<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d)
Of the Securities Exchange Act of 1934
For the Fiscal Year Ended Commission File Number
December 31, 1999 1-15639
CARBON ENERGY CORPORATION
(Exact name of Registrant as specified in it Charter)
Colorado 84-1515097
(State of Incorporation) (I.R.S. Employer Identification No.)
1700 Broadway, Suite 1150 80290
Denver, Colorado (Zip Code)
(Address of principal executive offices)
Registrants telephone number, including area code:
(303) 863-1555
Securities registered pursuant to
Section 12(b) of the Act:
Title of each class Name of Exchange on which registered
Common Stock, (no par value) American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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, and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
---- ----
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock excluding shares held by
persons who may be considered affiliates of the registrant as of March 27, 2000
is $5,863,426.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of March 30, 2000.
Outstanding at
Class March 30, 2000
----- --------------
Common Stock, no par value 6,042,826 shares
The Company's Proxy Statement for the 2000 Annual Meeting of Shareholders
is incorporated by Reference into Part III
None
<PAGE>
PART I
Item 1. Business
General
-------
Carbon Energy Corporation (the "Company" or "Carbon") was incorporated on
September 14, 1999 under the Colorado Business Corporation Act. The Company's
business is comprised of the assets and properties of Bonneville Fuels
Corporation ("BFC"), which were acquired on October 29, 1999 in a stock
purchase, and the assets and properties of CEC Resources Ltd. ("CEC") of which
Carbon currently owns approximately 97% of its outstanding shares. As the
parent company, Carbon provides management and other services to BFC and CEC.
The total cash purchase price after adjustments for BFC's assets was
$23,581,000. On August 11, 1999, CEC entered into a stock purchase agreement
with Bonneville Pacific Corporation ("BPC"), parent company of BFC, which
provided for the purchase by CEC from BPC of all outstanding shares of BFC for
$23,858,000 in cash and the assumption of certain liabilities, subject to
certain adjustments. The purchase of BFC stock under the stock purchase
agreement was completed by Carbon rather than CEC. Rights and obligation of CEC
under the stock purchase agreement were assigned to Carbon. Yorktown Energy
Partners III, L.P. ("Yorktown") purchased 4,500,000 shares of Carbon for
$24,750,000. The funds from this purchase were used to acquire the BFC shares
under the stock purchase agreement and pay expenses incurred in connection with
the purchase and related transactions.
Carbon is an independent oil and gas company engaged in the exploration,
development, and production of natural gas and crude oil. At December 31, 1999,
the Company had $ 39.3 million of total assets and 32.4 billion cubic feet
equivalent ("Bcfe") of proved reserves. Oil is converted to natural gas at a
ratio of six Mcf of natural gas to one barrel of oil. The reserves had an
estimated pretax present value, discounted at 10%, of $25.9 million based on
unescalated prices and costs at December 31, 1999. Of these proved reserves,
approximately 96% on a Mcfe basis are gas and approximately 85% of the reserves
are categorized as proved developed. Prior to October 29, 1999 all of the
properties and activities described below were acquired or conducted by the
prior management of BFC. Carbon's activities at December 31, 1999, were
concentrated in the Piceance and Uintah Basins in Colorado and Utah, the
San Juan Basin in New Mexico, the Permian Basin in New Mexico and
Texas, and southwestern Kansas. At December 31, 1999, the Company owned working
interests in approximately 293 oil and gas wells, of which approximately 187 are
operated by the Company. Daily average production during 1999 was 12,200 Mcfe
per day for the Company and its predecessor, BFC.
CEC, which became a 97% owned subsidiary of Carbon in February, 2000, had
18.6 Bfce of proved reserves at December 31, 1999. The reserves of CEC at
December 31, 1999 had an estimated pre-tax present value, discounted at 10%, of
Cdn $27.5 million based on unescalated prices and costs in Canadian dollars at
December 31, 1999. CEC engages in the exploration, development and production
of crude oil and natural gas and acquires and develops leaseholds and other
interests in oil and gas properties, primarily in the Provinces of Alberta and
Saskatchewan in Canada.
Exchange Offer for CEC Shares
-----------------------------
On January 21, 2000, Carbon commenced an exchange offer for shares of CEC.
The exchange offer was one of the last steps in transactions to combine BFC and
CEC. In the exchange offer, Carbon offered to exchange one share of Carbon for
each share of CEC. CEC's Board of Directors recommended that CEC's shareholders
accept the offer and directors and executive officers of CEC announced that they
intended to accept the exchange offer.
On February 18, 2000, Carbon announced that the Company had completed its
offer to exchange Carbon shares for shares of CEC. Of the 1,521,000 outstanding
shares of CEC, over 97% of the shares were exchanged. Concurrent with the
completion of the exchange offer, the American Stock Exchange ("AMEX") commenced
proceedings to delist the common stock of CEC (trading symbol CGS). On February
28, 2000, the Securities and Exchange Commission approved the delisting of CEC's
common stock from the AMEX.
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<PAGE>
Carbon began trading its shares on the American Stock Exchange on February
24, 2000 under the trading symbol CRB.
Business Strategy
-----------------
Our business strategy is to grow through exploitation of existing oil and
gas properties by development of proved undeveloped reserves; acquisitions of
complementary working interests in existing and adjacent properties; and
optimization of gathering, compression and processing facilities. We will also
conduct oil and gas exploration activities with the potential to add significant
reserves and production and evaluate acquisition and merger opportunities in
existing and future core areas. Our activities will be conducted in the United
States primarily through BFC and in Canada through CEC.
Employees and Offices
---------------------
On December 31, 1999, the Company had 25 employees. None of these
employees are represented by a labor union. The Company's executive offices are
located at 1700 Broadway, Suite 1150, Denver, Colorado 80290, and its telephone
number is (303) 863-1555.
ITEM 2. PROPERTIES
Piceance and Uintah Basins
The Company operated at December 31, 1999, 131 wells and owned working
interests in 148 wells in the Piceance Basin in Colorado and the Uintah Basin in
Utah. Carbon and its predecessor, BFC, participated in the drilling and
completion of one gas well in these basins during 1999 and additional drilling
locations have been identified for further analysis and possible future
drilling. The Company has leasehold rights in approximately 151,000 gross and
106,000 net acres of which approximately 110,500 gross and 78,000 net acres are
undeveloped.
San Juan Basin
The Company operated at December 31, 1999, 41 wells and owns working
interests in 42 wells in the San Juan Basin. Carbon its predecessor, BFC,
participated in the drilling and completion of two gas wells in 1999. The
Company has lease rights in approximately 5,000 gross and 4,500 net acres, of
which approximately 2000 gross and 1,500 net acres are undeveloped.
Permian Basin
The Company owned working interests in 76 wells in the Permian Basin and
operates 11 of these wells. During 1999, the Company and its predecessor, BFC,
participated in the drilling of seven wells, of which five were completed as gas
wells and two were completed as oil wells. The Company has lease rights in
approximately 14,500 gross and 10,000 net acres, of which 5,000 gross and 3,500
net acres are undeveloped.
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<PAGE>
Southwestern Kansas
The main exploratory efforts of Carbon are concentrated in southwestern
Kansas. The Company owns working interests in 28 wells and operates four wells
in this area. During 1999, the Company and its predecessor, BFC, participated in
the drilling of three wells, of which two were completed as gas wells and one
abandoned as a dry hole. The Company is conducting regional geologic and
geophysical work to identify additional drilling prospects and is also currently
acquiring acreage covering the most attractive prospects. The Company has lease
rights in approximately 29,000 gross and 25,000 net acres of which 26,500 gross
and 24,500 net acres are undeveloped.
Proved Reserves
---------------
The table below sets forth the estimated quantities of year end net proved
reserves and the present values attributable to those reserves for the Company
at December 31, 1999 and for BFC, the Company's predecessor, at December 31,
1998 and 1997. The estimates were prepared by Ryder Scott Company, an
independent reservoir engineering firm.
<TABLE>
<CAPTION>
Estimated Proved Reserves
--------------------------------------------------------------------
December 31,
--------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------- -------------------
(dollars in thousands, except sales price data)
<S> <C> <C> <C>
Estimated Proved Reserves
Natural gas (Mmcf) 31,012 25,855 23,140
Oil and condensate (MBbl) 228 166 298
Total (Mcfe) 32,380 26,851 24,928
Proved developed reserves (Mcfe) 27,504 26,851 24,411
Natural gas price as of
December 31 ($/Mcf) 2.05 1.84 1.81
Oil price as of
December 31 ($/Bbl) 24.41 10.69 16.91
Standardized measure of discounted
net cash flows before
income taxes (1) 25,894 20,495 19,629
</TABLE>
- - - -------------------------------------------------------------------------------
(1) The standardized measure of discounted net cash flows prepared by the
Company and its predecessor, BFC, represents the present value of estimated
future net revenues before income taxes, discounted at 10%.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms or primary recovery are included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
At December 31, 1999, Carbon had approximately 26.2 Bcf of proved developed
gas reserves representing 85% of Carbon's total proved gas reserves and 212,000
barrels of proved developed oil and natural gas liquid reserves representing 93%
of the Company's total proved oil reserves. Approximately 7.1 Bcf of the 26.2
Bcf of proved developed natural gas reserves are primarily reserves for wells
which have been completed and were awaiting connection to a gas pipeline as of
year end, provided such pipeline connection does not require significant
investment. Also included are reserves behind the casing in existing wells and
recompletion of those zones will be required to place them in production.
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<PAGE>
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage is limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units are claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation.
At December 31, 1999 Carbon's proved undeveloped reserves were
approximately 4.8 Bcf of gas, or 15% of its total proved natural gas reserves,
and 16,000 barrels of oil and natural gas liquids. These reserves are primarily
attributable to undrilled locations offsetting production in various fields.
Price declines decrease reserve values by lowering the future net revenues
attributable to the reserves and reducing the quantities of reserves that are
recoverable on an economic basis. Price increases have the opposite effect. A
significant decline in prices of oil or natural gas could have a material
adverse effect on the Company's financial condition and results of operations.
Future prices received from production and future production costs may
vary, perhaps significantly, from the prices and costs assumed for purposes of
these estimates. There can be no assurance that the proved reserves will be
developed within the periods indicated or that prices and costs will remain
constant. There can be no assurance that actual production will equal the
estimated amounts used in the preparation of reserve projections.
The present values shown should not be construed as the current market
value of the reserves. The 10% discount factor used to calculate present value,
which is specified by the Securities and Exchange Commission, is not necessarily
the most appropriate discount rate, and present value, no matter what discount
rate is used, is materially affected by assumptions as to timing of future
production, which may prove to be inaccurate. For properties operated by the
Company and its predecessor, BFC, expenses exclude the Company's share of
overhead charges. In addition, the calculation of estimated future net revenues
does not take into account the effect of various cash outlays, including among
other things general and administrative costs and interest expense.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. Oil and natural gas reserve engineering must be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way, and estimates of
other engineers might differ materially from those shown above. The accuracy of
any reserve estimate is a function of the quality of available data and
engineering and geological interpretation and judgement. Results of drilling,
testing and production may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered. The meaningfulness of such estimates depends
primarily on the accuracy of the assumptions upon which they were based. In
general, the volume of production from oil and gas properties the Company owns
decline as reserves are depleted. Except to the extent the Company acquires
additional properties containing proved reserves or conducts successful
exploration and development activities or both, the proved reserves will decline
as reserves are produced.
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<PAGE>
Production
----------
The following table sets forth annual net production for each of the three
years ended December 31, 1999, for the Company and its predecessor, BFC. For
1999, the production includes the activities of the Company (consolidated
inclusive of BFC) for November and December 1999 and Carbon's predecessor, BFC,
for the period January through October 1999. Production figures for 1997 and
1998 are for the Company's predecessor, BFC. Net production includes volumes
related to a production payment used to pay a related note. Volumes
attributable to this activity were 223,786 Mcf in 1999, 249,571 Mcf in 1998 and
277,542 Mcf in 1997.
Year ended December 31,
----------------------------------------------
1999 1998 1997
-------------- -------------- --------------
Gas - Mmcf 4,074 3,272 2,908
Oil - Bbls 64,000 65,000 63,000
-5-
<PAGE>
Average price and cost per unit of production for the past three years are
as follows (gas prices are inclusive of hedging results):
Year ended December 31,
----------------------------------------
1999 1998 1997
------------ ------------- -----------
Average sales price per Bbl of oil $17.44 $13.26 $19.48
Average sales price per Mcf of gas $2.07 $1.78 $1.79
Average production cost per Mcfe $0.77 $0.89 $0.85
We operate most of the wells in which we own interests and also hold
working interests in some wells operated by third parties. Gas sales are
generally made pursuant to gas purchase contracts with unrelated third parties.
Our gas sales are subject to price adjustment provisions of the gas purchase
contracts as well as general economic and political conditions affecting the
production and price of natural gas.
Producing Wells
The following table sets forth the producing wells in which the Company
owned a working interest at December 31, 1999. Wells are classified as oil or
natural gas wells according to their predominant production stream.
Productive Wells (1)
--------------------------------------------------
Gas Wells Oil Wells
----------------------- ------------------------
Gross Net Gross Net
---------- ---------- ----------- ----------
Permian Basin 62 12 14 5
Piceance and Uintah Basins 142 125 6 5
San Juan Basin 39 23 2 2
Southwestern Kansas 14 5 14 4
---------- ---------- ----------- ----------
Total 257 165 36 16
========== ========== =========== ==========
- - - -------------------------------------------------------------------------------
(1) Each well completed to more than one producing zone is counted as a single
well. The Company has royalty interests in certain wells that are not
included in this table.
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<PAGE>
Drilling Activities
The Company engages in exploratory and development drilling on its own and in
association with other oil and gas companies. The table below sets forth
information regarding the Company's and its predecessor, BFC's, drilling
activity for the last three years. For 1999, the table presents the drilling
activities of the Company (consolidated inclusive of BFC) for November and
December 1999 and Carbon's predecessor, BFC, for the period January through
October 1999. Drilling activity for 1997 and 1998 are for the Company's
predecessor, BFC.
<TABLE>
<CAPTION>
Wells Drilled
-----------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------------------------------------------
1999 1998 1997
-------------------------- ----------------------- -----------------------
Gross Net Gross Net Gross Net
---------- -------------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Development
Natural gas 3 1.79 3 0.49 1 1.00
Oil 2 0.14 2 0.14 1 1.00
Non-Productive - - 3 2.25 - -
---------- -------------- ---------- ----------- ---------- -----------
Total 5 1.93 8 2.88 2 2.00
========== ============== ========== =========== ========== ===========
Exploratory
Natural gas 7 4.23 1 0.26 - -
Oil - - 1 1.00 - -
Non-Productive 1 1.00 2 0.70 9 5.24
---------- -------------- ---------- ----------- ---------- -----------
Total 8 5.23 4 1.96 9 5.24
========== ============== ========== =========== ========== ===========
</TABLE>
The following table sets forth the leasehold acreage held by the Company at
December 31, 1999. Undeveloped acreage is acreage held under lease permit,
contract or option that is not in a spacing unit for a producing well, including
leasehold interests identified for development or exploratory drilling.
Developed acreage is acreage assigned to producing wells.
<TABLE>
<CAPTION>
Developed Acreage Undeveloped Acreage
------------------------------- -------------------------------
Gross Net Gross Net
--------------- -------------- -------------- ---------------
<S> <C> <C> <C> <C>
Permian Basin 9,690 6,695 4,995 3,467
Piceance and Uintah Basins 40,358 28,184 110,436 77,859
San Juan Basin - New Mexico 3,280 3,129 1,920 1,280
Southwestern Kansas 2,560 640 26,552 24,517
--------------- -------------- -------------- ---------------
Total 55,888 38,648 143,903 107,123
=============== ============== ============== ===============
</TABLE>
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<PAGE>
Marketing
---------
The Company markets all of its own natural gas and oil production from
wells that it operates.
Natural Gas
As of December 31, 1999, the Company did not have any of its production
committed to fixed price contracts nor is the Company committed to any firm
transportation agreements.
The Company has established a Risk Management Committee to oversee its
production hedging. It is the policy of the Company that the Risk Management
Committee approves all production hedging transactions.
As of December 31, 1999, the Company has entered into financial
transactions to hedge approximately 3,860,000 million MMBtu through 2001 at an
average fixed price of $2.39 per MMBtu, (See Item 7A "Quantitative and
Qualitative Disclosures About Market Risk").
Oil
Oil production is generally sold to refiners, marketers and other
purchasers who truck oil to local refineries or pipelines. The price is based
upon a local market posting for oil which generally approximates a West Texas
Intermediate posting, and is adjusted upward to reflect demand and quality. As
of December 31, 1999, the Company had entered into financial transactions to
hedge approximately 48,000 barrels of oil through December 2000 at an average
fixed price of $22.35 per barrel (See Item 7A "Quantitative and Qualitative
Disclosures About Market Risk").
Competition
-----------
The oil and natural gas industry is highly competitive. The Company
encounters competition from other oil and natural gas companies in all of its
operations, including the acquisition of producing properties and exploration
and development prospects. Major oil and gas companies and independent
producers are active bidders for undeveloped acreage and desirable oil and gas
properties as well as for the equipment and labor to operate such properties.
Many competitors have financial resources greater than those of the Company.
The ability of the Company to increase reserves in the future will be dependent
on its ability to acquire desirable producing properties and prospects for
future development and exploration.
Title to Properties
-------------------
Title to the Company's properties is subject to royalty, overriding
royalty, carried, net profits, working and similar interests customary in the
oil and gas industry. The Company's properties may also be subject to liens
incident to operating agreements, as well as other encumbrances, easements and
restrictions. As is customary in the industry in the case of undeveloped
properties, only a perfunctory investigation as to ownership is conducted at the
time of acquisition. Prior to the commencement of drilling operations, a title
examination is performed and curative work is performed with respect to material
title defects. The methods of title examination adopted by the Company are
reasonably calculated in the opinion of management, to insure that production
from its properties, if obtained, will be readily salable for the account of the
Company.
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<PAGE>
Government Regulation
---------------------
The Company's operations are regulated at the federal, state and local
levels. Natural gas and oil exploration, development, production and marketing
activities are subject to various laws and regulations and are periodically
changed for a variety of political, economical and other reasons. The burden of
the regulations increases the cost of doing business and may decrease
flexibility by limiting the quantity of hydrocarbons the Company may produce and
sell.
The Company conducts certain operations on federal oil and gas leases,
which the Mineral Management Service ("MMS") administers. These leases contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders.
State statues govern exploration and production operations, conservation of
oil and natural gas resources, protection of the correlative rights of natural
gas and oil owners and environmental standards. State commissions establish
rules and reclamation of sites, plugging bonds, reporting and other matters.
Increasingly, a number of city and county governments have enacted natural
gas and oil regulations which have increased the involvement of local
governments in the permitting of natural gas and oil operations, and impart
additional restrictions or conditions on the conduct of operators to mitigate
the impact of operations on the surrounding community. These local restrictions
have the potential to delay and increase the cost of natural gas and oil
operations.
The Company's natural gas sales are affected by regulation of intrastate
and interstate transportation. In recent years the Federal Energy Regulatory
Commission ("FERC") has issued a series of orders that has increased competition
in the sale, purchase, marketing and transportation of natural gas which have
helped natural gas become more responsive to changing market conditions. The
Company believes that these changes have generally improved the Company's access
to transportation and has enhanced the marketability of its natural gas
production. To date the Company believes it has not experienced any material
adverse effects as a result of these FERC orders; however the Company cannot
predict what new regulations may be adopted by FERC and other regulatory
authorities and the effect, if any, subsequent regulations may have on the
Company.
Environmental Regulation
------------------------
The Company, as a lessee and operator of natural gas and oil properties, is
subject to various federal, state and local laws and regulations that provide
for restriction and prohibitions on releases or emissions of various substances
produced in association with certain oil and gas industry operations and can
affect the location of wells and facilities and the extent to which exploration
and development is permitted. In addition, legislation requires that well and
facility sites and access be abandoned and reclaimed to the satisfaction of
federal or state authorities, as applicable. A breach of such regulations may
result in the imposition of fines and penalties, the suspension of operations
and potential civil liability.
The Company has made, and will continue to make, expenditures in its
efforts to comply with environmental regulations which it believes is a
necessary business cost in the oil and gas industry. The Company believes it is
in compliance with applicable environmental laws and regulations in effect and
that compliance will not have a material effect on capital expenditures or the
Company's competitive position in the industry. In connection with the
Company's acquisition of BFC, environmental assessments were performed resulting
in no identified material noncompliance or clean-up liabilities requiring action
in the immediate future; however environmental assessments were not performed on
all of the Company's properties. The Company believes that it is reasonably
likely that the trend in environmental legislation and regulation will continue
toward stricter standards. No assurance can be given as to future capital
expenditures which may be required for compliance with prospective environmental
regulations.
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<PAGE>
Operating Hazards
-----------------
The oil and gas business involves a variety of operating risks including
the risk of fire, explosions, blow-outs, pipe failure, casing collapse,
abnormally pressured formations, and environmental hazards such as oil spills,
gas leaks, ruptures and discharge of toxic substances. The occurrence of any of
these events might result in substantial losses to the Company due to injury and
loss of life, severe damage to and destruction of property and natural resources
and investigation and penalties and suspension of operations. The Company
maintains insurance against some, but not all, potential risks; however, there
can be no assurance that any such insurance that is obtained will be adequate to
cover all losses or exposure for liability. Furthermore, the Company cannot
predict whether such insurance will continue to be available at premium levels
that justify its purchase.
Item 3. Legal Proceedings
There are no legal proceedings pending or, to our knowledge, threatened
against us.
Item 4. Submission of Matters to a Vote of Security Holders
None.
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<PAGE>
PART II
Item 5. Market for Registrants Common Equity and Related Stockholder Matters
On February 24, 2000, the Company's shares began trading on the American
Stock Exchange under the trading symbol CRB.
On March 27, 2000, the closing price for the Company's common stock was 5
7/8 per share and there were 6,042,826 shares outstanding.
At February 29, 2000, there were approximately 38 holders of record of the
Company's common stock.
The Company has not paid any cash dividends on its common stock and does
not contemplate the payment of cash dividends since it plans to use available
earnings for its drilling, development and acquisition programs. Payment of
future cash dividends would also be dependent on earnings, financial
requirements and other factors.
As of September 15, 1999, Carbon sold 100 shares of its common stock to
Yorktown Energy Partners III, L.P. ("Yorktown Energy Partners") at $5.50 in cash
per share for an aggregate price of $550. On October 28, 1999, Carbon sold (1)
4,427,537 shares of its common stock to Yorktown Energy Partners at $5.50 in
cash per share for an aggregate price of $24,351,453 and (2) 72,363 shares of
its common stock to Yorktown Partners, LLC as agent for several investors, each
of whom is believed by Carbon to be an accredited investor as defined in
Regulation D of the Securities and Exchange Commission, at $5.50 in cash per
share for an aggregate price of $397,996. On October 28, 1999, Carbon also sold
10,000 shares of its common stock to David H. Kennedy, a director of Carbon, at
$5.50 in cash per share for an aggregate price of $55,000. As of January 31,
2000, Carbon sold 10,000 shares of its common stock to Cortlandt S. Dietler, a
director, at $5.50 in cash per share for an aggregate price of $55,000. These
transactions did not involve any underwriters, and there were no underwriting
discounts or commissions.
Carbon has relied on exemptions from securities registrations for these
transactions. The relevant exemptions include Section 4(2) of the Securities
Act of 1933, Rule 506 of Regulation D and Section 4(6) of the Securities Act of
1933. Carbon believes that all these purchasers were accredited investors.
Item 6. Selected Financial Data
The table below sets forth selected historical financial and operating data
for the Company and its predecessor, BFC, as of or for each of the years in the
five-year period ended December 31, 1999. For 1999, the table presents the
activities of the Company (consolidated inclusive of BFC) for November and
December 1999 (the Company's operating activities prior to November 1, 1999 were
minimal) and Carbon's predecessor, BFC, for the period January through October
1999, and twelve months 1999 pro forma operating and cash flow data that
combines these activities. The twelve month figures as of or for the year ended
December 31, 1995 - 1998 are for Carbon's predecessor, BFC. Future results may
differ substantially from historical results because of changes in oil and
natural gas prices, production increases or declines and other factors. This
information should be read in conjunction with the financial statements and
notes thereto and "Management's Discussion and Analysis of Financial Condition
and Results of Operations," presented elsewhere herein.
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<PAGE>
<TABLE>
<CAPTION>
Pro Forma As of or As of or
For the for the for the
12 months two months ten months
Ended Ended Ended
December 31, December 31 October 31,
-------------------- ------------------- --------------------
1999 1999 1999
-------------------- ------------------- --------------------
(in thousands)
<S> <C> <C> <C>
Operating Data:
Revenues $ 22,829 $ 2,803 $ 20,026
Net Earnings (loss) 147 (491) 638
Cash Flow Data:
Cash provided by (used in) operating activities $ (713) $ 999 $ (1,712)
Cash used in investing activities (28,841) (24,110) (4,731)
Cash provided by (used in) financing activities 28,056 24,106 3,950
Balance Sheet Data:
Total assets $ 39,298 $ 22,912
Working capital 232 1,954
Long-term debt 9,100 9,800
Stockholder's equity(1) 24,315 9,701
<CAPTION>
As of or for the Year Ended December 31,
----------------------------------------------------------------
1998 1997 1996 1995
-------------- -------------- -------------- ---------------
<S> <C> <C> <C> <C>
Operating Data:
Revenues $ 21,092 $ 16,539 $ 15,067 $ 12,675
Net Earnings (loss) (2,191) 732 4,060 172
Cash Flow Data:
Cash provided by (used in) operating activities $ 4,696 $ 3,193 $ 4,136 $ 3,016
Cash used in investing activities (5,948) (4,442) (1,025) (859)
Cash provided by (used in) financing activities 3,450 1,019 (2,760) (2,090)
Balance Sheet Data:
Total assets $ 22,840 $ 16,054 $ 14,524 $ 13,177
Working capital 562 1,491 1,725 628
Long-term debt 5,850 2,400 1,700 4,760
Stockholder's equity(1) 9,063 9,591 8,859 6,774 (1)
- - - -----------
</TABLE>
(1) Includes debt to former parent company (BPC) of $3,737 in 1995 which was
converted to equity in 1996.
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<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The financial statements and related notes thereto included elsewhere
herein are those of the Company, and its predecessor, BFC. The following
discussion should be read in conjunction with the financial statements and notes
thereto.
Results of Operations - Comparison of 1999 results to 1998
----------------------------------------------------------
The following table shows comparative revenue, sales volumes, average sales
prices, expenses and the percentage change between periods for the twelve months
ended December 31, 1999 and 1998. For 1999, the table presents the activities
of the Company (consolidated inclusive of BFC) for November and December 1999
(the Company's operating activities prior to November 1, 1999 were minimal) and
Carbon's predecessor, BFC, for the period January through October 1999 and
twelve months 1999 pro forma data that combines these activities. The
percentage change compares the pro forma data to 1998 results. The comparative
results discussion that follows also compares the pro forma data to 1998
results. The twelve month figures for the year ended December 31, 1998 are for
Carbon's predecessor, BFC.
<TABLE>
<CAPTION>
Twelve Two Ten Twelve
Months Months Months Months
Ended Ended Ended Ended Twelve
December 31, December 31, October 31, December 31, Months
--------------- -------------- --------------- -------------- Percentage
1999 1999 1999 1998 Change
--------------- -------------- --------------- -------------- -------------
(Pro forma) (Dollars in thousands, except
prices and per Mcfe information)
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas $ 8,429 $ 1,504 $ 6,925 $ 5,896 43%
Oil 1,128 233 895 862 31%
--------------- -------------- --------------- --------------
Total 9,557 1,737 7,820 6,758
Sales:
Natural gas (MMcf) 4,074 569 3,505 3,272 25%
Oil (Bbl) 64,000 9,000 55,000 65,000 -2%
Average price received:
Natural gas (Mcf) $ 2.07 $ 2.64 $ 1.98 $ 1.78 16%
Oil (Bbl) 17.44 25.29 16.13 13.26 32%
Production costs 3,457 597 2,860 3,254 6%
Average production costs/Mcfe $ 0.78 $ 0.96 $ 0.75 $ 0.89 -12%
Gas and electrical marketing revenue $ 12,619 $ 1,032 $ 11,587 $ 13,941 -9%
Gas and electrical marketing expense 12,530 1,028 11,502 13,811 -9%
General and administrative, net 2,559 939 1,620 1,655 55%
Depreciation, depletion and amortization 2,720 628 2,092 2,086 30%
Impairment expense 60 - 60 1,858 -97%
Exploration expense 800 - 800 556 44%
Interest expense, net 556 102 454 238 134%
</TABLE>
-13-
<PAGE>
Oil and Gas Revenues
Natural gas revenues for 1999 increased 43% compared to 1998 primarily due
to a 25% increase in sales volumes and a 16% increase in sales prices. The
increase in sales volumes were primarily due to successful drilling and
recompletion results in various basins, particularly in western Kansas and in
the Permian Basin of New Mexico, partially offset by production declines on
existing properties. Oil revenues for 1999 increased 31% compared to 1998 due
to a 32% increase in sales prices.
Average daily natural gas and oil production for 1999 was approximately
11,162 Mcf of gas per day and 175 barrels of oil per day, an increase of 22% on
a Mcfe basis from the same period in 1998.
Oil and Gas Production Costs
Oil and gas production costs consist of lease operating expense and
severance taxes. Oil and gas production costs for 1999 and 1998 were $.77 and
$.89, respectively, per Mcfe. The production costs of $.89 per Mcfe in 1998
included an accrual of $250,000 for the estimated liability under a well
connection reimbursement agreement. The 1998 production costs per Mcfe would
have been $.82 per Mcfe without these well connection costs.
Gas and Electrical Marketing
Gas and electrical marketing revenue and expense declined 9% in 1999
compared to 1998.
General and Administrative Expenses
G&A expenses relate to the direct costs of the Company which do not
originate from either its operation of properties or the providing of services
and are presented net of amounts billed to unrelated third parties. G&A expenses
increased by $904,000 in 1999 compared to 1998. This increase is primarily due
to one time charges approximating $1,025,000 due primarily to severance payments
incurred as a result of the acquisition of BFC by the Company. During 1998, the
Company's predecessor, BFC, increased staffing due to anticipated increases in
drilling activity. In 1999 charges related to this increased staffing were in
effect for the entire year resulting in comparative salary increases of
approximately $400,000. In 1998, BFC accrued $425,000 for an employee retention
bonus as the management of BFC and its former parent, BPC, deemed it prudent
that BFC remain fully staffed as BPC emerged from bankruptcy.
Depreciation, Depletion, Amortization and Impairment Expense
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 prospective DD&A rate will
be determined primarily by the purchase price the Company allocated to oil and
gas properties in connection with its acquisition of BFC and the proved reserves
the Company acquired in the BFC acquisition.
Through October 1999, the DD&A rate for the Company's predecessor, BFC, was
$.55 per Mcfe compared to $.57 in 1998. As a result of the Company's
acquisition of BFC and the resultant purchase accounting treatment, the current
DD&A rate increased to $.99 per Mcfe.
-14-
<PAGE>
Impairment losses were $60,000 in 1999 compared to $1,858,000 in 1998.
Impairments taken in 1998 are as follows:
South Humble City Field (SE New Mexico) - $931,000;
Taiga Mountain (Western Colorado) - $713,000;
Other - $214,000.
The major assumptions used for determining impairment losses were as
follows: Prices used were year-end 1998 prices for gas; $15.00/Bbl for oil;
estimates of declining production were based on estimates by independent third
party engineers; estimated operating cost and severance taxes were based on past
experience.
Impairment losses in 1998 were generally calculated by comparing the cost
basis of proved properties with the undiscounted cash flows based on unescalated
pricing. If the unamortized cost on a property was higher than the net
undiscounted cash flow projected, the property was deemed to be possibly
impaired. A further test was done at this point to determine the amount (if
any) to impair. A subsequent test compared unamortized cost to the estimated
fair market value. This test looked at the price of the commodity used in the
initial test, and assessed whether it was representative of fair market value.
Both tests described above used estimates by independent third party engineers
to determine estimates of declining production. Additional considerations
included in-house assessments of reserves attributable to a property. After the
above tests, if a property was still deemed to require an impairment allowance,
impairment was taken to reduce the carrying value to the estimated fair value.
Technical reasons for impairments taken in 1998 are pressure declines in
the reservoir for the South Humble City Field and unsuccessful offset drilling
which indicated a smaller reservoir than originally forecast for the Taiga
Mountain Field.
Reserve categories used in the impairment test include all categories of
proven reserves. There were no categories of reserves used other than proved
(i.e. no probable or possible).
Effective as of the date of the acquisition of BFC, the Company utilizes
the full cost method of accounting and will be subject to full cost ceiling
provisions applicable in assessing impairment of the full cost pool.
Exploration Expense
Through October 1999, 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 ("G&G") costs.
Exploration expense in 1999 was $800,000 compared to $556,000 in 1998. The
amount related to unsuccessful drilling was $304,000 in 1999 compared to $84,000
in 1998, while G&G costs increased to $496,000 compared to $390,000 in 1998
because of increased exploration activities. 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 will be
capitalized.
Interest Expense
Interest expense was $556,000 in 1999 compared to $238,000 in 1998. The
increase in 1999 is primarily due to increased borrowings for drilling and
development activity.
Income Taxes
The Company and its predecessor, BFC, 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
actual
-15-
<PAGE>
tax rates in effect for the year in which the differences are expected to
reverse. The operations of the Company's predecessor, BFC were included in
BPC's consolidated tax return through October 29, 1999. Income taxes were
allocated to BFC as if BFC was a separate taxpayer.
Results of Operations - Comparison of 1998 results to 1997.
-----------------------------------------------------------
The following table shows comparative revenue, sales volumes, average sales
prices, expenses and the percentage change between periods for the twelve months
ended December 31, 1998 and 1997. These twelve month figures are for the
Company's predecessor, BFC.
<TABLE>
<CAPTION>
Twelve Months Ended
December 31,
------------------------------------------------
1998 1997 % Change
----------------- -------------- ------------
(Dollars in thousands, except
prices and per Mcfe information)
<S> <C> <C> <C>
Revenues:
Natural gas $ 5,896 $ 5,202 13%
Oil 862 1,227 -30%
-------------- --------------
Total 6,758 6,429
Sales:
Natural gas (MMcf) 3,272 2,908 13%
Oil (Bbl) 65,000 63,000 3%
Average price received:
Natural gas (Mcf) $ 1.78 $ 1.79 -1%
Oil (Bbl) 13.26 19.48 -32%
Production costs 3,254 2,779 17%
Average production costs/Mcfe $ 0.89 $ 0.85 5%
Gas and electrical marketing revenue $ 13,941 $ 9,641 45%
Gas and electrical marketing expense 13,811 9,050 53%
General and administrative, net 1,655 590 181%
Depreciation, depletion and amortization 2,086 1,942 7%
Impairment expense 1,858 312 496%
Exploration expense 556 772 -28%
Interest expense, net 238 83 187%
</TABLE>
Oil and Natural Gas Revenues
Natural gas revenues for 1998 increased 13% compared to 1997 primarily due
to a 13% increase in sales volumes. Oil revenue for 1998 decreased 30% compared
to 1997 primarily due to a 32% decrease in sales prices. The increases in sales
volumes were primarily due to successful drilling and recompletion activity,
partially offset by production declines on previously existing properties.
-16-
<PAGE>
Oil and Gas Production Costs
Oil and gas production costs consist of lease operating expense and
severance taxes. Oil and gas production costs for 1998 and 1997 were $.89 and
$.85 respectively, per Mcfe. The 1998 production costs of $.89 per Mcfe
included an accrual of $250,000 for the estimated liability under a well
connection reimbursement agreement. The 1998 production costs per Mcfe would
have been $.82 per Mcfe without these well connection costs.
Gas and Electrical Marketing
Gas and electrical marketing revenue increased 45% in 1998 compared to 1997
while gas and electrical marketing expense increased 53% in 1998 compared to
1997. Certain high margin contracts expired early in 1997. The related margins
were not present during most of 1997, nor in 1998.
General and Administrative Expenses
G&A expenses relate to the direct costs of BFC which do not originate from
either its operation of properties or the providing of services and are
presented net of amounts billed to unrelated third parties. G&A expenses
increased by $1,065,000 in 1998 compared to 1997. In 1998, BFC accrued $425,000
for an employee retention bonus. The remainder of the increase is primarily due
to costs associated with additional staffing related to anticipated increases in
drilling activity.
Depreciation, Depletion, Amortization and Impairment Expense
DD&A of oil and gas assets are determined based upon the units of
production method. This expense is primarily dependent upon historical
capitalized costs incurred to find, develop and recover oil and gas reserves.
For 1998 the depletion rate was $.57 per Mcfe compared to $.59 per Mcfe in 1997.
Impairment losses were $1,858,000 in 1998 compared to $312,000 in 1997.
Impairments taken in 1998 are as follows:
South Humble City Field (SE New Mexico) - $931,000;
Taiga Mountain (Western Colorado) - $713,000;
Other - $214,000.
The major assumptions used for determining impairment losses were as
follows: Prices used were year-end 1998 prices for gas; $15.00/Bbl for oil;
estimates of declining production were based on estimates by independent third
party engineers; estimated operating cost and severance taxes were based on past
experience.
Impairment losses in 1998 were generally calculated by comparing the cost
basis of proved properties with the undiscounted cash flows based on unescalated
pricing. If the unamortized cost on a property was higher that the net
undiscounted cash flow projected, the property was deemed to be possibly
impaired. A further test was done at this point to determine the amount (if
any) to impair. A subsequent test compared unamortized cost to the estimated
fair market value. This test looked at the price of the commodity used in the
initial test, and assessed whether it was representative of fair market value.
Both tests described above used estimates by independent third party engineers
to determine estimates of declining production. Additional considerations
included in-house assessments of reserves attributable to a property. After the
above tests, if a property was still deemed to require an impairment allowance,
impairment was taken to reduce the carrying value to the estimated fair value.
Technical reasons for impairments taken in 1998 are pressure declines in
the reservoir for the South Humble City Field and unsuccessful offset drilling
which indicated a smaller reservoir than originally forecast for the Taiga
Mountain Field.
-17-
<PAGE>
The primary factor causing the impairments in 1997 was the reevaluation of
certain undeveloped leases.
Reserve categories used in the impairment test include all categories of
proven reserves. There were no categories of reserves used other than proved
(i.e. no probable or possible).
Exploration Expense
Exploration expense was recorded under the successful efforts method of
accounting and consists primarily of unsuccessful drilling costs and G&G costs.
Exploration expense in 1998 was $556,000 compared to $772,000 in 1997. The
amount related to unsuccessful drilling was $84,000 in 1998 compared to $599,000
in 1997, while G&G costs increased in 1998 to $390,000 compared to $89,000 in
1997 because of increased exploration activities.
Interest Expense
Interest expense was $238,000 in 1998 compared to $83,000 in 1997. The
increase in 1998 is primarily due to increased borrowings for drilling and
development activity and because of lower prices received from oil and gas
sales.
Income Taxes
The Company and its predecessor, BFC, accounts for income taxes under the
liability method, which requires recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have been
included in the financial statements or tax returns. Under this method,
deferred tax assets and liabilities are determined based on the difference
between the financial statement and tax bases of assets and liabilities using
enacted tax rates in effect for the year in which the differences are expected
to reverse. The operations of the Company's predecessor, BFC, were included in
BPC's consolidated tax return. Income taxes were allocated to BFC as if BFC was
a separate taxpayer.
Effects of Changing Prices
The U.S. economy experienced considerable inflation during the late 1970's
and early 1980's but in recent years inflation has been fairly stable at
relatively low levels. The Company, along with most other business enterprises,
was then and will be affected in the future by any recurrence of such inflation.
Changing prices, or a change in the dollar's purchasing power, distorts the
traditional measures of financial performance which are generally expressed in
terms of the actual number of dollars exchanged and do not take into account
changes in the purchasing power of the monetary unit. This results in the
reporting of many transactions over an extended period as though the dollars
received or expended were of common value, which does not accurately portray
financial performance.
Inflation, as well as a recessionary period, can cause significant swings
in the interest rates that companies pay on bank borrowings. These factors are
anticipated to continue to affect the Company's operations both positively and
negatively for the foreseeable future.
Oil and gas prices fluctuate over time as a function of market economies.
Refer to the price change tables in the discussions "Oil and Gas Operations
Comparisons for 1999, 1998 and 1997" for information on product price
fluctuation over the past three years. These tables depict the effect of
changing prices on the revenue stream of the Company and its predecessor, BFC.
Operating expenses have been relatively stable but are a critical component
of profitability since they represent a larger percentage of revenues when lower
product prices prevail. Competition in the industry can significantly affect
the cost of acquiring leases, although in recent years this factor has been less
important as more operators have withdrawn from active exploration programs.
-18-
<PAGE>
Liquidity and Capital Resources
-------------------------------
At December 31, 1999, the Company had $39.3 million of assets. Total
capitalization was $33.4 million, consisting of 73% of stockholder's equity and
27% of debt. In October, 1999, the Company sold 4,500,000 shares of common
stock to Yorktown for $24,750,000 of which $23,581,000 was used to purchased the
stock of BFC in October 1999. The remaining proceeds have been used to fund
working capital.
The Company has a credit facility with U.S. Bank National Association. The
purpose of the loan is to provide financing for the acquisition of oil and gas
reserves and for normal operating requirements. The 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. The 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 the Company's proved oil and gas reserves,
generally determined semi-annually. The future minimum principal payment under
the term loan will be dependent upon the bank's evaluation of the Company's
reserves at that time. The borrowing base was $16.4 million at December 31, 1999
with interest at a variable rate that approximated 8.2% at December 31, 1999. At
December 31, 1999, outstanding borrowings were $9,100,000. In addition, the
Company has issued letters of credit totaling $2.0 million which further reduces
the amount available for borrowing under the base.
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's predecessor, BFC,
has periodically negotiated extensions and additions to the loan, however, there
is no assurance the Company were be able to do so in the future.
For the twelve months ended December 31, 1999, pro forma net cash used by
operating activities for the Company, and its predecessor, BFC, was $713,000
compared to net cash provided by operating activities of $4,696,000 in 1998.
The decrease was primarily due to changes in operating assets and liabilities.
Pro forma cash used in investing activities was $28,841,000 in 1999 compared to
$5,948,000 in 1998. Pro forma net cash provided by financing activities was
$28,056,000 for 1999 compared to $3,450,000 in 1998. Changes in comparative
investing and financing cash flows were due primarily to the Company's
acquisition of BFC.
The principle source of the Company's funds are cash flows from operating
activities and available borrowings under the Company's existing credit
facility. At December 31, 1999, there were no significant commitments for
capital expenditures. The Company anticipates that capital expenditures,
exclusive of acquisitions (if any) will approximate $5.0 million in 2000. The
Company expects to be able to fund its development and exploration programs for
the next twelve months from cash generated by operations and existing bank
financing.
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.
Year 2000 Compliance
--------------------
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.
-19-
<PAGE>
Disclosures Regarding Forward-Looking Statements
------------------------------------------------
This Annual Report on Form 10-K includes "forward-looking statements". All
statements other than statements of historical facts included in the Annual
Report on Form 10-K are forward-looking statements. 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, reserve estimates (including
estimates of future net revenues associated with such reserves and the present
value of such 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
expectations 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 expectations and assumptions will prove to be correct.
Factors that could cause actual results to differ materially ("Cautionary
Statements") are described, in among other places in the Marketing, Competition,
and Government Regulation sections in this 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 of persons acting on its behalf are
expressly qualified in their entirety by the Cautionary Statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Quantitative and Qualitative Disclosures about Market Risk
----------------------------------------------------------
Interest Rate Risk
Market risk is estimated as the potential change in fair value resulting
from an immediate hypothetical change in interest rates. The sensitivity
analysis presents the change in 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 only has floating rate
debt, interest rate changes would not affect the fair value of these 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 December 31, 1999 and December 31, 1998, the
Company and its predecessor, BFC, had floating rate debt of $9,100,000 and
$5,850,000, respectively. Assuming constant debt levels, earnings and cash flow
impacts for the next twelve month period from December 31, 1999 and December 31,
1998 due to a one percent change in interest rates would be approximately
$91,000 and $58,500, respectively, before taxes.
Foreign Currency Risk
To date the Company's cash flows have been in U.S. dollars only, negating
the need to hedge against any foreign currency risks.
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 uses certain financial instruments in an attempt to manage commodity
price risk. The Company attempts to manage these risks by minimizing its
-20-
<PAGE>
commodity price exposure through the use of derivative contracts as described in
Note 8 to the December 31, 1999 financial statements of Carbon and in Note 8 to
the October 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 December 31,
1999.
Weighted Average
Fixed price
Year MMBTUs per MMBTU
- - - -------------- ------------- ----------------
2000 2,317,500 $ 2.42
2001 1,543,000 $ 2.36
-------------
3,860,500
=============
Weighted Average
Fixed price
Year Barrels per Barrel
- - - -------------- ------------- ----------------
2000 48,000 $ 22.35
As of December 31, 1999, the Company would have been required to pay $733,000 to
exit these contracts and all related hedging obligations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-21-
<PAGE>
Carbon Energy Corporation
Consolidated Financial Statements
-22-
<PAGE>
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Report of Independent Public Accountants......................................24
Consolidated Balance Sheet - December 31, 1999................................25
Consolidated Statement of Operations - For the Period from Inception
(September 14, 1999) through December 31, 1999...........................26
Consolidated Statement of Stockholder's Equity - For the Period from
Inception (September 14, 1999) through December 31, 1999.................27
Consolidated Statement of Cash Flows - For the Period from Inception
(September 14, 1999) through December 31, 1999...........................28
Notes to Consolidated Financial Statements....................................29
-23-
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Carbon Energy Corporation:
We have audited the accompanying consolidated balance sheet of Carbon Energy
Corporation (a Colorado corporation) and subsidiary as of December 31, 1999, and
the related consolidated statements of operations, stockholder's equity and cash
flows for the period from inception (September 14, 1999) through December 31,
1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Carbon Energy
Corporation and subsidiary as of December 31, 1999, and the results of their
operations and their cash flows for the period from inception (September 14,
1999) through December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Denver, Colorado,
March 28, 2000
-24-
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
1999
--------------
ASSETS
------
<S> <C>
Current assets:
Cash $ 995,000
Current portion of employee trust 881,000
Accounts receivable, trade 2,286,000
Accounts receivable, other 69,000
Amounts due from broker 1,250,000
Prepaid expenses and other 107,000
--------------
Total current assets 5,588,000
--------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 7,879,000
Proved properties 25,020,000
Furniture and equipment 214,000
--------------
33,113,000
Less accumulated depreciation, depletion and amortization (627,000)
--------------
Property and equipment, net 32,486,000
--------------
Other Assets:
Deferred acquisition costs 310,000
Deposits and other 245,000
Employee trust 669,000
--------------
Total other assets 1,224,000
--------------
$ 39,298,000
==============
Total Assets
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable and accrued expenses $ 4,391,000
Accrued production taxes payable 367,000
Undistributed revenue 598,000
--------------
Total current liabilites 5,356,000
--------------
Long-term debt 9,100,000
Other long-term liabilites 527,000
------------
Total long-term liabilities 9,627,000
Commitments and contingencies (Note 5) -
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
4,510,000 shares outstanding 24,806,000
Accumulated deficit (491,000)
-------------
Total stockholders' equity 24,315,000
-------------
Total liabilities and stockholders' equity $ 39,298,000
=============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
-25-
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
For the Period from
Inception
(September 14, 1999)
through
December 31,
1999
----------------------
Revenues:
Oil and gas sales $ 1,737,000
Gas marketing and transportation 1,032,000
Other 34,000
---------------------
2,803,000
---------------------
Expenses:
Oil and gas production costs 597,000
Gas marketing and transportation costs 1,028,000
Depreciation, depletion and amortization expense 628,000
General and administrative expense, net 939,000
Interest expense, net 102,000
---------------------
3,294,000
---------------------
Net loss $ (491,000)
=====================
Earings per share
Basic and diluted $ (0.12)
Average number of common shares
outstanding (in thousands):
Basic and diluted 4,056
The accompanying notes are an integral part of these consoldiated financial
statements.
-26-
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY
For the Period from Inception (September 14, 1999) through December 31, 1999
<TABLE>
<CAPTION>
Common Stock
--------------------------------- Accumulated
Shares Amount Deficit Total
-------------- ---------------- ----------------- -------------------
<S> <C> <C> <C>
Balances, September 14, 1999 - $ - $ - $ -
Issuance of common stock 4,510,000 24,806,000 24,806,000
Net loss - (491,000) (491,000)
-------------- ---------------- ----------------- -------------------
Balances, December 31, 1999 4,510,000 $ 24,806,000 $ (491,000) $ 24,315,000
============== ================ ================= ===================
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
-27-
<PAGE>
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
For the Period from
Inception
(September 14, 1999)
through
December 31,
1999
---------------------
<S> <C>
Cash flows from operating activities:
Net loss $ (491,000)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 628,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable, trade 203,000
Amounts due from broker 269,000
Employee trust 17,000
Prepaid expenses and other 38,000
Other assets (337,000)
Increase (decrease) in:
Accounts payable and accrued expenses 711,000
Undistributed revenue (39,000)
---------------------
Net cash provided by operating activities 999,000
Cash flows from investing activities:
Acquisition of Bonneville Fuels Corporation (23,521,000)
Capital expenditures for oil and gas properties (589,000)
---------------------
Net cash used in investing activities (24,110,000)
Cash flows from financing activities:
Proceeds from note payable 400,000
Principal payments on note payable (1,100,000)
Proceeds from issuance of common stock 24,806,000
---------------------
Net cash provided by financing activities 24,106,000
---------------------
Net increase in cash 995,000
Cash, beginning of year ---------------------
Cash, end of year $ 995,000
=====================
Supplemental cash flow information:
Cash paid for interest $ 121,400
=====================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
-28-
<PAGE>
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations and Significant Accounting Policies:
--------------------------------------------------------
Nature of Operation - Carbon Energy Corporation (Carbon) was incorporated
-------------------
under the laws of the State of Colorado on September 14, 1999. Carbon is an
independent oil and gas company engaged in the acquisition, exploration,
development, gathering, production and marketing of natural gas and crude
oil through Bonneville Fuels Corporation (BFC), its wholly owned subsidiary.
BFC also purchases and resells electricity. BFC was acquired by Carbon on
October 29, 1999. The acquisition was accounted for as a purchase as more
fully described in Note 2. BFC was formed in April of 1987, and owns two
active subsidiaries; Bonneville Fuels Management Corporation (BFM Corp.) and
Colorado Gathering Corporation (CGC), and two inactive subsidiaries;
Bonneville Fuels Marketing Corporation (BFMC) and Bonneville Fuels Operating
Corporation (BFO). Collectively, Carbon, BFC and BFC's subsidiaries are
referred to as the Company.
Principles of Consolidation - The consolidated financial statements include
---------------------------
the accounts of Carbon and its consolidated subsidiary. 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. Under this method of accounting, all costs
incurred in the acquisition, exploration and development of properties
(including cost of surrendered and abandoned leaseholds, delay 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 cost 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 3 to 7 years.
-29-
<PAGE>
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 Notes 2 and 4). The current
portion of the employee trust is expected to be disbursed by December 31,
2000.
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 related cost of sales on gas and electricity
marketing transactions using the accrual method of accounting (i.e., the
transaction is recorded when the commodity is purchased and/or delivered).
The Company's gas marketing contracts are generally month-to-month and
provide that the Company will sell gas to end users which is produced from
the Company's properties and/or acquired from third parties.
Income Taxes - The Company accounts for income taxes under the liability
------------
method which requires recognition of deferred tax assets and liabilities for
the expected future tax consequences of events that have been included in
the financial statements or tax returns. Under this method, deferred tax
assets and liabilities are determined based on the difference between the
financial statement and tax basis of assets and liabilities using enacted
tax rates in effect for the year in which the differences are expected to
reverse.
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 in order to mitigate the risk of market price
fluctuations.
Pursuant to Company guidelines, the Company 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. 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 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.
30
<PAGE>
Upon the acquisition of BFC (see Note 2), the Company assumed open hedge
contracts held by BFC that when marked to market reflected an obligation of
$1,733,000. This obligation was recognized as a part of the purchase price
of BFC. The corresponding obligation was recorded as a liability. At
December 31, 1999, this obligation was $1,508,000. The obligations related
to hedge positions which will mature within the year 2000 are included as
current liabilities, while the obligations maturing in 2001 are presented as
other long-term liabilities. The following tables summarize the Company's
derivative financial instrument position on its natural gas and oil
production as of December 31, 1999:
Weighted Average
Fixed price
Year MMBTUs per MMBTU
- - - -------------- ------------- ----------------
2000 2,317,500 $ 2.42
2001 1,543,000 $ 2.36
-------------
3,860,500
=============
Weighted Average
Fixed price
Year Barrels per Barrel
- - - -------------- ------------- ----------------
2000 48,000 $ 22.35
As of December 31, 1999, the Company would have been required to pay
$733,000 to exit these contracts and all related hedging obligations.
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.
Earnings (Loss) Per Share. Basic earnings per share is computed by dividing
-------------------------
income or (loss) available to common shareholders by the weighted average
number of common shares outstanding for the period. Diluted earnings per
share reflects the potential dilution that could occur if the Company's
outstanding stock options were exercised (calculated using the treasury
stock method). The consolidated statement of operations for 1999 reflects
only basic earnings per share because the Company was in a loss position and
all common stock equivalents are anti-dilutive.
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.
2. Purchase of Bonneville Fuels Corporation:
-----------------------------------------
On October 29, 1999, Carbon completed the acquisition of 100% of the stock
of BFC. The purchase price of $38,714,000 was composed of the following:
Current liabilities assumed $ 3,411,000
Open hedges assumed 1,733,000
31
<PAGE>
Long-term debt assumed 9,800,000
Professional fees 189,000
Cash paid 23,581,000
-------------------
$ 38,714,000
===================
3. Long-term debt:
--------------
The Company has an asset-based line-of-credit with a bank which provides for
borrowing up to the borrowing base (as defined). The borrowing base was
$16,400,000 at December 31, 1999. At December 31, 1999, outstanding
borrowings were $9,100,000. The Company has issued letters of credit
totaling $2,000,000, which further reduces the amount available for
borrowing under the base. This facility is collateralized by certain oil
and gas properties of the Company and is scheduled to convert to a term note
on July 1, 2001. This term loan is scheduled to have a maturity of either
the economic half life of the Company's remaining reserves on the date of
conversion, or July 1, 2006, whichever is earlier. The facility bears
interest at prime or (at the Company's option) LIBOR plus 1.75%.
This rate approximated 8.2% at December 31, 1999. The borrowing base is
based upon the lender's evaluation of the Company's proved oil and gas
reserves, generally determined semi-annually.
Scheduled maturities of indebtedness for the next five years are as follows:
Year Maturities
--------- -----------------
(in thousands)
2000 $ --
2001 1,166
2002 2,684
2003 2,095
2004 1,843
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 the bank which provides for
borrowings and letters of credit up to $500,000. There were no outstanding
borrowings under this facility at December 31, 1999, however, there was a
letter of credit issued in the amount of $40,000, which reduces the amount
available under this line. This facility bears interest at prime (8.5% at
December 31, 1999). 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 on employment
contracts or length of service, if the employee is terminated within 2 years
following the effective date of BFC's acquisition by Carbon. The maximum
amount which could be disbursed under the Plan is $1,546,000. The employees
will be required to pay any increased premiums for the insurance benefits
and the Plan insurance commitment is capped at the above amount.
Terminations as of December 31, 1999 will require payments under the Plan of
$438,000. Costs associated with these terminations were expensed by BFC
prior to the acquisition and accrued at December 31, 1999.
32
<PAGE>
At December 31, 1999, contracts with various employees have resulted in the
actual payment or agreement to pay an additional $513,000 from the trust.
These payments were expensed in 1999.
The Company has deposited the maximum amount in a employee trust cash
account. This trust is restricted from disbursing funds except for the
payment of benefits or upon the insolvency of the Company. The amount the
Company is obligated to pay in 2000 due to the above mentioned terminations
and contracts is recorded as a current asset. All remaining amounts are
recorded as long-term assets. The trustee fees were minimal for the period
ending December 31, 1999.
5. Commitments:
-----------
Office Lease - The Company leases office space under a lease which
------------
terminates on March 31, 2000. Total rental expense under this lease was
approximately $25,000 for the two months ended December 31, 1999. With the
acquisition of BFC, the Company assumed the obligations of BFC's office
lease. In conjunction with the acquisition of CEC Resources (see Note 10),
the Company also had an existing office lease obligation prior to the
acquisition of BFC. The Company entered an agreement to buyout the
remaining term of the BFC lease for $100,000. The Company has entered into
a new lease agreement, effective on April 1, 2000, which provides for total
minimum rental commitments as follows:
2000 $ 182,000
2001 197,000
2002 203,000
2003 208,000
2004 212,000
Thereafter 53,000
------------------
$ 1,055,000
==================
33
<PAGE>
6. Stock Options and Award Plans:
-----------------------------
In 1999, the Company adopted a stock option plan to afford an opportunity for
stock ownership to selected employees, directors and consultants of the
Company and its subsidiaries. All salaried employees of the Company and its
subsidiaries who are responsible for the conduct and management of its
business or who are involved in the endeavors significant to its success 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 but who are involved in endeavors significant to its success
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.
The specific terms of grant and exercise are 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. A
summary of the status of the Company's stock option plan as of December 31,
1999 and changes during 1999 is presented below:
1999
----------------------------
Weighted
Average
Exercise
Shares Price
------------ -----------
Outstanding at beginning of period -
Granted 115,000 $ 5.50
Exercised -
Forfeited -
------------
Shares under option at end of year 115,000
============
Options exercisable at year-end -
Shares available for future grant at year-end 585,000
Weighted-average fair value of options
granted during the year $ 1.28
The following table summarizes information about the Company's stock options
outstanding at December 31, 1999.
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
- - - -------------------------------------------------------------------------------- ---------------------------------------------
<CAPTION>
Options Weighted-Avg. Options
Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg.
Exercise Price at Year-end Contractual Life Exercise Price at Year-end Exercise Price
- - - ----------------- ---------------- ------------------- ----------------- ---------------- ------------------
<S> <C> <C> <C> <C> <C>
$5.50 115,000 9.83 years $5.50 - -
</TABLE>
34
<PAGE>
The Company applies APB Opinion No. 25 "Accounting for Stock Issued to
Employees" and related interpretations in accounting for these plans. Under
APB Opinion No. 25 no compensation costs are recognized for option grants
that are equal to or greater than the market price at the time of the grant.
If compensation costs for this plan had been determined consistent with SFAS
No. 123 "Accounting for Stock-Based Compensation," the Company's net loss and
loss per share would have been reduced as follows:
For the Period from Inception
(September 14, 1999) through
December 31, 1999
-----------------------
Net loss:
As reported ($491)
Pro forma ($504)
Loss per share:
As reported ($.12)
Pro forma (S.12)
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following assumptions:
dividend yield of 0%; expected volatility of 24%; risk-free interest rate of
5.97% and expected live of 5 years.
In 1999, the Company adopted a restricted stock plan to afford an opportunity
for stock ownership to 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 shares. In 1999
40,000 shares of restricted shares of common stock were granted. The shares
vest ratably over 36 months.
7. Income Taxes:
-------------
Deferred tax assets are comprised of the following:
As of
December 31,
1999
--------------
(in thousands)
Net operting loss carryforward $ 297
Oil, gas and other property basis
difference (195)
Other 90
--------------
Total deferred tax assets 192
Less valuation allowence (192)
--------------
Net deferral tax assets $ -
==============
8. Concentrations of Credit Risk and Price Risk Management:
--------------------------------------------------------
Concentrations of Credit Risk - Substantially all of the Company's accounts
-----------------------------
receivable at December 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 owners, 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.
9. Fair Value of Financial Instruments:
------------------------------------
The Company's on-balance sheet financial instruments consist of cash, cash
equivalents, accounts receivable, inventories, accounts payable, other
accrued liabilities and long-term debt. Except for long-term debt, the
35
<PAGE>
carrying amounts of such financial instruments approximate fair value due to
their short maturities. At December 31, 1999, the fair market value of
long-term debt was not materially different from its carrying amount. The
Company's off-balance sheet financial instruments consist of derivative
instruments which are intended to manage commodity price risks (see Note 8)
10. Subsequent Event:
-----------------
On January 21, 2000, Carbon commenced an exchange offer for shares of CEC
Resources Ltd. (CEC) whereby Carbon offered to exchange one share of Carbon
common stock for each share of CEC common stock. The exchange offer was one
of the last steps in transactions to combine BFC and CEC. On February 18,
2000, Carbon announced that the Company had completed its offer to exchange
Carbon shares for shares of CEC. Of the 1,521,400 outstanding shares of
CEC, over 97% of the shares were exchanged.
On February 24, 2000 Carbon announced that trading of its shares on the
American Stock Exchange (AMEX) had begun under the trading symbol CRB and
that the AMEX had commenced proceedings to delist the common stock of CEC
(trading symbol CGS). On February 28, 2000, the Securities and Exchange
Commission approved the delisting of CEC's common stock from the AMEX.
11. Oil and Gas Activities (Unaudited)
----------------------------------
Costs Incurred in Property Acquisition,
Exploration and Development Activities
(in thousands)
For the Period
from Inception
(September 14, 1999)
through
December 31,
1999
-----------------------
Acquisition of properties:
Proved properties $ 24,535
Unproved properties 7,879
Exploration 347
Development 84
-----------------------
Total costs incurred $ 32,845
=======================
The Company anticpates that substantially all unevaluated costs will be
classified as evaluated costs within five years.
36
<PAGE>
Capitalized Costs Related to Oil and Gas
Producing Activities
(in thousands)
December 31,
1999
-----------------
Capitalized costs:
Unproved properties not being
amortized $ 7,879
Properties being amortized:
Productive and nonproductive 24,970
Gas transportation system 50
-----------------
Costs being amortized 25,020
Total capitalized costs 32,899
Less: Accumulated DD&A (617)
-----------------
Net capitalized costs $ 32,282
=================
Estimated Oil and Gas Reserve Quantities (Unaudited)
The table below sets forth the estimated quantities of year end proved
reserves at December 31, 1999. The estimates were prepared by Ryder Scott
Company, an independent reservoir engineering firm.
Analysis of Changes in
Proved Oil and Gas Reserves
Oil Natural Gas
--------- ---------------
(MBbl) (MMcf)
Balance, September 14, 1999 - -
Revisions to previous estimates 2 250
Purchase of minerals in place 235 31,331
Production (9) (569)
---------- ---------------
Balance, December 31, 1999 228 31,012
========== ===============
Proved developed reserves:
December 31, 1999 212 26,232
Standardized Measure
The Standardized Measure schedule is presented below pursuant to the
disclosure requirements of the Securities and Exchange Commission and
Statement of Financial Accounting Standards No. 69, "Disclosures About Oil
and Gas Producing Activities" (SFAS No. 69).
37
<PAGE>
Carbon Energy Corporation
Notes to Consolidated Financial Statements
Oil prices of $24.41 per barrel and gas prices of $2.05 per Mcf at December 31,
1999 were used in the estimation of the Company's reserves and future net cash
flows.
The standardized measure is intended to provide a standard of comparable
measurement of the Company's estimated proved oil and gas reserves based on
economic and operating conditions existing as of December 31, 1999. Pursuant to
SFAS No. 69, future oil and gas revenues are calculated by applying to the
proved oil and gas reserves the oil and gas prices at December 31, 1999 relating
to such reserves. Future price changes are considered only to the extent
provided by contractual arrangement in existence at year-end. Production and
development costs are based upon costs at each year-end. Future income taxes are
computed by applying statutory tax rates as of the year end with recognition of
tax basis, net operating loss carryforwards and other statutory deductions.
Discounted amounts are based on a 10% annual discount rate. Changes in the
demand for oil and gas, price changes and other factors make such estimates
inherently imprecise and subject to revision.
Standardized Measure of Discounted Future Net Cash Flows Relating to
Estimated Proved Oil and Gas Reserves
(thousands of dollars)
December 31,
1999
-----------------
Future oil and gas revenue $ 68,542
Future production costs (19,473)
Future development costs (5,916)
Future income taxes (772)
-----------------
Future net cash flows 42,381
Discount at 10% (16,952)
-----------------
Standardized measure of discounted future
net cash flows $ 25,429
=================
______________
(1) The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas
properties but without consideration of general and administrative expenses.
For both standardized measure and ceiling test purposes the Company
estimates future income taxes using the "short-cut" method.
-38-
<PAGE>
Carbon Energy Corporation
Notes to Consolidated Financial Statements
Changes in Standardized Measure of Discounted Future Net Cash Flows
from Estimated Proved Oil and Gas Reserves
(thousands of dollars)
For the Period
from Inception
(September 14, 1999)
through
December 31,
1999
----------------------
Standardized measure-inception (September 14, 1999) $ -
Sales and transfers of oil and gas produced, net
of production costs (1,140)
Net changes in prices and production costs (7,248)
Purchase of reserves in place 34,136
Revisions of previous quantity estimates 23
Accretion of discount 341
Other (683)
----------------------
Net increase 25,429
----------------------
Standardized measure-end of year $ 25,429
======================
-39-
<PAGE>
Bonneville Fuels Corporation
and Subsidiaries
Consolidated Financial Statements
-40-
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Independent Auditor's Report ....................................................... 42
Consolidated Balance Sheets - October 31, 1999 and December 31, 1998 ............... 43
Consolidated Statements of Operations - For the Period From January 1, 1999
through October 31, 1999 and the Years Ended December 31, 1998 and 1997 ....... 44
Consolidated Statement of Stockholder's Equity - For the Period From January 1, 1997
through October 31, 1999 ...................................................... 45
Consolidated Statements of Cash Flows - For the Period From January 1, 1999
through October 31, 1999 and the Years Ended December 31, 1998 and 1997 ....... 46
Notes to Consolidated Financial Statements ......................................... 47
</TABLE>
-41-
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Board of Directors
Bonneville Fuels Corporation
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Bonneville Fuels
Corporation and subsidiaries as of October 31, 1999 and December 31, 1998 and
the related consolidated statements of operations, stockholder's equity, and
cash flows for the period from January 1, 1999 through October 31, 1999 and the
years ended December 31, 1998 and 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Bonneville Fuels
Corporation and subsidiaries as of October 31, 1999 and December 31, 1998, and
the results of their operations and their cash flows for the 10-month period
ended October 31, 1999 and the years ended December 31, 1998 and 1997, in
conformity with generally accepted accounting principles.
Hein + Associates LLP
March 1, 2000
-42-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
October 31, December 31,
----------------------- --------------------
1999 1998
----------------------- --------------------
ASSETS
------
<S> <C> <C>
Current assets:
Cash $ 249,000 $ 2,742,000
Restricted cash in Rabbi Trust 898,000 -
Accounts receivable, trade 2,499,000 4,972,000
Accounts receivable, other 69,000 8,000
Amounts due from broker 1,519,000 534,000
Prepaid expenses and other 131,000 233,000
------------ ------------
Total current assets 5,365,000 8,489,000
------------ ------------
Property and equipment, at cost:
Oil and gas properties, using the successful efforts method:
Unproved properties 3,025,000 2,745,000
Proved properties 34,128,000 29,679,000
Furniture and equipment 499,000 497,000
------------ ------------
37,652,000 32,921,000
Less accumulated depreciation, depletion and amortization (21,022,000) (18,891,000)
------------ ------------
Property and equipment, net 16,630,000 14,030,000
------------ ------------
Other Assets:
Deposits and other 240,000 276,000
Rabbi Trust 648,000 -
Deferred loan costs, net 29,000 45,000
------------ ------------
Total other assets 917,000 321,000
------------ ------------
------------ ------------
Total assets $ 22,912,000 $ 22,840,000
============ ============
LIABILITIES AND STOCKHOLDER'S EQUITY
------------------------------------
Current liabilities:
Accounts payable and accrued expenses $ 2,490,000 $ 7,116,000
Accrued production taxes payable 284,000 335,000
Undistributed revenue 637,000 476,000
------------ ------------
Total current liabilities 3,411,000 7,927,000
------------ ------------
Commitments and contingencies (notes 2, 4, 6 and 8) - -
Long-term debt 9,800,000 5,850,000
Stockholder's equity:
Common stock, $.01 par value; 1,000 shares authorized,
issued, and outstanding - -
Additional paid in capital 3,475,000 3,475,000
Retained earnings 6,226,000 5,588,000
------------ ------------
Total stockholder's equity 9,701,000 9,063,000
------------ ------------
------------ ------------
Total liabilities and stockholder's equity $ 22,912,000 $ 22,840,000
============ ============
</TABLE>
See accompanying notes to these consolidated financial statements.
-43-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
For the Ten
Months Ended For the Years Ended
October 31, December 31,
------------------ ----------------------------------------
1999 1998 1997
------------------ ------------------- -------------------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 7,820,000 $ 6,758,000 $ 6,429,000
Gas marketing and transportation 9,805,000 12,610,000 9,135,000
Electricity sales 1,782,000 1,331,000 506,000
Other 619,000 393,000 469,000
------------------ ------------------- -------------------
20,026,000 21,092,000 16,539,000
------------------ ------------------- -------------------
Expenses:
Oil and gas production costs 2,860,000 3,254,000 2,779,000
Gas marketing and transportation 9,773,000 12,674,000 8,553,000
Cost of electricity 1,729,000 1,137,000 497,000
Depreciation, depletion and amortization expense 2,092,000 2,086,000 1,942,000
Exploration expense 800,000 556,000 772,000
Impairment expense 60,000 1,858,000 312,000
General and administrative expense 1,620,000 1,655,000 590,000
Interest expense 454,000 238,000 83,000
------------------ ------------------- -------------------
19,388,000 23,458,000 15,528,000
------------------ ------------------- -------------------
Income (Loss) Before Taxes 638,000 (2,366,000) 1,011,000
Tax Expense (Benefit):
Current - (225,000) 279,000
Deferred - 50,000 -
------------------ ------------------- -------------------
Net Income (Loss) $ 638,000 $ (2,191,000) $ 732,000
================== =================== ===================
</TABLE>
See accompanying notes to these consolidated financial statements.
-44-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY
For the Period from January 1, 1997 Through October 31, 1999
<TABLE>
<CAPTION>
Common Stock Additional
--------------------------- Paid-in Retained
Shares Par Value Capital Earnings Total
---------- --------------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Balances, January 1, 1997 1,000 $ - $ 1,812,000 $ 7,047,000 $ 8,859,000
Net income - - - 732,000 732,000
----------- -------------- ----------- ----------- -----------
Balances, December 31, 1997 1,000 - 1,812,000 7,779,000 9,591,000
Intercompany payables converted to equity
by parent - - 1,663,000 - 1,663,000
Net loss - - - (2,191,000) (2,191,000)
----------- -------------- ----------- ----------- -----------
Balances, December 31, 1998 1,000 - 3,475,000 5,588,000 9,063,000
Net income - - - 638,000 638,000
----------- -------------- ----------- ----------- -----------
Balances, October 31, 1999 1,000 $ - $ 3,475,000 $ 6,226,000 $ 9,701,000
=========== ============== =========== =========== ===========
</TABLE>
See accompanying notes to these consolidated financial statements.
-45-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Ten
Months Ended For the Year Ended
October 31, December 31,
----------- -------------------------------
1999 1998 1997
----------- ----------- ------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net Income (loss) $ 638,000 $(2,191,000) $ 732,000
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Deferred taxes - 50,000 -
Depreciation, depletion and amortization expense 2,071,000 2,067,000 1,942,000
Impairment of property and equipment 60,000 1,858,000 312,000
Amortization of loan costs 16,000 19,000 19,000
Changes in operating assets and liabilities:
Decrease (increase) in:
Accounts receivable, trade 2,404,000 (2,154,000) (21,000)
Amount due from broker (985,000) (471,000) 152,000
Prepaid expenses and other 110,000 (50,000) (36,000)
Rabbi Trust (1,546,000) - -
Other assets 36,000 41,000 (26,000)
Increase (decrease in):
Accounts payable and accrued expenses (4,626,000) 5,646,000 59,000
Accrued production taxes payable (51,000) 78,000 (77,000)
Undistributed revenues 161,000 28,000 (194,000)
Deferred gain and other liabilities - - 52,000
Taxes payable to parent - (225,000) 279,000
----------- ----------- -----------
Net cash provided (used) by operating activities (1,712,000) 4,696,000 3,193,000
----------- ----------- -----------
Cash flows from investing activities:
Capital expenditures for oil and gas properties (4,731,000) (5,948,000) (4,442,000)
----------- ----------- -----------
Net cash used in investing activities (4,731,000) (5,948,000) (4,442,000)
Cash flows from financing activities:
Proceeds from note payable 6,675,000 4,650,000 3,600,000
Payments on note payable (2,725,000) (1,200,000) (2,900,000)
Production payment received - - 319,000
----------- ----------- -----------
Net cash provided by financing activities 3,950,000 3,450,000 1,019,000
----------- ----------- -----------
Net increase (decrease) in cash and equivalents (2,493,000) 2,198,000 (230,000)
Cash, beginning of year 2,742,000 544,000 774,000
----------- ----------- -----------
Cash, end of year $ 249,000 $ 2,742,000 $ 544,000
=========== =========== ===========
Supplemental disclosures of cash flow information:
Cash paid for interest $ 453,000 $ 236,000 $ 83,000
=========== =========== ===========
Noncash investing and financing activities-intercompany
payable contributed to capital by parent $ - $ 1,663,000 -
=========== =========== ===========
</TABLE>
See accompanying notes to these consolidated financial statements.
-46-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations and Significant Accounting Policies:
--------------------------------------------------------
Nature of Operation - Bonneville Fuels Corporation (BFC), which was 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.
The Company was acquired by Carbon Energy Corporation (Carbon) on October
29, 1999 for approximately $23,858,000. The accompanying financial
statements do not include the purchase price adjustments that will be
recorded by Carbon.
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. The Company consolidates
its pro rata share of oil and gas ventures in these 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.
Restricted Cash in Rabbi Trust - Restricted cash in Rabbi Trust represents
------------------------------
payments to be made within the next year to severed employees.
Gas Marketing - The Company's marketing contracts are generally month-to-
-------------
month or up to eighteen months, and provide that the Company will sell gas
to end users which is produced from the Company's properties and acquired
from third parties.
Amounts Due From Broker- This account generally represents net cash margin
-----------------------
deposits held by a brokerage firm for the Company's trading accounts.
Oil and Gas Producing Activities - The Company follows the "successful
--------------------------------
efforts" method of accounting for its oil and gas properties, all of which
are located in the continental United States. Under this method of
accounting, all property acquisition costs and costs of exploratory and
development wells are capitalized when incurred, pending determination of
whether the well has found proved reserves. If an exploratory well has not
found proved reserves, the costs of drilling the well are charged to
expense. The costs of development wells are capitalized whether productive
or nonproductive.
Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Depreciation and depletion
of capitalized costs for producing oil and gas properties is computed using
the units-of-production method based upon proved reserves for each field.
In 1997, the Company began to accrue for future plugging, abandonment, and
remediation using the negative salvage value method whereby costs are
expensed through additional depletion expense over the remaining economic
lives of the wells. Management's estimate of the total future costs to
plug, abandon, and remediate the Company's share of all existing wells,
including those currently shut in is approximately $3,500,000 net
-47-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of salvage values. The total cumulative amount accrued as additional
depletion for plugging and abandonment is $612,000 at October 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 oil and gas properties to the aggregate
undiscounted future net revenues related to each field. If the net
capitalized costs exceed the limitation, impairment is provided to reduce
the carrying value of the properties in the field to estimated actual value.
The impairment is included as a reduction of gross oil and gas properties in
the accompanying balance sheet. For the 10 months ended October 31, 1999 and
the years ended December 31, 1998 and 1997 the Company recorded impairments
of $60,000, $1,858,000 and $312,000, respectively. Factors causing the
impairment of oil and gas properties were the decline in oil prices
worldwide and the re-assessment of reserve valves on certain producing
properties in 1998 and re-assessment of reserves values on a drilling
venture in 1999. The primary factor causing the impairments in 1997 was the
reevaluation of certain undeveloped leases.
Gains and losses are generally recognized upon the sale of interests in
proved oil and gas properties based on the portion of the property sold.
For sales of partial interests in unproved properties, the Company treats
the proceeds as a recovery of costs with no gain recognized until all costs
have been recovered.
Revenue Recognition - The Company recognizes revenue for oil and gas
-------------------
production upon delivery of the commodity to the purchaser.
The Company records sales and related cost of sales on gas and electricity
marketing transactions using the accrual method of accounting (i.e., the
transaction is recorded when the commodity is purchased and/or delivered).
Undistributed Revenue - Represents amounts due to other owners of jointly
---------------------
owned oil and gas properties for their revenue from the properties.
Energy Marketing Arrangements - In 1998, BFC entered into an agreement to
-----------------------------
manage certain natural gas contracts of an unrelated entity. This agreement
was terminated on April 30, 1999. For some contracts, BFC takes title to
the gas purchased to service these contracts prior to the sale under the
contracts. For these contracts, BFC records all revenue, expenses,
receivables and payables associated with the contracts. In contracts where
title is not taken, BFC records only 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 are removed from the accounts, and
any gains or losses are reflected in current operations.
Deferred Loan Costs - Costs associated with the Company's note payable have
-------------------
been deferred and are being amortized using the effective interest method
over the original term of the note.
Gas Balancing - The Company uses the sales method of accounting for amounts
-------------
received from natural gas sales resulting from production credited to the
Company in excess of its revenue interest share. Under this method, all
proceeds from production credited to the Company are recorded as revenue
until such time as the
-48-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Company has produced its share of related estimated remaining reserves.
Thereafter, additional amounts received are recorded as a liability.
Income Taxes - The Company accounts for income taxes under the liability
------------
method which requires recognition of deferred tax assets and liabilities for
the expected future tax consequences of events that have been included in
the financial statements or tax returns. Under this method, deferred tax
assets and liabilities are determined based on the difference between the
financial statement and tax bases of assets and liabilities using enacted
tax rates in effect for the year in which the differences are expected to
reverse. BPC includes the Company's operations in its consolidated tax
return. Income taxes are allocated by BPC as if the Company were a separate
taxpayer.
Accounting for Hedged Transactions - The Company periodically enters into
----------------------------------
futures, forwards, and swap contracts as hedges of commodity prices
associated with the production of oil and gas and with the purchase and sale
of natural gas in order to mitigate the risk of market price fluctuations.
Changes in the market value of futures, forwards, and swap contracts are not
recognized until the related production occurs or until the related gas
purchase or sale takes place. Realized losses from any positions which were
closed early are deferred and recorded as an asset or liability in the
accompanying balance sheet, until the related production, purchase or sale
takes place. Gains and losses incurred on these contracts are included in
oil and gas revenue or in gas marketing costs in the accompanying statements
of operations.
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.
Impact of Recently Issued Accounting Pronouncements (Unaudited) - In June
---------------------------------------------------------------
1998, the Financial Accounting Standards Board issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities. This
pronouncement is effective for fiscal quarters of fiscal years beginning
after June 15, 2000. SFAS No. 133 requires companies to report all
derivatives at fair value as either assets or liabilities and bases the
accounting treatment of the derivatives on the reasons an entity holds the
instrument. The Company is currently reviewing the effects SFAS No. 133
will have on the financial statements in relation to the Company's hedging
activities.
-49-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Parent Company Bankruptcy and Related Transactions:
--------------------------------------------------
In 1991, BPC filed a petition for re-organization under Chapter 11 of the
U.S. Bankruptcy Code. In 1998, BFC emerged from bankruptcy.
In 1998, BPC approved the conversion of $1,633,000 in taxes payable to
equity.
There are no significant expenses incurred by Bonneville Pacific Corporation
on behalf of Bonneville Fuels Corporation, nor by Bonneville Fuels
Corporation on behalf of Bonneville Pacific Corporation.
3. Long-term Debt:
--------------
The Company has an asset-based line-of-credit with a bank which provides for
borrowing up to the borrowing base (as defined). The borrowing base was
$16,900,000 at October 31, 1999. At October 31, 1999, outstanding
borrowings amounted to $9,800,000. The Company has issued letters of credit
totaling $2,167,000, which further reduces the amount available for
borrowing under the base. This facility is collateralized by certain oil
and gas properties of the Company and is scheduled to convert to a term note
on July 1, 2001. This term loan is scheduled to have a maturity of either
the economic half life of the Company's remaining reserves on the date of
conversion, or July 1, 2006, whichever is earlier. The facility bears
interest at prime (8.5% at October 31, 1999). The borrowing base is based
upon the lender's evaluation of BFC's proved oil and gas reserves, generally
determined semi-annually. The future minimum principal payments under the
term note will be dependent upon the bank's evaluation of the Company's
reserves at that time.
The Company also has an accounts receivable-based credit facility which
includes a revolving line-of-credit with the bank which provides for
borrowings and letters of credit up to $1,500,000. There were no
outstanding borrowings under this facility at October 31, 1999, however,
there was a letter of credit issued in the amount of $40,000, which reduces
the amount available under this line. This facility bears interest at prime
(8.5% at October 31, 1999). This facility is collateralized by certain
trade receivables of BFC and has a maturity date of July 1, 2001.
The credit agreement contains various covenants which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, repay debt to the Parent, sell properties or merge with
another entity. The Company is also required to maintain certain financial
ratios. The bank waived the non-merger covenants in connection with the
acquisition by Carbon.
4. Salary Continuation Plan:
------------------------
In 1999, the Company 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 on employment
contracts or length of service, if the employee is terminated within 2 years
following the effective date of the Company's acquisition by Carbon. The
maximum amount which could be disbursed under the Plan is $1,546,000.
The employees will be required to pay any increased premiums for the
insurance benefits and the Plan insurance commitment is capped at the above
amount.
-50-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Terminations as of October 31, 1999 will require payment out of the Rabbi
Trust in the amount of $438,000. Cost associated with these terminations
has been expensed in the current period, and accrued for as of October 31,
1999. No additional terminations are expected as of October 31, 1999.
Subsequent to October 31, 1999, contracts with various employees has
resulted in the actual payment or agreement to pay an additional $460,000
from the trust within the next 12 months. These payments will be expensed
subsequent to October 31, 1999.
The Company has deposited the maximum amount noted above in a Rabbi Trust
cash account. This Trust is restricted from disbursing funds except for the
payment of benefits or upon the insolvency of the Company. The amounts to
be paid in 2000 are recorded as a current asset. All remaining amounts are
recorded as a long-term asset. The trustee fees were not material for the
period ending October 31, 1999.
5. Exploration Expense:
-------------------
Exploration expense consists of the following:
<TABLE>
<CAPTION>
For the
Ten Months
Ended For the Year Ended
October 31, December 31,
------------------- ----------------- ------------------
1999 1998 1997
------------------- ----------------- ------------------
<S> <C> <C> <C>
Annual rental payments on unproved properties $ 20,000 $ 82,000 $ 84,000
Geological and geophysical cost 476,000 390,000 89,000
Dry hold costs and abandonments 304,000 84,000 599,000
------------------- ----------------- ------------------
$ 800,000 $ 556,000 $ 772,000
=================== ================= ==================
</TABLE>
6. Commitments:
-----------
Office Lease - The Company leases office space under a noncancellable
------------
operating lease. Total rental expense was approximately $123,000, $139,000
and $58,000 for the 10 months ended October 31, 1999 and for the years ended
December 31, 1998 and 1997, respectively. The Company has a lease agreement
which provides for total minimum rental commitments of:
Remaining 1999 $ 24,000
2000 152,000
2001 158,000
2002 164,000
2003 28,000
------------
$ 526,000
============
-51-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Well Connection Reimbursement - The Company entered into a contract with an
-----------------------------
unrelated party in 1997 to connect certain wells to sales pipelines. The
Company is obligated to reimburse the unrelated party for the difference
between the gathering fees generated by these wells and the cost of
connection. The accompanying financial statements contain an accrual of
$250,000, representing management's current estimate of the potential
liability under this agreement.
7. Income Taxes:
------------
The components of the net deferred tax assets are as follows:
<TABLE>
<CAPTION>
As of As of
October 31, December 31,
--------------- ----------------
1999 1998
--------------- ----------------
<S> <C> <C>
Excess of tax basis over book basis of oil and gas properties $ 3,153,000 $ 1,873,000
Deferred tax assets 3,153,000 1,873,000
Less valuation allowance (3,153,000) (1,873,000)
----------- -----------
Net deferred tax assets $ - $ -
=========== ===========
</TABLE>
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.
8. Concentrations of Credit Risk and Price Risk Management:
-------------------------------------------------------
Concentrations of Credit Risk - Substantially all of the Company's accounts
-----------------------------
receivable at October 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 is derived from natural gas reserves.
Energy Financial Instruments - BFC uses energy financial instruments and
----------------------------
long-term user contracts to minimize its risk of price changes in the spot
and fixed price natural gas and crude oil markets. Energy risk management
products used include commodity futures and 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 October 31, 1999, BFC has financial
contracts which hedge a total of 4.1 Bcf (billion cubic feet) of production
through December 31, 2001.
-52-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The difference between the current market value of the hedging contracts and
the original market value of the hedging contracts was an unfavorable
$1,733,000 as of October 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 at October 31,
1999.
9. Financial Instruments:
---------------------
SFAS Nos. 107 and 127 requires certain entities to disclose the fair value of
certain financial instruments in their financial statements. Accordingly,
management's best estimate is that the carrying amount of cash, receivables,
notes payable, accounts payable, undistributed revenue, and accrued expenses
approximates fair value of these instruments. See Note 8 for a discussion
regarding the fair value of energy financial instruments.
-53-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Unaudited Supplemental Oil and Gas Reserve Information:
------------------------------------------------------
Estimated Reserve Oil and Gas Quantities
The table below sets forth the estimated quantities of year end proved
reserves at October 31, 1999 and December 31, 1998 and 1997. The estimates
were prepared by Ryder Scott Company, and independent reservoir engineering
firm.
Proved Oil and Gas Reserves
Oil Natural Gas
------- --------
(MBbl) (MMcf)
December 31, 1996 227 26,512
Revisions to previous estimates 3 (1,569)
Extensions and discoveries 32 427
Purchase of minerals in place 99 916
Production (63) (3,146)
------- -------
December 31, 1997 298 23,140
Revisions to previous estimates (101) 976
Extensions and discoveries 34 5,011
Purchase of minerals in place 0 0
Production (65) (3,272)
------- -------
December 31, 1998 166 25,855
Revisions to previous estimates 46 2,044
Extensions and discoveries 78 6,937
Purchase of minerals in place 0 0
Production (55) (3,505)
------- -------
October 31, 1999 235 31,331
Proved developed reserves:
December 31, 1997 298 22,623
December 31, 1998 166 25,855
October 31, 1999 221 26,801
-54-
<PAGE>
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Standardized Measure
The Standardized Measure schedule is presented below pursuant to the
disclosure requirements of the Securities and Exchange Commission and
Statement of Financial Accounting Standards No. 69, "Disclosures About Oil
and Gas Producing Activities" (SFAS 69). Future cash flows are calculated
using year-end oil and gas prices and operating expenses, and are
discounted using a 10% discount factor.
Oil and gas prices at October 31, 1999 and December 31, 1998 and 1997 of
$19.68 $10.69 and $16.91 respectively, per barrel of oil and $2.50, $1.84
and $1.81 respectively, per Mcf of gas were used in the estimation of
Carbon's reserves and future net cash flows.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and
gas reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions. Future income tax expense
has not been provided based on the availability of net operating loss carry
forwards and other deductions available to the parent of the Company.
The standardized measure is intended to provide a standard of comparable
measurement of Carbon's estimated proved oil and gas reserves based on
economic and operating conditions existing as of October 31, 1999, and
December 31, 1998 and 1997. Pursuant to SFAS 69, future oil and gas
revenues are calculated by applying to the proved oil and gas reserves the
oil and gas prices at the end of each reporting period relating to such
reserves. Future price changes are considered only to the extent provided
by contractual arrangement in existence at the report date. Production and
development costs are based upon costs at the report date. Discounted
amounts are based on a 10% annual discount rate. Changes in the demand for
oil and gas, price changes and other factors make such estimates inherently
imprecise and subject to revision.
Standardized Measure of Discounted Future Net Cash Flows
Relating to Estimated Proved Oil and Gas Reserves
(thousands of dollars)
<TABLE>
<CAPTION>
October 31, December 31, December 31,
1999 1998 1997
----------------- ----------------- -----------------
<S> <C> <C> <C>
Future oil and gas revenue $82,818 $49,428 $46,859
Future production and development costs (26,490) (18,507) (18,155)
----------------- ----------------- -----------------
Future net cash flows 56,328 30,921 28,704
Discount @ 10% (22,192) (10,426) (9,075)
----------------- ----------------- -----------------
Standardized measure of discounted future
net cash flows $34,136 $20,495 $19,629
================= ================= =================
</TABLE>
-55-
<PAGE>
Change in Standardized Measure of Discounted Future
Net Cash Flows from Estimated Proved Oil and Gas Reserves
(thousands of dollars)
<TABLE>
<CAPTION>
October 31, December 31, December 31,
1999 1998 1997
---------------------- ----------------- ------------------
<S> <C> <C> <C>
Standardized measure-beginning of period $20,495 $19,629 $40,011
Sales and transfers of oil and gas produced, net
of production costs (4,960) (3,754) (3,650)
Net changes in prices and production costs 10,834 (999) (20,485)
Extensions, discoveries and other additions 4,576 4,699 756
Purchase of reserves in place 0 147 1,610
Revisions of future development costs (310) 87 1,069
Revisions of previous quantity estimates 2,818 279 (1,098)
Accretion of discount 1,708 1,963 4,001
Other (1,025) (1,556) (2,585)
---------------------- ----------------- ------------------
Net increase (decrease) 13,641 866 (20,382)
---------------------- ----------------- ------------------
Standardized measure-end of period $34,136 $20,495 $19,629
====================== ================= ==================
</TABLE>
Costs Incurred in Property Acquisition,
Exploration and Development Activities
(in thousands)
<TABLE>
<CAPTION>
Ten months
ended Year ended Year ended
October 31, December 31, December 31,
1999 1998 1997
----------------------- ----------------- -----------------
<S> <C> <C> <C>
Acquisition of properties:
Proved properties - $ 95 $ 2,230
Unproved properties 248 473 -
Exploration 3,088 1,932 599
Development 1,371 3,784 1,812
----------------------- ----------------- -----------------
Total costs incurred $ 4,707 $ 6,284 $ 4,641
======================= ================= =================
</TABLE>
-56-
<PAGE>
Capitalized Costs Related to Oil and Gas
Producing Activities
(in thousands)
<TABLE>
<CAPTION>
October 31, December 31,
1999 1998
----------------- -----------------
<S> <C> <C>
Capitalized costs:
Unproven properties not being
amortized $ 3,025 $ 2,745
Properties being amortized:
Productive and nonproductive 33,970 29,521
Gas transportation system 158 158
----------------- -----------------
Costs being amortized 34,128 29,679
Total capitalized costs 37,153 32,424
Less: Accumulated DD&A (21,022) (18,891)
----------------- -----------------
Net capitalized costs $ $ 16,131 $ 13,533
================= =================
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
-57-
<PAGE>
PART III
--------
ITEM 10. DIRECTORS and Executive Officers of the Registrant.
ITEM 11. Executive Compensation.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.
ITEM 13. Certain Relationships and Related Transactions.
For Part III, the information set forth in the Company's definitive Proxy
Statement for the Company's 2000 Annual Meeting of Shareholders, to be filed, is
incorporated by reference into this Report.
-58-
<PAGE>
PART IV
-------
ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) (1) Financial Statements:
See indexes to Financial Statements of Carbon and BFC in Item 8.
Schedules are omitted because of the absence of the conditions under which
they are required or because the information is included in the financial
statements or notes to the financial statements.
(b) Reports on Form 8-K:
The following report was filed by the Company on Form 8-K during the
quarter ended December 31, 1999: None.
(c) Exhibits:
<TABLE>
<CAPTION>
Exhibit
Number Description of Exhibit
- - - ------------ ----------------------------------------------------------------------------------------------
<C> <S>
3.1 Articles of Incorporation of Carbon Energy Corporation, incorporated by reference to Exhibit
2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18,
2000.
3.2 Bylaws of Carbon Energy Corporation, incorporated by reference to Exhibit 3 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.1 1999 Stock Option Plan, incorporated by reference to Exhibit 10.1 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.2 1999 Restricted Stock Plan, incorporated by reference to Exhibit 10.2 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.3 Exchange and Financing Agreement dated October 14, 1999 among Carbon Energy Corporation, CEC
Resources Ltd. and Yorktown Energy Partners III, L.P., incorporated by reference to Exhibit
10.3 of the Company's registration statement on Form S-4, No. 333-89783, effective January
18, 2000.
10.4 Stock Purchase Agreement dated August 11, 1999 between Bonneville Pacific Corporation and CEC
Resources Ltd., incorporated by reference to Exhibit 10.4 of the Company's registration
statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.5 Form of Indemnification Agreement between Carbon Energy Corporation and its officers and
directors, incorporated by reference to Exhibit 10.5 of the Company's registration statement
on Form S-4, No. 333-89783, effective January 18, 2000.
10.6 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation
and Patrick R. McDonald, incorporated by reference to Exhibit 10.6 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.7 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation
and Kevin D. Struzeski, incorporated by reference to Exhibit 10.7 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
</TABLE>
-59-
<PAGE>
<TABLE>
<CAPTION>
<C> <S>
10.8 Amended and Restated Credit Agreement dated as of May 31, 1994 among Bonneville Fuels
Corporation, Bonneville Fuels Marketing Corporation, Colorado Gathering Corporation,
Bonneville Fuels Operating Corporation and Bonneville Fuels Management Corporation
("Borrowers") and First Interstate Bank of Denver, N.A. ("Lender"); Revolving Note for
$20,000,000 dated May 31, 1994 from Borrowers to Lender; Promissory Note for $1,000,000 from
Borrowers to Lender dated May 31, 1994; Term Note for $20,000,000 from Borrowers to Lender
dated May 31, 1994; as amended by Note Modification Agreement dated April 1, 1995, among
Borrowers and Lender; Amendment to Credit Agreement dated as of April 1, 1995 among Borrowers
and Lender; Note Modification Agreement dated May 1, 1996 among Borrowers and Lender; Second
Amendment to Credit Agreement dated as of April 1, 1996 among Borrowers and Lender; Loan
Transfer Agreement dated as of September 18, 1996 among Borrowers, Wells Fargo Bank
(Colorado), N.A. formerly known as First Interstate Bank of Denver, N.A., and Colorado
National Bank ("CNB"); Third Amendment of Amended and Restated Credit Agreement dated as of
September 18, 1996 among Borrowers and CNB; Fourth Amendment of Amended and Restated Credit
Agreement dated as of May 15, 1998 among Borrowers and CNB; and Fifth Amendment of Amended
and Restated Credit Agreement dated as of June 1, 1999 among Borrowers and CNB, all
incorporated by reference to Exhibit 10.8 of the Company's registration statement on Form
S-4, No. 333-89783, effective January 18, 2000.
24 Power of Attorney.
27 Financial Data Schedule.
</TABLE>
-60-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 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.
Date: March 30, 2000.
CARBON ENERGY CORPORATION
By: /s/ Patrick R. McDonald
------------------------------------
Patrick R. McDonald, President
By: /s/ Kevin D. Struzeski
------------------------------------
Kevin D. Struzeski, Treasurer and
Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons of the Registrant and in
the capacities and on the dates indicated:
<TABLE>
<CAPTION>
Date Name and Title Signature
- - - ---- -------------- ---------
<S> <C> <C>
March 30, 2000 Cortlandt S. Dietler, )
Director )
) /s/ Patrick R. McDonald
) ------------------------------------------
March 30, 2000 David H. Kennedy, ) Patrick R. McDonald, for himself and
Director ) as Attorney-in-Fact for the named
) directors who together constitute all
March 30, 2000 Bryan H. Lawrence, ) of the members of Registrant's Board
Director ) of Directors
)
March 30, 2000 Peter A. Leidel, )
Director )
)
March 30, 2000 Patrick R. McDonald, )
Director )
)
March 30, 2000 Harry A. Trueblood, Jr., )
Director )
)
)
)
)
</TABLE>
-61-
<PAGE>
Exhibit Index
<TABLE>
<CAPTION>
Exhibit
Number Description of Exhibit
- - - ------ ----------------------
<C> <S>
3.1 Articles of Incorporation of Carbon Energy Corporation, incorporated by reference to Exhibit
2 of the Company's registration statement on Form S-4, No. 333-89783, effective January 18,
2000.
3.2 Bylaws of Carbon Energy Corporation, incorporated by reference to Exhibit 3 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.1 1999 Stock Option Plan, incorporated by reference to Exhibit 10.1 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.2 1999 Restricted Stock Plan, incorporated by reference to Exhibit 10.2 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.3 Exchange and Financing Agreement dated October 14, 1999 among Carbon Energy Corporation, CEC
Resources Ltd. and Yorktown Energy Partners III, L.P., incorporated by reference to Exhibit
10.3 of the Company's registration statement on Form S-4, No. 333-89783, effective January
18, 2000.
10.4 Stock Purchase Agreement dated August 11, 1999 between Bonneville Pacific Corporation and CEC
Resources Ltd., incorporated by reference to Exhibit 10.4 of the Company's registration
statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.5 Form of Indemnification Agreement between Carbon Energy Corporation and its officers and
directors, incorporated by reference to Exhibit 10.5 of the Company's registration statement
on Form S-4, No. 333-89783, effective January 18, 2000.
10.6 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation
and Patrick R. McDonald, incorporated by reference to Exhibit 10.6 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.7 Form of Employment Agreement, dated as of October 29, 1999, between Carbon Energy Corporation
and Kevin D. Struzeski, incorporated by reference to Exhibit 10.7 of the Company's
registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
10.8 Amended and Restated Credit Agreement dated as of May 31, 1994 among Bonneville Fuels
Corporation, Bonneville Fuels Marketing Corporation, Colorado Gathering Corporation,
Bonneville Fuels Operating Corporation and Bonneville Fuels Management Corporation
("Borrowers") and First Interstate Bank of Denver, N.A. ("Lender"); Revolving Note for
$20,000,000 dated May 31, 1994 from Borrowers to Lender; Promissory Note for $1,000,000 from
Borrowers to Lender dated May 31, 1994; Term Note for $20,000,000 from Borrowers to Lender
dated May 31, 1994; as amended by Note Modification Agreement dated April 1, 1995, among
Borrowers and Lender; Amendment to Credit Agreement dated as of April 1, 1995 among Borrowers
and Lender; Note Modification Agreement dated May 1, 1996 among Borrowers and Lender; Second
Amendment to Credit Agreement dated as of April 1, 1996 among Borrowers and Lender; Loan
Transfer Agreement dated as of September 18, 1996 among Borrowers, Wells Fargo Bank
(Colorado), N.A. formerly known as First Interstate Bank of Denver, N.A., and Colorado
National Bank ("CNB"); Third Amendment of Amended and Restated Credit Agreement dated as of
September 18, 1996 among Borrowers and CNB; Fourth Amendment of Amended and Restated Credit
Agreement dated as of May 15, 1998 among Borrowers and CNB; and Fifth Amendment of Amended
and Restated Credit Agreement dated
</TABLE>
-62-
<PAGE>
<TABLE>
<CAPTION>
<C> <S>
as of June 1, 1999 among Borrowers and CNB, all incorporated by reference to Exhibit 10.8 of
the Company's registration statement on Form S-4, No. 333-89783, effective January 18, 2000.
24 Power of Attorney.
27 Financial Data Schedule.
</TABLE>
-63-
<PAGE>
EXHIBIT 24
POWER OF ATTORNEY
Each of the undersigned directors and/or officers of Carbon Energy
Corporation (the "Company") hereby authorizes Patrick R. McDonald and Kevin D.
Struzeski, and each of them, as their true and lawful attorneys-in-fact and
agents (1) to sign in the name of the undersigned and file with the Securities
and Exchange Commission the Company's annual report on Form 10-K, for the fiscal
year ended December 31, 1999, and any amendments to such annual report; and (2)
to take any and all actions necessary or required in connection with such annual
report to comply with the Securities Exchange Act of 1934, as amended, and the
rules and regulations of the Securities and Exchange Commission promulgated
thereunder.
<TABLE>
<CAPTION>
Signature Title Date
- - - --------- ----- ----
<S> <C> <C>
/s/ Patrick R. McDonald Director and President ______________
- - - ---------------------------------------
Patrick R. McDonald
/s/ Kevin D. Struzeski Treasurer and Chief Financial ______________
- - - --------------------------------------- Officer
Kevin D. Struzeski
/s/ Cortlandt S. Dietler Director ______________
- - - ---------------------------------------
Cortlandt S. Dietler
/s/ David H. Kennedy Director ______________
- - - ---------------------------------------
David H. Kennedy
/s/ Bryan H. Lawrence Director ______________
- - - ---------------------------------------
Bryan H. Lawrence
/s/ Peter A. Leidel Director March 27, 2000
- - - ---------------------------------------
Peter A. Leidel
/s/ Harry A. Trueblood, Jr. Director March 27, 2000
- - - ---------------------------------------
Harry A. Trueblood, Jr.
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> OTHER
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> SEP-14-1999
<PERIOD-END> DEC-31-1999
<CASH> 995,000
<SECURITIES> 0
<RECEIVABLES> 2,355,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 5,588,000
<PP&E> 33,113,000
<DEPRECIATION> (627,000)
<TOTAL-ASSETS> 39,298,000
<CURRENT-LIABILITIES> 5,356,000
<BONDS> 0
0
0
<COMMON> 24,806,000
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 39,298,000
<SALES> 2,769,000
<TOTAL-REVENUES> 34,000
<CGS> 1,625,000
<TOTAL-COSTS> 3,192,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 102,000
<INCOME-PRETAX> (491,000)
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (491,000)
<EPS-BASIC> (.12)
<EPS-DILUTED> (.12)
</TABLE>
