risk
Market risk is estimated as the potential change in the fair value of interest
sensitive instruments resulting from an immediate hypothetical change in
interest rates. The sensitivity analysis presents the change in the fair value
of these instruments and changes in the Company's earnings and cash flows
assuming an immediate one percent change in floating interest rates. As the
Company presently has only floating rate debt, interest rate changes would not
affect the fair value of these floating rate instruments but would impact future
earnings and cash flows, assuming all other factors are held constant. The
carrying amount of the Company's floating rate debt approximates its fair value.
At March 31, 2000, the Company had $10.3 million of floating rate debt through
its facility with U.S. Bank, NA, and $3 million through its facility with CIBC.
Assuming constant debt levels, earnings and cash flow impacts for the next
twelve month period from March 31, 2000 due to a one percent change in interest
rates would be approximately
30
$103,000 before taxes for the facility with the U.S. bank and $30,000 before
taxes for the facility with the Canadian bank.
Foreign Currency Risk
The Canadian dollar is the functional currency of CEC and is subject to foreign
currency exchange rate risk on cash flows related to sales, expenses, financing
and investing transactions. The Company has not entered into any foreign
current forward contracts or other similar financial investments to manage this
risk.
Commodity Price Risk
Oil and gas commodity markets are influenced by global as well as regional
supply and demand. World wide political events can also impact commodity
prices. The Company used certain financial instruments in an attempt to manage
commodity price risk. The Company attempts to manage these risks by minimizing
its commodity price exposure through the use of derivative contracts as
described in Note 1 to the March 31, 2000 financial statements of Carbon and
Note 5 to the March 31, 1999 financial statements of BFC. These tools include,
but are not limited to commodity futures and option contracts, fixed-price
swaps, basis swaps, and term sales contracts. Gains and losses on these
contracts are deferred and recognized in income as an adjustment to oil and gas
sales revenue during the period in which the physical product to which the
contract relates to is actually sold.
The following tables summarize the Company's derivative financial instrument
position on its natural gas and oil production as of March 31, 2000.
BFC Contracts CEC Contracts
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtus per MMBtu Year MMBtus per MMBtu
- ----- ---------- ------------ ------ --------- ------------
2000 1,842,500 $ 2.37 2000 783,000 $ 2.36
2001 1,543,000 $ 2.36 2001 304,000 $ 2.37
---------- ---------
3,385,500 1,087,000
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year Barrels per Bbl Year Barrels per Bbl
- ----- ---------- ------------ ------ -------- ------------
2000 36,000 $ 21.47 2000 27,000 $ 22.35
As of March 31, 2000, the Company would have been required to pay $2,462,000 and
$849,000 to exit the BFC and CEC contracts, respectively.
31
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (SFAS 133), "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement, and
requires that a Company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. SFAS 133 is
effective for all fiscal quarters of fiscal years beginning after June 15, 2000.
The Company has not yet quantified the impacts of adopting SFAS 133 on its
financial statements and has not determined the timing of, or method of,
adoption of SFAS 133. However, SFAS 133 could increase volatility in earnings
and other comprehensive income.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of inflation,
factors unique to the oil and natural gas industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and natural gas prices. Although it is particularly difficult to
estimate future prices of oil and natural gas, price fluctuations have had, and
will continue to have, a material effect on the Company.
32
PART II - OTHER INFORMATION
Items 1 - 5. Not applicable
Item 6. (a) Exhibits
27 - Financial Data Schedule*
(b) No reports on Form 8-K were filed by the Registrant during the
quarter ended March 31, 2000.
*Filed herewith
33
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, 2000 By /s/ Patrick R. McDonald
-------------------- -------------------------------------
President and Chief Executive Officer
(a duly authorized officer)
Date: May 15, 2000 By /s/ Kevin D. Struzeski
-------------------- -------------------------------------
Treasurer
(Chief Financial Officer)
34
EXHIBIT INDEX
27 Financial Data Schedule
35