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, 2000 1-15639
CARBON ENERGY CORPORATION
(Exact name of Registrant as specified in its 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 21, 2001
is $8,899,832.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of March 21, 2001.
Outstanding at
Class March 21, 2001
----- --------------
Common Stock, no par value 6,076,992 shares
The Company's Proxy Statement for the 2001 Annual Meeting of Shareholders
is incorporated by Reference into Part III
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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 conducts the Company's operations in the United States and the assets of
CEC Resources Ltd. (CEC) which conducts the Company's operations in Canada. As
the parent company, Carbon provides management services to BFC and CEC.
Carbon is an independent oil and gas company engaged in the exploration,
development and production of natural gas and crude oil in the United States and
Canada. The Company's core areas in the United States include the Piceance Basin
in Colorado, the Uintah Basin in Utah, the Permian Basin in New Mexico and Texas
and the Hugoton Basin in Southwest Kansas. The Company's core areas in Canada
include the Carbon Field area of Central Alberta and Southeast Saskatchewan.
All amounts are presented in U.S. dollars unless otherwise noted.
At December 31, 2000, the Company had 56.8 billion cubic feet of natural gas
equivalent ("Bcfe" where one barrel of oil is equivalent to six thousand cubic
feet of gas) proved reserves. This was a 9.6 Bcfe or 20% increase from the net
proved reserves of 47.1 Bcfe reported at December 31, 1999 for Carbon's
subsidiaries, BFC and CEC. Net proved natural gas reserves totaled 51.0 Bcf of
gas at December 31, 2000 compared to 43.6 Bcfe at year end 1999, an increase of
7.4 Bcf or 17%. Crude oil and natural gas liquids at December 31, 2000 totaled
968,000 barrels compared to 588,000 barrels at year end 1999, an increase of
380,000 barrels or 65%. Of these proved reserves, approximately 90% on a Mcfe
basis are gas and approximately 83% are categorized as proved developed. The
reserves had an estimated pretax present value, discounted at 10% of $265
million based upon existing prices and costs at December 31, 2000.
The Company's estimated reserves at December 31, 2000 included volumes
attributable to Carbon's working interests in 40 natural gas wells located in
the Kutz Field, San Juan County, New Mexico. The Kutz property was sold January
5, 2001. The proved reserves for the Kutz property were estimated to be 38,000
barrels of oil and 5.6 Bcf of natural gas. These reserves had an estimated
pretax present value, discounted at 10% of $24 million.
At December 31, 2000, Carbon's U.S. exploration and production operations
were comprised of working interests in approximately 265 producing oil and
gas wells. Carbon operates 168 of these wells. The Company had an interest in
over 148,000 net acres of oil and gas leases primarily located in the
Piceance Basin of Colorado, the Uintah Basin of Utah, the Permian Basin of
New Mexico and the Hugoton Basin of Southwest Kansas. For the year ended
December 31, 2000, the Company's average net production in the United States
was 10.3 MMcfe per day.
At December 31, 2000, Carbon's Canadian exploration and production operations
were comprised of working interests in 68 producing oil and natural gas wells
located in Alberta and Saskatchewan. Carbon operates 33 of these wells. The
Company had an interest in over 26,000 net acres of oil and gas leases. The
Company's average net production before Crown royalty interest, subsequent to
the Company's acquisition of CEC in February 2000, was 6.3 MMcfe per day.
BFC was acquired by the Company on October 29, 1999 in a stock purchase. 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 all outstanding shares of BFC for $23,858,000 in cash
and the assumption of certain liabilities, subject to certain adjustments.
Rights and obligations of CEC under the stock purchase agreement were assigned
to Carbon. The purchase of BFC stock under the stock purchase agreement was
completed by Carbon rather than CEC. Yorktown Energy Partners III, LP (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
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purchase agreement and to pay expenses incurred in connection with the purchase
and related transactions. The total cash purchase price after adjustments for
BFC was $23,521,000.
On January 21, 2000, Carbon commenced an exchange offer for shares of CEC. In
the exchange offer, Carbon offered to exchange one share of Carbon for each
share of CEC. On February 18, 2000, Carbon announced that the Company had
completed its offer to exchange Carbon shares for shares of CEC. Of the
1,521,000 outstanding shares of CEC, over 97% of the shares were exchanged.
Carbon began trading its shares on the American Stock Exchange on February 24,
2000 under the trading symbol CRB. On February 28, 2000, at the request of CEC,
the Securities and Exchange Commission (SEC) approved the delisting of CEC's
common stock from the American Stock Exchange (AMEX).
On November 22, 2000, CEC initiated an offer to purchase shares (the Offer) of
CEC stock that were not owned by Carbon. The Offer was completed on February 6,
2001. CEC conducted the Offer in order to avoid the administrative costs and
time involved in corresponding with a small number of minority shareholders. The
Offer was made by CEC at the direction of the Board of Directors of CEC. The
Board of Directors of CEC maintained a neutral position in regard to the Offer
because of potential conflicts of interest. Of the approximate 39,000 shares of
CEC that were not acquired by Carbon in the original Offer to Exchange,
approximately 34,000 shares of CEC stock were purchased by CEC pursuant to the
Offer. Carbon currently owns 99.7% of the stock of CEC.
BUSINESS STRATEGY
The Company's objective is to build shareholder value through consistent growth
in reserves and production and the resultant increase in net asset value, cash
flow, and earnings per share. Our business strategy is to grow through the
exploitation of existing oil and gas properties by development of proved
undeveloped reserves, by the acquisition of complementary working interests and
adjacent properties and through the optimization of gathering, compression and
processing facilities. In addition, we will conduct exploration activities for
oil and gas on our leases. Management believes that the Company's existing
infrastructure and its acreage position in the Piceance Basin in Colorado and
the Uintah Basin in Utah and the Carbon and Rowley areas of Alberta, Canada
provide the Company with a good opportunity to achieve its objectives. The
Company will also selectively pursue acquisition opportunities in existing and
future core areas.
EMPLOYEES AND OFFICES
As of December 31, 2000, the Company had 25 employees located in Denver,
Colorado and six in Calgary, Alberta. 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
UNITED STATES
Piceance and Uintah Basins - At December 31, 2000, Carbon owned working
interests in 126 producing wells in the Piceance Basin of Colorado and Uintah
Basin of Utah. Carbon operates 112 wells of these wells. For the year ended
December 31, 2000, the Company did not participate in any drilling activities in
these basins. The Company has leasehold rights in approximately 129,000 gross
and 106,000 net acres of which approximately 91,000 gross and 73,000 net acres
are undeveloped. Carbon's focus in the United States during 2001 is to continue
the development of its natural gas properties in the Rocky Mountains, with
emphasis on the Piceance and Uintah Basins.
Permian Basin - At December 31, 2000, Carbon owned working interests in 81
producing wells in the Permian Basin of New Mexico and Texas. Carbon operates
twelve of these wells. For the year ended December 31, 2000, the Company
participated in the drilling of ten wells (2.3 net), of which nine (2.0 net)
were completed as oil wells. The Company has leasehold rights in approximately
27,000 gross and 9,000 net acres of which approximately 10,000 gross and 4,000
net acres are undeveloped.
-3-
Hugoton Basin - At December 31, 2000, Carbon owned working interest in 18
producing wells in the Hugoton Basin of Southwestern Kansas. Carbon operates
four of these wells. For the year ended December 31, 2000, the Company
participated in the drilling of four wells (3.5 net), of which one (1.0 net) was
completed as an oil well. The Company has leasehold rights in approximately
27,000 gross and 21,000 net acres of which approximately 24,000 gross and 20,000
net acres are undeveloped.
San Juan Basin - At December 31, 2000, Carbon owned working interests in 40
producing wells in the San Juan Basin of New Mexico, all of which it
operates. For the year ended December 31, 2000, the Company did not
participate in any drilling activities in this basin. The Company has
leasehold rights in approximately 5,000 gross and 4,000 net acres of which
approximately 2,000 gross and 1,000 net acres are undeveloped. In January
2001, Carbon announced that it had closed the sale of its entire working
interests and related leasehold rights in the San Juan Basin. The effective
date of the sale was September 1, 2000 and the purchase price was $7.5
million, subject to certain adjustments. The Company expects to utilize the
proceeds from the sale to partially fund its 2001 drilling program.
CANADA
Alberta - At December 31, 2000, Carbon owned working interests in 58 producing
wells primarily in the Carbon and Rowley areas of Alberta. Carbon operates 33 of
these wells. For the year ended December 31, 2000, the Company participated in
the drilling of eight wells (4.9 net), all of which were completed as gas wells.
These activities were conducted during the fourth quarter of 2000. The Company
has leasehold rights in approximately 42,000 gross and 24,000 net acres of which
approximately 12,000 gross and 7,000 net acres are undeveloped. Carbon's focus
in Canada during 2001 is to continue the development of its natural gas
properties in central Alberta, with emphasis on the Carbon and Rowley areas.
Saskatchewan - At December 31, 2000, Carbon owned non-operating working
interests in ten producing wells in Southeast Saskatchewan. For the year ended
December 31, 2000, the Company did not participate in any drilling activities in
this area. The Company has leasehold rights in approximately 7,000 gross and
3,000 net acres of which approximately 6,000 gross and 3,000 net acres are
undeveloped.
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RESERVES
The table below sets forth the Company's estimated quantities of historical
proved reserves and the present values attributable to those reserves as of
December 31, 2000, 1999 and 1998. The estimates for the Company's reserves in
the United States were prepared by Ryder Scott Company, an independent reservoir
engineering firm and the estimates for the Company's reserves in Canada were
prepared by Sproule Associates Limited, independent geological and petroleum
engineering consultants. Additional information regarding the Company's proved
and proved developed oil and gas reserves and the standardized measure of
discounted net cash flow and changes therein are described in Note 14 to the
December 31, 2000 financial statements of Carbon and in Note 10 to the October
31, 1999 financial statements of BFC.
United States Canada (2)
--------------------------------------------- -------------
2000 1999 1998 (1) 2000
-------------- ------------- ------------- -------------
(dollars in thousands, except price data)
Estimated proved reserves
Natural gas (MMcf) 32,100 31,012 25,855 18,867
Oil and liquids (MBbl) 507 228 166 461
Total Mcfe 35,142 32,380 26,851 21,633
Proved developed reserves (MMcfe) (3) 28,714 27,504 26,851 18,659
Natural gas price as of December 31 ($/Mcf) $ 9.76 $ 2.05 $ 1.84 $ 9.00
Oil and liquids price as of December 31 ($/Bbl) $ 25.50 $ 24.41 $ 10.69 $ 21.73
Present value of estimated future net revenues
before future income taxes, discounted at 10% $153,528 $ 25,894 $ 20,495 $111,461
- ----------------------
(1) Reserves for December 31, 1998 are for the Company's predecessor, BFC.
(2) Canadian reserves are presented only for December 31, 2000 as the
Company acquired CEC in February 2000.
(3) Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and
operating methods.
The estimate of net proved reserves at December 31, 2000 included volumes
attributable to the Company's working interest in 40 natural gas wells
located in the San Juan Basin of New Mexico. These properties were sold in
January 2001. The proved reserves for these properties were estimated to be
38,000 barrels of oil and 5.6 Bcf of natural gas. The present value of
estimated future net revenues before future income tax, discounted at 10% for
these properties were $24.0 million.
In accordance with applicable requirements of the Securities and Exchange
Commission (SEC), estimates of the Company's proved reserves and future net
reserves are made using sale prices estimated to be in effect as of the date of
the reserve estimates and are held constant throughout the life of the
properties (except to the extent provided by contractual arrangements in
existence at year end). Price declines decrease reserve values by lowering the
future net revenues attributable to the reserves and may reduce the quantities
of reserves that are recoverable on an economic basis. Price increases may have
the opposite effect. A significant decline in prices of natural gas or oil could
have a material adverse effect on the Company's financial condition and results
of operations. Future prices received for production and future production costs
may vary, perhaps significantly, from the prices and costs assumed for purposes
of the estimates.
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 gas reserve engineering is a subjective process of
estimating underground accumulations of natural gas and oil 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
interpretations and judgment. Results of
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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
declines 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 of the
Company will decline as reserves are produced. Reserves generated from future
activities of the Company are therefore highly dependent upon the level of
success in acquiring or discovering additional reserves and the costs incurred
in doing so.
Since January 1, 2000, the Company has filed the Department of Energy Form
EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," as required by
operators of oil and gas properties in the United States. There are differences
between the reserves as reported on Form EIA-23 and reserves as reported herein.
Form EIA-23 requires that operators report on total proved reserves for operated
wells only and that reported reserves be reported on a gross basis rather than
on a net basis.
PRODUCTION
The following table sets forth information regarding net oil and natural gas
production, average sales prices and other production information. Average sales
prices for natural gas, oil and liquids are inclusive of hedging gains and
losses for the years ended December 31, 2000, 1999 and 1998.
United States (1) Canada (2)
-------------------------------------------- -------------
2000 1999 1998 2000
------------- ------------- -------------- -------------
Quantities produced and sold
Natural gas (MMcf) 3,374 4,074 3,272 1,679
Oil and liquids (Bbl) 69,000 64,000 65,000 53,000
Total Mcfe (3) 3,788 4,458 3,662 1,997
Average sales price
Natural gas ($/Mcf) $ 2.80 $ 2.07 $ 1.78 $ 3.23
Oil and liquids ($/Bbl) 23.16 17.44 13.26 21.87
Average production (lifting) costs ($/Mcfe) $ 0.42 $ 0.34 $ 0.36 $ 0.40
- ----------------------
(1) For 1999, the results represent the combined activities of the Company
for November and December 1999 and Carbon's predecessor, BFC, for the
period January through October 1999. Results for 1998 are for BFC.
(2) The results for 2000 are the results of CEC subsequent to its
acquisition by Carbon in February 2000. Volumetric production figures
are presented net before Crown royalty interests.
(3) Oil and liquids production is converted to natural gas equivalents
(Mcfe) at the rate of one barrel to six Mcf.
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PRODUCTIVE WELLS
The following table sets forth information regarding the number of productive
wells in which the Company held a working interest at December 31, 2000.
Productive Wells (1)
------------------------------------------------------
Gas Wells Oil Wells
----------------------- -----------------------
Gross (2) Net (3) Gross Net
---------- ---------- ---------- -----------
United States
Permian Basin 58 11.9 23 5.7
Piceance/Uintah Basins 122 107.7 4 4.0
San Juan Basin 40 24.3 - -
Southwestern Kansas 8 3.2 10 3.0
---------- ---------- ---------- -----------
Total 228 147.1 37 12.7
========== ========== ========== ===========
Canada
Alberta 57 36.5 1 0.3
Saskatchewan - - 10 2.8
---------- ---------- ---------- -----------
Total 57 36.5 11 3.1
========== ========== ========== ===========
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(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.
(2) A gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned.
(3) A net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one. The number of net wells is the sum of
the fractional working interest owned in gross wells.
The number of productive wells in which the Company held a working interest
at December 31, 2000, included 40 natural gas wells located in the San Juan
Basin of New Mexico. These properties were sold in January 2001.
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DRILLING ACTIVITY
The Company engages in exploratory and developmental drilling on its own and in
association with other oil and gas companies. The following table sets forth the
wells drilled for the years ended December 31, 2000, 1999 and 1998.
United States (1) Canada (2)
-------------------------------------------- -------------
2000 1999 1998 2000
------------- ------------- ------------- -------------
Gross wells (3)
Development
Natural gas - 3 3 8
Oil 6 2 2 -
Non-productive (4) - - 3 -
------------- ------------- ------------- -------------
Total 6 5 8 8
============= ============= ============= =============
Exploratory
Natural gas - 7 1 -
Oil 4 - 1 -
Non-productive 5 1 2 -
------------- ------------- ------------- -------------
Total 9 8 4 -
============= ============= ============= =============
Net wells (5)
Development
Natural gas - 1.8 0.5 4.9
Oil 0.4 0.1 0.1 -
Non-productive - - 2.3 -
------------- ------------- ------------- -------------
Total 0.4 1.9 2.9 4.9
============= ============= ============= =============
Exploratory
Natural gas - 4.2 0.3 -
Oil 2.5 - 1.0 -
Non-productive 3.8 1.0 0.7 -
------------- ------------- ------------- -------------
Total 6.3 5.2 2.0 -
============= ============= ============= =============
- -----------------------
(1) For 1999, the results represent the combined activities of the Company
for November and December 1999 and Carbon's predecessor, BFC, for the
period January through October 1999. Results for 1998 are for BFC.
(2) The results for 2000 are the results of CEC subsequent to its acquisition
by Carbon in February, 2000.
(3) A gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned.
(4) A non-productive hole is a well deemed to be incapable of producing either
natural gas or oil in sufficient quantities to justify completion as a
natural gas or oil well.
(5) A net well is deemed to exist when the sum of the fractional ownership
working interests in gross wells equals one. The number of net wells is the
sum of the fractional working interest owned in gross wells.
At December 31, 2000, the Company was participating in the drilling of three
gross (2.5 net) wells in the United States and three gross (three net) wells in
Canada.
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DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth the leasehold acreage held by the Company at
December 31, 2000.
Developed Acreage (1) Undeveloped Acreage (2)
-------------------------------- --------------------------------
Gross (3) Net (4) Gross Net
-------------- ------------- ------------- --------------
United States
Permian Basin 17,201 4,694 9,750 4,027
Piceance and Uintah Basins 37,728 32,344 91,131 73,177
San Juan Basin 3,280 2,640 1,920 1,280
Southwest Kansas 3,600 1,172 23,634 19,541
Other 2,354 1,177 9,400 8,620
-------------- ------------- ------------- --------------
Total 64,163 42,027 135,835 106,645
============== ============= ============= ==============
Canada
Alberta 29,920 16,347 11,840 7,449
Saskatchewan 1,440 412 5,680 2,744
-------------- ------------- ------------- --------------
Total 31,360 16,759 17,520 10,193
============== ============= ============= ==============
- -----------------------
(1) Developed acres are those acres which are spaced or assigned to productive
wells.
(2) Undeveloped acres are considered to be those acres on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas regardless of whether such
acreage contains proved reserves. It should not be confused with undrilled
acreage held by production under the terms of a lease.
(3) A gross acre is an acre in which a working interest is owned. The number of
gross acres is the total number of acres in which a working interest is
owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is the
sum of the fractional working interests owned in gross acres.
MARKETING
The Company sells all of its natural gas and oil production from wells that it
operates. In Canada, the Company's natural gas liquids production is currently
marketed through the operator of facilities that process the Company's gas for
liquids recovery. The Company's oil and natural gas production is generally sold
to end users, marketers, refineries and other purchasers having access to
natural gas pipeline facilities near its properties and the ability to truck oil
to the local refineries or oil pipelines.
The Company generally enters into short-term gas sales contracts for the sale
of natural gas from its properties. As of December 31, 2000, the Company was
committed to natural gas sales contracts that had fixed prices or price
ceilings covering 1,500 MMbtu/day and 1,896 MMbtu/day in the United States
and Canada, respectively. These contracts expire in March 2001.
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The Company believes that it will have sufficient production from its
properties to meet the Company's delivery obligations under its existing
natural gas sales contracts. As of December 31, 2000, the Company has entered
into various natural gas transportation agreements in Canada. The Company
typically assigns these transportation agreements to a buyer of the Company's
production during the term of the natural gas sales contract between the
Company and the buyer. The Company is typically paid on an index basis, net
of transportation charges incurred by the buyer. The rights and obligations
under these transportation agreements will revert back to the Company upon
expiration of the natural gas sales contracts.
In the United States, oil is typically sold under contracts extending up to a
year at prices based upon a local market posting for oil which generally
approximates a West Texas Intermediate posting and is adjusted to reflect
transportation costs and quality. In Canada, oil and liquids are typically
sold under short-term contracts at prices based upon posted prices at Alberta
pipeline and processing hubs and is adjusted to reflect transportation costs
and quality.
Please see Note 10 to the December 31, 2000 financial statements of Carbon
for information on major customers.
COMPETITION
The oil and natural gas industry is highly competitive. The Company
encounters competition from other oil and natural gas companies including
major oil companies, other independent oil and natural gas concerns and
individual producers and operators, for the acquisition of producing
properties and exploration and development prospects. The Company also
competes with other oil and natural gas companies in attempting to secure
drilling rigs and other equipment necessary for drilling and completion of
wells. We compete with a large number of companies having substantially
larger technical staffs and greater financial and operational resources. 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 and for current taxes not yet due. For acquisitions of developed
properties, the Company will conduct a title examination on all material
properties, typically reviewed by title attorneys. Consistent with standard
industry practice, title investigation before acquiring undeveloped
properties is typically less rigorous than that conducted prior to drilling a
well. 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
reasonable in the opinion of management, to insure that production from its
properties, if obtained, will be readily salable for the account of the
Company.
GOVERNMENT REGULATION
UNITED STATES
The Company's United States 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.
In the past, the federal government has regulated the prices at which oil and
natural gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989
removed all price controls affecting producing wellhead sales effective
January 1, 1993. While sales by producers of oil, natural gas, and natural
gas liquids can currently be made at uncontrolled market prices, Congress
could reenact price controls in the future. 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 by, among other things,
removing the transportation barriers to market access. These orders have had
a significant impact upon gas markets in the United States and have fostered
the development of a large spot market for gas and increased competition for
gas markets. As a result of the FERC orders, producers can access gas markets
directly but face increased competition for these markets. 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
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what new regulations may be adopted by FERC and other regulatory authorities and
the effect, if any, subsequent regulations may have on the Company.
The Company's oil and natural gas operations are regulated by administrative
agencies under statutory provisions of the states where such operations are
conducted and by certain agencies of the Federal government for operations on
federal oil and gas leases. All of the jurisdictions in which the Company owns
or operates producing oil and natural gas properties have statutory
provisions regulating the exploration for and production of crude oil and
natural gas. These statutes include the regulation of the size of drilling
and spacing units and the number of wells which may be drilled in an area and
the unitization or pooling of oil and natural gas properties. In addition,
state conservation laws establish maximum rates of production from oil and
natural gas wells, typically prohibit the venting or flaring of natural gas,
and impose certain requirements regarding the apportionment of production
from fields and individual wells. The effect of these regulations may limit
the amount of oil and natural gas the Company can produce from its wells and
to limit the number of wells or location at which the Company can drill.
State commissions establish rules for reclamation of sites, plugging bonds,
reporting and other matters.
Increasingly, a number of city and county governments have enacted oil and
natural gas regulations which have increased the involvement of local
governments in the permitting of oil and natural gas operations and impart
additional restrictions or conditions on the conduct of operators to mitigate
the impact of operations on the local community. These local restrictions have
the potential to delay and increase the cost of oil and natural gas operations.
CANADA
The oil and natural gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. Federal authorities do not
regulate the price of oil and gas in export trade but instead rely on market
forces to establish these prices. Legislation exists that regulates the
quantities of oil and natural gas which may be removed from the provinces and
exported from Canada. The Company does not expect that any of these controls and
regulations will affect the Company in a manner significantly different than
other oil and natural gas companies of similar size.
The provinces in which the Company operates have legislation and regulation
which govern land tenure, royalties, production rates and environmental
protection. The royalty regime in the provinces in which the Company operates is
a significant factor in the profitability of the Company's production. Crown
royalties are determined by government regulation and are typically calculated
as a percentage of production. The value of the production and the rate of
royalties payable depends on prescribed reference prices, well productivity,
geographical location and the type or quality of the product produced.
In Alberta, the Company is entitled to a credit against Crown royalties on most
of the properties in which the Company has an interest in by virtue of the
Alberta Royalty Tax Credit (ARTC). The credit is determined by applying a rate
to a maximum of CDN $2.0 million of Crown royalties payable in Alberta for each
company or associated group of companies. The rate is a function of the royalty
tax credit par prices which is determined quarterly by the Alberta Department of
Energy. The rate ranges from 25% to 75% depending upon petroleum prices for the
previous quarter.
ENVIRONMENTAL REGULATION
UNITED STATES
The Company, as a lessee and operator of natural gas and oil properties, is
subject to various federal, state and local laws and regulations in the United
States that provide for restriction and prohibition 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. These laws and
regulations may, among other things, impose liability and penalties on the
lessee for the cost of pollution cleanup resulting from operations, subject the
lessee to liability for pollution
-11-
damages, require suspension or cessation of operations in affected areas, and
impose restrictions on the injection of liquids into subsurface aquifers that
may contaminate ground water.
The Company has made, and will continue to make, expenditures in its efforts to
comply with environmental regulations. The Company believes it is in compliance
with applicable environmental laws and regulations in effect and that continued
compliance with existing requirements will not have a material adverse impact on
the Company. Nevertheless, changes in existing environmental laws or the
adoption of new environmental laws could have a potential to adversely affect
the Company's operations. In connection with the Company's acquisition of BFC,
environmental assessments were performed. No material noncompliance or clean-up
liabilities requiring action were discovered. However, environmental assessments
were performed on only a percentage of the Company's properties according to the
value of the properties established at the time of acquisition. 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.
CANADA
In Canada, the oil and natural gas industry is currently subject to
environmental regulations pursuant to provincial and federal legislation.
Environmental legislation provides for restrictions on releases or emissions of
various substances produced or utilized in association with certain oil and gas
industry operations. In addition, legislation requires that well and facility
sites be abandoned and reclaimed to the satisfaction of provincial authorities.
A breach of such regulations may result in the imposition of fines and
penalties, the suspension of operations and potential civil liability. The
Environmental Protection and Enhancement Act imposes environmental standards and
requires compliance with various legislative criteria including reporting and
monitoring in Alberta. The Alberta Energy and Utility Board, pursuant to its
governing legislation, also plays a role with respect to the regulation of
environmental impacts of oil and gas activities.
OPERATING HAZARDS
The oil and gas industry involves a variety of operating risks including the
risk of fire, explosion, 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. 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
Except as provided below, the Company is not engaged in any material legal
proceedings to which the Company or its subsidiaries are party or to which any
of its property is subject.
The Company is the plaintiff in the case Bonneville Fuels Corporation
(Bonneville) vs. Barrett Resources Corporation (Barrett) case number 00 CV 274B,
currently pending in the District Court of Garfield County, Colorado. At issue
is Bonneville's claim to certain oil and gas leasehold interests reserved
pursuant to an assignment between Bonneville and a third party. Barrett
subsequently acquired the rights formerly held by the third party. Barrett has
denied Bonneville's claim on a portion of these alleged reserved oil and gas
leasehold interests. The Company also seeks damages for breach of the operating
agreement governing the lands in question. To date, Barrett has not counter
claimed for money damages but has counter claimed seeking a declaratory
judgement that Barrett is the owner of these contested leasehold interests.
-12-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
-13-
PART II
ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
On February 24, 2000, Carbon Energy shares began trading on the American Stock
Exchange under the trading symbol CRB. The Company's equity securities consist
of common stock with no par value. The range of the high and low closing prices
for each quarterly period since the Company's common stock has traded is as
follows:
Quarter Ended High Low
- --------------------------- ------------ ------------
March 31, 2000 $ 6.5000 $ 5.8750
June 30, 2000 $ 5.8750 $ 5.5000
September 30, 2000 $ 6.5625 $ 5.5000
December 31, 2000 $ 6.7500 $ 5.6250
On March 21, 2001, the closing price of the common stock was $8.55. There were
approximately 41 holders of record of the common stock and 6.1 million shares
outstanding.
The Company has not paid dividends on its common stock since inception and does
not anticipate doing so in the future. Future payments of dividends, if any,
will depend on the Company's earnings, capital requirements, loan restrictions,
financial condition and other relevant factors. There is no assurance that the
Company will ever pay dividends.
For the year ended December 31, 2000, the Company granted 27,500 shares of
restricted stock to the executive officers of Carbon and high level officers
of its subsidiaries. The Company believes that these grants did not
constitute sales under the Securities Act of 1933. These grants would also be
exempt under Section 4(2) of the Securities Act of 1933 and Rule 506 of
Regulation D if considered a sale.
-14-
ITEM 6. SELECTED FINANCIAL DATA
The table below sets forth selected historical financial and operating data for
Carbon and its predecessor, BFC, as of or for each of the years in the five-year
period ended December 31, 2000. For 1999, the table presents the activities of
the Company 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 a pro forma presentation for the
combined operating and cash flow data for the year ended December 31, 1999. The
twelve month figures as of or for the years ended December 31, 1996 - 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. Please see Note 9 and Note 15 to the December 31,
2000 financial statements of Carbon for information on geographic segments and
quarterly data for 2000.
As of or As of or As of or
for the Pro Forma for the for the
Year for the Two Months Ten Months As of or for the Year
Ended Year Ended Ended Ended Ended December 31,
December 31, December 31, December 31, October 31, ----------------------------
2000 1999 1999 1999 1998 1997 1996
------------ ------------ ------------ ----------- -------- -------- --------
(dollars in thousands, except per share data)
Operating Data:
Revenues $ 17,819 $ 10,299 $ 1,775 $ 8,524 $ 7,281 $ 7,489 $ 8,157
Net earnings (loss) 1,456 147 (491) 638 (2,191) 732 4,060
Earning (loss) per share:
Basic $ 0.25 n/a $ (0.12) n/a n/a n/a n/a
Diluted 0.25 n/a (0.12) n/a n/a n/a n/a
Cash Flow Data:
Cash provided by (used in)
operating activities $ 3,755 $ (713) $ 999 $ (1,712) $ 4,696 $ 3,193 $ 4,136
Cash used in investing
activities (8,266) (28,841) (24,110) (4,731) (5,948) (4,442) (1,025)
Cash provided by (used in)
financing activities 3,526 28,056 24,106 3,950 3,450 1,019 (2,760)
EBITDA(1) 8,763 3,483 239 3,244 1,816 3,348 6,959
Balance Sheet Data:
Total assets $ 62,480 n/a $ 39,298 $ 22,912 $22,840 $ 16,054 $ 14,524
Working capital (267) n/a 232 1,954 562 1,491 1,725
Long-term debt 15,082 n/a 9,100 9,800 5,850 2,400 1,700
Stockholders' equity 32,235 n/a 24,315 9,701 9,063 9,591 8,859
- -------------------
(1) Earnings before Interest, Taxes, Depreciation, Amortization and
Impairment (BFC).
-15-
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 2000 RESULTS TO 1999
The following table shows comparative pro forma revenue, sales volumes, average
sales prices, expenses and the percentage change between periods for the twelve
months ended December 31, 2000 and 1999 for the Company's United States
operations conducted through BFC, and comparative pro forma revenue, sales
volumes, average sales prices, expenses and the percentage change between the
periods for the period February 18 through December 31, 2000 and 1999, (to
reflect activity subsequent to the time the Company acquired CEC) for the
Company's Canadian operations conducted through CEC.
Canada (2)(3)
United States (1) For the Period from
For the Year Ended February 18 through
December 31, December 31,
--------------------------------- --------------------------------
2000 1999 Change 2000 1999 Change
---------- ---------- ------- ---------- ---------- -------
(dollars in thousands, except (dollars in thousands, except
prices and per Mcfe information) prices and per Mcfe information)
Revenues:
Natural gas $ 9,456 $ 8,429 12% $ 5,431 $ 2,630 107%
Oil and liquids 1,598 1,128 42% 1,159 818 42%
-------- -------- -------- --------
Total 11,054 9,557 16% 6,590 3,448 91%
Sales volumes:
Natural gas (MMcf) 3,374 4,074 -17% 1,679 1,420 18%
Oil and liquids (Bbl) 69,000 64,000 8% 53,000 51,000 4%
Average price realized:
Natural gas (Mcf) $ 2.80 $ 2.07 35% $ 3.23 $ 1.85 75%
Oil and liquids (Bbl) 23.16 17.44 33% 21.87 16.04 36%
Direct lifting costs $ 1,602 $ 1,511 6% $ 793 $ 524 51%
Average direct lifting costs/Mcfe 0.42 0.34 24% 0.40 0.30 33%
Other production costs 2,172 1,946 12% 1,216 314 287%
Marketing and other, net $ 245 $ 742 -67% $ (70) $ (8) -775%
General and administrative, net 1,989 2,559 -22% 1,260 1,282 -2%
Depreciation, depletion and amortization 4,042 2,720 49% 1,494 1,362 10%
Exploration and impairment expense - 860 n/a - - n/a
Interest expense, net 917 556 65% 187 151 24%
Income tax 44 - n/a 623 (206) 402%
- ----------------------
(1) For 1999, the pro forma results are for the activities of the Company 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.
(2) The pro forma results for 1999 are the results of CEC prior to the
acquisition of CEC by the Company.
(3) Volumetric sales figures for Canadian activities are presented net before
Crown royalty interests.
Revenues for oil and gas sales of BFC for the year ended December 31, 2000 were
$11.1 million, a 16% increase from 1999. The increase was due primarily to
increased oil and gas prices partially offset by natural production declines in
all operating areas.
-16-
Revenues for oil, liquids and gas sales of CEC for the period February 18
through December 31, 2000 were $6.6 million, a 91% increase from 1999. The
increase was due primarily to increased oil, liquids and gas production and
higher oil, liquids and gas prices.
BFC's average production for the year ended December 31, 2000 was 189 barrels of
oil per day and 9.2 million cubic feet (MMcf) of gas per day, a decrease of 15%
from 1999 on a Mcf equivalent (Mcfe) basis where one barrel of oil is equal to
six Mcf of gas. The decrease was due primarily to natural production declines on
existing properties partially offset by new gas well connections in Utah.
Successful drilling activities in the Permian Basin resulted in increased oil
production during the fourth quarter of 2000. During the twelve months ended
December 31, 2000, the Company participated in the drilling of 15 gross and 6.7
net wells compared to 13 gross and 7.1 net wells during 1999.
CEC's average production for the period February 18 through December 31, 2000
was 167 barrels of oil and liquids per day and 5.3 MMcf of gas per day, an
increase of 16% from 1999 on an Mcfe basis. The increase was due primarily to
acquisitions, successful well drilling activities and optimization of the
Company's natural gas gathering and compression facilities, primarily in the
Carbon and Rowley areas of Central Alberta. During the period February 18
through December 31, 2000, eight gross and 4.9 net wells were drilled. CEC did
not have any drilling activity in 1999.
Average oil prices realized by BFC increased 33% from $17.44 per barrel for the
year ended December 31, 1999 to $23.16 for 2000. The average oil price includes
hedge losses of $414,000 for the year ended December 31, 2000. There was no oil
hedge activity for 1999. Average natural gas prices realized by BFC increased
35% from $2.07 per Mcf for the year ended December 31, 1999 to $2.80 per Mcf for
2000. The average natural gas price includes hedge losses of $2.6 million for
the year ended December 31, 2000 compared to hedge losses of $65,000 for 1999.
Average oil and liquids prices realized by CEC increased 36% from $16.04 per
barrel for the period from February 18 through December 31, 1999 to $21.87 for
2000. The average oil and liquids price includes hedge losses of $186,000 for
the period February 18 through December 31, 2000. There was no oil hedge
activity for the similar period in 1999. Average natural gas prices realized by
CEC increased 75% from $1.85 per Mcf for the period from February 18 through
December 31, 1999 to $3.23 for 2000. The average natural gas price includes
hedge losses of $987,000 for the period February 18 through December 31, 2000
compared to hedge losses of $239,000 for 1999.
Direct lifting costs incurred by BFC were $1.6 million or $.42 per Mcfe for the
year ended December 31, 2000 compared to $1.5 million or $.34 per Mcfe for 1999.
The per Mcfe increase was related to operating approximately the same number of
wells with lower production per well. Compared to the year ended December 31,
1999, BFC has seen an increase in well service costs due to vendor price
increases. This increase was partially offset by well workover expenses incurred
during 1999.
Other production costs incurred by BFC consisting of production taxes, workovers
and overhead were $2.2 million for the year ended December 31, 2000 compared to
$1.9 million for 1999. The increase was primarily due to higher severance taxes
due to increased oil and gas prices, partially offset by a reduction in
production.
Direct lifting costs incurred by CEC were $793,000 or $.40 per Mcfe for the
period February 18 through December 31, 2000 compared to $524,000 or $.30 per
Mcfe for 1999. The increase was primarily due to credits received by CEC in 1999
for gas processing fees related to prior periods and increases in well service
costs due to vendor price increases.
Other production costs incurred by CEC consisting of net Crown and other royalty
expense was $1.2 million for the period February 18 through December 31, 2000
compared to $314,000 for 1999. The increase was due to a rise in net Crown
royalties due to higher oil and gas prices and increased production.
Exploration and impairment expense was recorded by the Company's predecessor,
BFC, under the successful efforts method of accounting and consists primarily of
unsuccessful drilling and geological and geophysical costs.
-17-
Effective as of the date of the acquisition of BFC, Carbon utilizes the full
cost method of accounting. Under this method, all exploration costs associated
with continuing efforts to acquire or review prospects and outside geological
and seismic consulting work are capitalized.
Net marketing and other revenues for BFC decreased 67% from
$742,000 for the year ended December 31, 1999 to $ 245,000 for 2000. The
decrease is primarily due to decreased levels of activity and margins on the
marketing of third party natural gas and a pipeline imbalance correction
related to a prior period recorded by BFC in 1999. The Company anticipates
that they will continue to reduce its efforts concerning the marketing of
third party natural gas in 2001.
General and administrative expenses incurred by BFC, net of overhead
reimbursements, decreased 22% from $2.6 million for the year ended December 31,
1999 to $2.0 million for 2000. The decrease was due primarily to expenses
incurred during 1999 of approximately $1.0 million for severance payments
incurred as a result of the acquisition of BFC by Carbon. This decrease was
partially offset by costs related to a change in the location of the
administrative office of the Company and costs for reporting, printing and
regulatory filings relating to the Company being a publicly held company in
2000. In addition, during 1999, BFC reversed $95,000 of an employee retention
bonus accrued in 1998 due to the pending sale of the company to Carbon.
General and administrative expenses incurred by CEC for the period February 18
through December 31, 2000 and 1999 were $1.3 million.
Interest expense incurred by BFC increased 65% from $556,000 for the year ended
December 31, 1999 to $917,000 for 2000. The increase was due primarily to
increased borrowings to maintain margin requirements on certain of the Company's
derivative positions.
Interest expense incurred by CEC increased 24% from $151,000 for the period
February 18 through December 31, 1999 to $187,000 for 2000. The increase was due
primarily to increased borrowings for acquisitions, drilling and development
activity.
Depreciation, depletion and amortization (DD&A) of oil and gas assets are
determined based upon the units of production method. This expense is typically
dependent upon historical capitalized costs incurred to find, develop and
recover oil and gas reserves; however, the Company's current DD&A rate is
determined primarily by the purchase price the Company allocated to oil and gas
properties in connection with its acquisition of BFC and CEC and the proved
reserves the Company acquired in the acquisitions.
DD&A expense incurred by BFC increased 49% from $2.7 million for the year ended
December 31, 1999 to $4.0 million for 2000. DD&A expense was $.61 per Mcfe for
the year ended December 31, 1999 compared to $1.07 per Mcfe for 2000. The
increase was due primarily to increased property costs recorded as a result of
the acquisition of BFC.
DD&A expense incurred by CEC increased 10% from $1.4 million for the period
February 18 through December 31, 1999 to $1.5 million for 2000. The increase
resulted primarily from increased production. DD&A expense was $.79 per Mcfe for
the period February 18 through December 31, 1999 compared to $.75 per Mcfe for
2000.
Income tax expense incurred by BFC was $44,000 for the year ended December 31,
2000. BFC did not record a provision for income taxes for 1999. BFC's effective
tax rate was 8% for the year ended December 31, 2000 as a result of the
reversal of a valuation allowance of $192,000.
Income tax expense incurred by CEC was $623,000 for the year ended December 31,
2000 compared to an income tax benefit of $206,000 for 1999. CEC's effective tax
rate was 40% for the year ended December 31, 2000.
-18-
RESULTS OF OPERATIONS - COMPARISON OF 1999 RESULTS TO 1998
The following table shows comparative pro forma revenue, sales volumes, average
sales prices, expenses and the percentage change between periods for the twelve
months ended December 31, 1999 and 1998 for the Company's United States
operations. The comparative results discussion that follows also compares pro
forma 1999 activity to 1998 activity. The comparative discussion only includes
the Company's activities in the United States as the Company did not acquire CEC
until February 2000.
Twelve
Months Two Ten Twelve
Ended Months Months Months Twelve
December 31, Ended Ended Ended Months
1999 December 31, October 31, December 31, Percentage
pro forma (1) 1999 1999 1998 (2) Change
-------------- ---------- ----------- -------------- --------------
(dollars in thousands, except
prices and per Mcfe information)
Revenues:
Natural gas $ 8,429 $ 1,504 $ 6,925 $ 5,896 43%
Oil and liquids 1,128 233 895 862 31%
----------- -------- -------- ----------
Total 9,557 1,737 7,820 6,758 41%
Sales volumes:
Natural gas (MMcf) 4,074 569 3,505 3,272 25%
Oil and liquids (Bbl) 64,000 9,000 55,000 65,000 -2%
Average price realized:
Natural gas (Mcf) $ 2.07 $ 2.64 $ 1.98 $ 1.78 16%
Oil and liquids (Bbl) 17.44 25.29 16.13 13.26 32%
Direct lifting costs $ 1,511 $ 218 $ 1,293 $ 1,321 14%
Average direct lifting costs/Mcfe 0.34 0.35 0.34 0.36 -6%
Other production costs 1,946 379 1,567 1,933 1%
Marketing and other, net $ 742 $ 38 $ 704 $ 523 42%
General and administrative, net 2,559 939 1,620 1,655 55%
Depreciation, depletion and amortization 2,720 628 2,092 2,086 30%
Exploration and impairment expense 860 - 860 2,414 -64%
Interest expense, net 556 102 454 238 134%
- ----------------------
(1) For 1999, the pro forma results are for the activities of the Company for
November and December 1999 (the Company's operating activities prior to
November 1, 1999 were minimal) and for Carbon's predecessor, BFC, for the
period January through October 1999.
(2) The twelve month figures for the year ended December 31, 1998 are for
Carbon's predecessor, BFC.
Revenues for oil and gas sales of BFC for the year ended December 31, 1999 were
$9.6 million, a 41% increase from 1998. The increase was due primarily to
increased oil and gas prices and increased gas production.
BFC's average production for the year ended December 31, 1999 was 175 barrels of
oil per day and 11.2 MMcf of gas per day, an increase of 22% from 1998 on a Mcfe
basis. The increase was due primarily to successful drilling and recompletion
results, particularly in the Hugoton Basin of Southwest Kansas and the Permian
Basin of New Mexico, partially offset by natural production declines on existing
properties. During the twelve months ended December 31, 1999, the Company
participated in the drilling of 13 gross and 7.1 net wells compared to twelve
gross and 4.9 net wells during 1998.
-19-
Average oil prices realized by BFC increased 32% from $13.26 per barrel for the
year ended December 31, 1998 to $17.44 for 1999. Average natural gas prices
realized by BFC increased 16% from $1.78 per Mcf for the year ended December 31,
1998 to $2.07 in 1999. The average natural gas price includes hedge losses of
$65,000 for the year ended December 31, 1999 compared to hedge gains of $80,000
for 1998.
Direct lifting costs incurred by BFC were $1.5 million or $.34 per Mcfe for the
year ended December 31, 1999 compared to $1.3 million or $.36 Mcfe for 1998.
Other production costs incurred by BFC consisting of production taxes, workovers
and overhead were $1.9 million for the year ended December 31, 1999 and 1998.
For the year ended December 31, 1999, BFC incurred higher severance taxes due to
increased oil and gas prices and increased gas sales compared to 1998, offset by
an accrual of $250,000 recorded in 1998 for the estimated liability under a well
connection reimbursement agreement.
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 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 geological and geophysical costs were $496,000 in 1999 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.
Net marketing and other revenues for BFC increased 42% from $523,000 for the
year ended December 31, 1998 to $742,000 for 1999. The increase is primarily
due to a pipeline imbalance correction related to a prior period recorded by
BFC in 1999.
General and administrative expenses incurred by BFC, net of overhead
reimbursements, increased 55% from $1.7 million for the year ended December 31,
1998 to $2.6 million in 1999. The increase is primarily due to expenses of
approximately $1.0 million for severance payments incurred as a result of the
acquisition of BFC by Carbon. 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. In 1999, BFC reversed $95,000 of this accrual due
to the pending sale of the company to Carbon.
Interest expense increased 134% from $238,000 for the year ended December 31,
1998 to $556,000 for 1999. The increase is due primarily to increased borrowings
for drilling and development activity.
DD&A of oil and gas assets are determined based upon the units of production
method. This expense is typically dependent upon historical capitalized costs
incurred to find, develop and recover oil and gas reserves; however, the
Company's current DD&A rate is determined primarily by the purchase price the
Company allocated to oil and gas properties in connection with its acquisition
of BFC and 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 purchase accounting
treatment in connection with the Company's acquisition of BFC, the current DD&A
rate increased to $1.01 per Mcfe.
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
-20-
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 economics. Refer
to the price change tables in the discussions "Results of Operations -
Comparison of 2000 results to 1999, and 1999 results to 1998" 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.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2000, the Company had $62.5 million of assets. Total
capitalization was $47.3 million, consisting of 68% of stockholders' equity and
32% of debt. In February 2000, the Company exchanged shares of common stock for
over 97% of the shares of CEC.
UNITED STATES
The Company moved its credit facility from U.S. Bank National Association to
Wells Fargo Bank, National Association in the third quarter of 2000.
The facility is an oil and gas reserve based line-of-credit and had a borrowing
base of $16.1 million with outstanding borrowings of $12.5 million at December
31, 2000. The facility is secured by certain U.S. oil and gas properties of the
Company and is scheduled to convert to a term note on October 1, 2002. This
facility is scheduled to have a maturity date of either the economic half life
of the Company's remaining U.S. based reserves on the last day of the revolving
period, or October 1, 2006, whichever is earlier. The facility bears interest at
a rate equal to LIBOR plus 1.75% or Wells Fargo Bank West Prime, at the option
of the Company. The Company's average borrowing rate was approximately 8.5% at
December 31, 2000. The borrowing base is based upon the lender's evaluation of
the Company's proved oil and gas reserves, generally determined semi-annually.
The credit agreement contains various covenants, which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is also
required to maintain certain financial ratios.
CANADA
The facility with the Canadian Imperial Bank of Commerce (CIBC), has a borrowing
base of approximately $4.4 million with outstanding borrowings of $2.6 million
at December 31, 2000. The Canadian facility is secured by the Canadian oil and
gas properties of the Company. The revolving phase of the Canadian facility
expired on December 31, 2000 and the Company is currently in negotiations with
CIBC to extend the revolving phase to April 1, 2002. However, there can be no
guarantee that the Company will be able to successfully negotiate such an
extension. If the revolving commitment is not renewed, the loan will be
converted into a term loan and will be reduced by consecutive monthly payments
over a period not to exceed 36 months. However, subject to possible changes in
the borrowing base, CIBC has agreed that it will not require the Company to make
any principal payments under the term loan section of the facility until January
2002 at the earliest. As such, no amounts under the CIBC facility have been
classified as current in the December 31, 2000 balance sheet. The Canadian
facility bears interest at the CIBC Prime rate plus 3/4%. The rate was
approximately 8.25% at December 31, 2000.
-21-
The Canadian facility contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness, sell
properties, or merge with another entity.
The agreement with CIBC also contains a $3.0 million swap facility that provides
at the Company's request and subject to market availability, commodity swaps
covering a portion of the Company's oil and gas production, forward exchange
contracts and firm gas purchase and sales transactions. The Company currently
utilizes the swap facility to hedge its Canadian production.
For the year ended December 31, 2000, net cash provided by operating activities
was $3.8 million compared to pro forma net cash used by operating activities of
$713,000 in 1999. The increase is due primarily to increases in net income and
non-cash charges to net income in 2000 compared to 1999. Net cash used in
investing activities was $8.3 million in 2000 compared to $28.8 million in 1999.
Net cash provided by financing activities was $3.5 million in 2000 compared to
$28.1 million in 1999. Changes in comparative investing and financing cash flows
were due primarily to Carbon's acquisition of BFC and Yorktown's purchase of
Carbon shares to facilitate the acquisition of BFC in 1999.
Carbon's primary cash requirements will be to finance acquisitions, exploration
and development expenditures, repayment of debt, and general working capital
needs. However, future cash flow is subject to a number of variables including
the level of production and oil and natural gas prices and there can be no
assurance that operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures or that
increased capital expenditures will not be undertaken. In January 2001, Carbon
announced that it had closed the sale of its entire working interests and
related leasehold rights in the San Juan Basin. The effective date of the sale
was September 1, 2000 and the purchase price was $7.5 million, subject to
certain adjustments. The Company anticipates that capital expenditures,
exclusive of acquisitions (if any) or divestitures will approximate $19.5
million in 2001. Carbon believes that available borrowings under its credit
agreements, the proceeds from the sale of its San Juan Basin properties,
projected operating cash flows and the cash on hand will be sufficient to
cover its working capital, capital expenditures, planned development
activities and debt service requirements for the next 12 months.
Nevertheless, Carbon may explore outside funding opportunities including
equity or additional debt financings for use in expanding Carbon's operations
or in consummating any significant acquisition. Carbon does not know however,
whether any financing can be accomplished on terms that are acceptable to the
Company.
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), 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-
-22-
looking statements attributable to the Company or persons acting on its
behalf are expressly qualified in their entirety by the Cautionary Statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
INTEREST RATE RISK
Market risk is estimated as the potential change in fair value of interest
sensitive investments 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, 2000,
the Company had $12.5 million of floating rate debt through its facility with
Wells Fargo Bank West and $2.6 million through its facility with CIBC. Assuming
constant debt levels, earnings and cash flow impacts for the next twelve month
period from December 31, 2000 due to a one percent change in interest rates
would be approximately $125,000 before taxes for the facility with the U.S. bank
and $26,000 before taxes for the facility with the Canadian bank.
FOREIGN CURRENCY RISK
The Canadian dollar is the functional currency of CEC and is subject to foreign
currency exchange rate risk on cash flows related to sales, expenses, financing
and investing transactions. The Company has not entered into any foreign
currency forward contracts or other similar financial investments to manage this
risk.
COMMODITY PRICE RISK
Oil and gas commodity markets are influenced by global as well as regional
supply and demand. Worldwide political events can also impact commodity
prices. The Company from time to time uses certain financial instruments in
an attempt to reduce exposure to the market fluctuations in the price of oil
and natural gas. The Company's general strategy is to hedge price and
location risk of a portion of the Company's production with swap, collar,
futures, and floor and ceiling arrangements, as described in Note 1 to the
December 31, 2000 financial statements of Carbon and in Note 8 to the October
31, 1999 financial statements of BFC. The Company generally enters into
hedges for delivery into one of several pipelines located near producing
regions of the Company although in some cases an exact hedge instrument may
not exist. Pursuant to Company guidelines, the Company is to engage in these
activities only as a hedging mechanism. The Company has a Risk Management
Committee to administer its production hedging program. It is the policy of
the Company that the Risk Management Committee approves all production
hedging transactions. Gains 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 table below sets forth the Company's derivative financial instrument
position on its natural gas and oil production as of December 31, 2000.
BFC Contracts CEC Contracts
- ---------------------------------------- -------------------------------------
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtu per MMBtu Year MMBtu per MMBtu
- ------- ------------ --------------- ------ ---------- ----------------
2001 1,408,000 $ 2.35 2001 391,000 $ 2.72
-23-
As of December 31, 2000, the Company would have been required to pay $5.7
million and $1.6 million to exit the BFC and CEC contracts, respectively.
In addition, the Company utilizes collars that establish a price between a floor
and ceiling to hedge natural gas and oil prices. The table below sets forth the
Company's natural gas collars in place at December 31, 2000.
Average Average
Floor Ceiling
per per
Year MMBtu MMBtu MMBtu
- ----------- ---------- ------------ ------------
2001 85,000 $ 3.51 $ 4.89
As of December 31, 2000, the Company would have been required to pay $378,000 to
exit these contracts.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for all fiscal quarters of fiscal years beginning after June
15, 2000. The financial statement impact of recording derivative
instruments designated as hedges and derivative instruments not designated as
hedges upon adoption of SFAS No. 133 on January 1, 2001 is as follows:
Amount
(millions)
------------
Balance Sheet
Derivative liability $ (7.2)
Deferred tax asset 2.9
Cumulative effect of a change in accounting principle
(other comprehensive loss) 2.8
Statement of Operations
Cumulative effect of a change in accounting principle
(derivative loss) $ 1.5
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
-24-
CARBON ENERGY CORPORATION
CONSOLIDATED FINANCIAL STATEMENTS
-25-
INDEX TO FINANCIAL STATEMENTS
PAGE
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS..............................................................................27
CONSOLIDATED BALANCE SHEETS - December 31, 2000 and 1999..............................................................28
CONSOLIDATED STATEMENTS OF OPERATIONS - For the Year Ended December 31, 2000 and the Period from Inception
(September 14, 1999) through December 31, 1999...............................................................29
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - For the Year Ended December 31, 2000 and the Period from Inception
(September 14, 1999) through December 31, 1999...............................................................30
CONSOLIDATED STATEMENTS OF CASH FLOWS - For the Year Ended December 31, 2000 and the Period from Inception
(September 14, 1999) through December 31, 1999...............................................................31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS............................................................................32
-26-
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Carbon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Carbon Energy
Corporation (a Colorado corporation) and subsidiaries as of December 31, 2000
and 1999, and the related consolidated statements of operations, stockholders'
equity and cash flows for the year ended December 31, 2000 and 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 audits.
We conducted our audits 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 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 Carbon Energy
Corporation and subsidiaries as of December 31, 2000 and 1999, and the results
of their operations and their cash flows for the year ended December 31, 2000
and 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 23, 2001
-27-
CARBON ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------------------------------------
2000 1999
--------------------- -----------------
ASSETS
Current assets:
Cash $ 21,000 $ 995,000
Current portion of employee trust 683,000 881,000
Accounts receivable, trade 6,129,000 2,286,000
Accounts receivable, other 337,000 69,000
Amounts due from broker 3,871,000 1,250,000
Prepaid expenses and other 701,000 107,000
----------------- -----------------
Total current assets 11,742,000 5,588,000
----------------- -----------------
Property and equipment, at cost:
Oil and gas properties, using the full cost method of accounting:
Unproved properties 6,576,000 7,879,000
Proved properties 49,547,000 25,020,000
Furniture and equipment 398,000 214,000
----------------- -----------------
56,521,000 33,113,000
Less accumulated depreciation, depletion and amortization (6,152,000) (627,000)
----------------- -----------------
Property and equipment, net 50,369,000 32,486,000
----------------- -----------------
Other assets:
Deferred acquisition costs - 310,000
Deposits and other 369,000 245,000
Employee trust - 669,000
----------------- -----------------
Total other assets 369,000 1,224,000
----------------- -----------------
Total assets $ 62,480,000 $ 39,298,000
================= =================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 9,583,000 $ 4,391,000
Accrued production taxes payable 637,000 367,000
Income taxes payable 228,000 -
Undistributed revenue 1,561,000 598,000
----------------- -----------------
Total current liabilities 12,009,000 5,356,000
----------------- -----------------
Long-term debt 15,082,000 9,100,000
Other long-term liabilities - 527,000
Deferred income taxes 2,984,000 -
Commitments and contingencies (Note 5)
Minority interest 170,000 -
Stockholders' equity:
Preferred stock, no par value:
10,000,000 shares authorized, none outstanding - -
Common stock, no par value:
20,000,000 shares authorized, issued, and
6,021,626 shares and 4,510,000 shares outstanding
at December 31, 2000 and December 31, 1999, respectively 31,495,000 24,806,000
Retained earnings (accumulated deficit) 965,000 (491,000)
Currency translation adjustment (225,000) -
----------------- -----------------
Total stockholders' equity 32,235,000 24,315,000
----------------- -----------------
Total liabilities and stockholders' equity $ 62,480,000 $ 39,298,000
================= =================
The accompanying notes are an integral part of these
consolidated financial statements.
-28-
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE PERIOD
FROM INCEPTION
FOR THE YEAR (SEPTEMBER 14, 1999)
ENDED THROUGH
DECEMBER 31, 2000 DECEMBER 31, 1999
--------------------------- --------------------------
Revenues:
Oil and gas sales $ 17,644,000 $ 1,737,000
Marketing and other, net 175,000 38,000
--------------------------- --------------------------
17,819,000 1,775,000
Expenses:
Oil and gas production costs 5,783,000 597,000
Depreciation, depletion and amortization
expense 5,536,000 628,000
General and administrative expense, net 3,249,000 939,000
Interest expense, net 1,104,000 102,000
--------------------------- --------------------------
Total operating expenses 15,672,000 2,266,000
Minority interest 24,000 -
--------------------------- --------------------------
2,123,000 (491,000)
Income taxes:
Current 250,000 -
Deferred 417,000 -
--------------------------- --------------------------
Net income (loss) $ 1,456,000 $ (491,000)
=========================== ==========================
Earnings (loss) per share:
Basic $ 0.25 $ (0.12)
Diluted 0.25 (0.12)
Average number of common shares outstanding (in thousands):
Basic 5,822 4,056
Diluted 5,874 4,056
The accompanying notes are an integral part of these
consolidated financial statements.
-29-
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2000 AND
THE PERIOD FROM INCEPTION (SEPTEMBER 14, 1999) THROUGH
DECEMBER 31, 1999
RETAINED
COMMON STOCK EARNINGS CURRENCY
--------------------------------- (ACCUMULATED TRANSLATION
SHARES AMOUNT DEFICIT) ADJUSTMENT TOTAL
--------------- --------------- --------------- --------------- ---------------
Balance, September 14, 1999 - $ - $ - $ - $ -
Issuance of common stock 4,510,000 24,806,000 - - 24,806,000
Net loss - - (491,000) - (491,000)
--------------- --------------- --------------- --------------- ---------------
Balance, December 31, 1999 4,510,000 24,806,000 (491,000) - 24,315,000
Issuance of common stock 10,000 55,000 - - 55,000
Issuance of common stock for
acquisition of CEC Resources Ltd. 1,482,826 6,518,000 - - 6,518,000
Vesting of restricted stock grants 18,800 116,000 - - 116,000
Currency translation adjustment - - - (225,000) (225,000)
Net income - - 1,456,000 - 1,456,000
--------------- --------------- --------------- --------------- ---------------
Balance, December 31, 2000 6,021,626 $ 31,495,000 $ 965,000 $ (225,000) $ 32,235,000
=============== =============== =============== =============== ===============
The accompanying notes are an integral part of these
consolidated financial statements.
-30-
CARBON ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE PERIOD
FROM INCEPTION
FOR THE YEAR (SEPTEMBER 14, 1999)
ENDED THROUGH
DECEMBER 31, 2000 DECEMBER 31, 1999
--------------------- ---------------------
Cash flows from operating activities:
Net income (loss) $ 1,456,000 $ (491,000)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization expense 5,536,000 628,000
Deferred income tax 417,000 -
Minority interest 24,000 -
Employee stock grants 116,000 -
Changes in operating assets and liabilities,
net of effects of acquisition:
Decrease (increase) in:
Accounts receivable (3,063,000) 203,000
Amounts due from broker (2,621,000) 269,000
Employee trust 867,000 17,000
Prepaid expenses and other (664,000) 38,000
Other assets 112,000 (337,000)
Increase (decrease) in:
Accounts payable and accrued expenses 496,000 711,000
Undistributed revenue 1,079,000 (39,000)
--------------------- ---------------------
Net cash provided by operating activities 3,755,000 999,000
Cash flows from investing activities:
Capital expenditures for oil and gas properties (7,941,000) (589,000)
Acquisition of Bonneville Fuels - (23,521,000)
Acquisition of CEC Resources (146,000) -
Capital expenditures for support equipment (179,000) -
--------------------- ---------------------
Net cash used in investing activities (8,266,000) (24,110,000)
Cash flows from financing activities:
Proceeds from note payable 30,852,000 400,000
Principal payments on note payable (27,381,000) (1,100,000)
Proceeds from issuance of common stock 55,000 24,806,000
--------------------- ---------------------
Net cash provided by financing activities 3,526,000 24,106,000
--------------------- ---------------------
Effect of exchange rate changes on cash 11,000 -
--------------------- ---------------------
Net increase (decrease) in cash (974,000) 995,000
Cash, beginning of period 995,000 -
--------------------- ---------------------
Cash, end of period $ 21,000 $ 995,000
===================== =====================
Supplemental cash flow information:
Cash paid for interest $ 1,147,000 $ 121,400
Cash paid for taxes 46,000 -
The accompanying notes are an integral part of these
consolidated financial statements.
-31-
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 in
September, 1999 under the laws of the State of Colorado to facilitate the
acquisition of Bonneville Fuels Corporation (BFC) and subsidiaries. The
acquisition of BFC closed on October 29, 1999 and was accounted for as a
purchase. In February 2000, Carbon completed an offer to exchange common shares
of Carbon for common shares of CEC Resources, Ltd. (CEC), an Alberta, Canada
company. Over 97% of the shareholders of CEC accepted the offer for exchange.
This acquisition closed on February 17, 2000 and was also accounted for as a
purchase as further described in Note 2. Collectively, Carbon, CEC, BFC and its
subsidiaries are referred to as the Company. The Company's operations currently
consist of the acquisition, exploration, development, and production of oil and
natural gas properties located primarily in Colorado, Kansas, New Mexico, Utah,
and the Canadian provinces of Alberta and Saskatchewan.
All amounts are presented in U.S. dollars unless otherwise noted.
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include the
accounts of Carbon and its subsidiaries all of which are wholly owned, except
CEC of which the Company owns approximately 97% of the equity at year end. All
significant intercompany transactions and balances have been eliminated.
CASH EQUIVALENTS - The Company considers all highly liquid instruments with
original maturities of three months or less when purchased to be cash
equivalents.
AMOUNTS DUE FROM BROKER - This account generally represents net cash margin
deposits held by a brokerage firm for the Company's futures accounts.
PROPERTY AND EQUIPMENT - The Company follows the full cost method of accounting
for its oil and gas properties, whereby all costs incurred in the acquisition,
exploration and development of properties (including costs of surrendered and
abandoned leaseholds, delay lease rentals, dry holes and direct overhead related
to exploration and development activities) are capitalized.
Capitalized costs are accumulated on a country-by-country basis and are depleted
using the units of production method based on proved reserves of oil and gas.
The Company presently has two cost centers - the United States and Canada. For
purposes of the depletion calculation, oil and gas reserves are converted to a
common unit of measure on the basis of six thousand cubic feet of gas to one
barrel of oil. A reserve is provided for the estimated future cost of site
restoration, dismantlement and abandonment activities as a component of
depletion. Investments in unproved properties are recorded at the lower of cost
or fair market value and are not depleted pending the determination of the
existence of proved reserves.
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 market value of
unproved properties included in the costs being amortized, if any; less (4)
related income tax effects. The costs reflected in the accompanying financial
statements do not exceed this limitation.
Proceeds from disposal of interests in oil and gas properties are accounted for
as adjustments of capitalized costs with no gain or loss recognized, unless such
adjustment would significantly alter the rate of depletion.
Buildings, transportation and other equipment are depreciated on the
straight-line method with lives ranging from 3 to 7 years.
-32-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EMPLOYEE TRUST - The employee trust represents amounts which will be used to
satisfy obligations to persons who have been, or will be, terminated as a result
of the Company's acquisition of BFC (see Note 4). The current portion of the
employee trust is expected to be disbursed or returned to the Company by October
31, 2001.
UNDISTRIBUTED REVENUE - Represents amounts due to other owners of jointly owned
oil and gas properties for their share of revenue from the Company's oil and gas
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. At December 31, 2000, wellhead
imbalances related to the Company's interests were minimal. 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 from time to time uses certain financial
instruments in an attempt to reduce exposure to the market fluctuations in the
price of oil and natural gas. The Company's general strategy is to hedge price
and location risk of a portion of the Company's production with swap, collar,
and floor and ceiling instruments.
Pursuant to Company guidelines, the Company is to engage in these activities
only as a hedging mechanism. 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. The
following table sets forth the hedge losses realized by the Company for 2000 and
1999.
For the Period
from Inception
(September 14, 1999)
For the Year Ended through
December 31, 2000 December 31, 1999
----------------------------------------------- ------------------------
United States Canada United States
--------------------- --------------------- ------------------------
(in thousands) (in thousands)
Oil $ 414 $ 186 $ -
Natural gas 2,608 987 157
-33-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Upon the acquisition of BFC and CEC the Company assumed open hedge contracts and
fixed price sales contracts that when marked to market reflected an obligation
of $1,733,000 and $553,000, respectively. These obligations were recorded as
liabilities. At December 31, 2000 these obligations were $453,000 for open hedge
contracts and $74,000 for fixed price sales contracts for BFC and $156,000 for
open hedge contracts for CEC. At December 31, 2000 these liabilities are
included in current liabilities. The liabilities will decline as the contracts
expire. The table below sets forth BFC's and CEC's derivative financial
instrument positions on its natural gas and oil production as of December 31,
2000.
BFC Contracts CEC Contracts
- ---------------------------------------- ------------------------------------
Weighted Weighted
Average Average
Fixed Price Fixed Price
Year MMBtu per MMBtu Year MMBtu per MMBtu
- ------- ------------ --------------- ------ ---------- ---------------
2001 1,408,000 $ 2.35 2001 391,000 $ 2.72
As of December 31, 2000, the Company would have been required to pay $5.7
million and $1.6 million to exit the BFC and CEC contracts, respectively.
In addition the Company utilizes collars that establish a price between a floor
and ceiling to hedge natural gas and oil prices. The table below sets forth the
Company's natural gas collars in place at December 31, 2000.
Average Average
Floor Ceiling
per per
Year MMBtu MMBtu MMBtu
- ----------- ---------- ------------ ------------
2001 85,000 $ 3.51 $ 4.89
As of December 31, 2000, the Company would have been required to pay $378,000 to
exit these contracts.
-34-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability
measured at its fair value. It also requires that changes in the derivative's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item in the income
statement, and requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge accounting. SFAS No.
133 is effective for all fiscal quarters of fiscal years beginning after June
15, 2000. The financial statement impact of recording derivative instruments
designated as hedges and derivative instruments not designated as hedges upon
adoption of SFAS No. 133 on January 1, 2001 is as follows:
Amount
(millions)
------------
Balance Sheet
Derivative liability $ (7.2)
Deferred tax asset 2.9
Cumulative effect of a change in accounting principle
(other comprehensive loss) 2.8
Statement of Operations
Cumulative effect of a change in accounting principle (derivative loss) $ 1.5
FOREIGN CURRENCY TRANSLATION - The functional currency of CEC is the Canadian
dollar. Assets and liabilities related to the Company's Canadian operations are
generally translated at current exchange rates, and related translation
adjustments are reported as a component of shareholders' equity. Income
statement accounts are translated at the average rates during the period. As a
result of the change in the value of the Canadian dollar relative to the US
dollar, the Company reported a non cash currency translation loss of $225,000
for the year ended December 31, 2000.
The Company follows the provisions of SFAS No. 130, "Reporting Comprehensive
Income." SFAS No. 130 establishes standards for reporting and display of
comprehensive income and its components in a full set of general-purpose
financial statements. In addition to net income, comprehensive income
includes all changes in equity during a period, except those resulting from
investment and distributions to owners. Separate statements of comprehensive
income have not been presented in these financial statements as the only
reconciling items between net income as reflected in the statements of
operation and comprehensive income would be the change in cumulative foreign
currency translation adjustment in 2000 of $225,000.
EARNINGS (LOSS) PER SHARE - The Company uses the weighted average number of
shares outstanding in calculating basic earnings per share data. When dilutive,
options are included as share equivalents using the treasury stock method and
are included in the calculations of diluted per share data.
ACCOUNTING ESTIMATES - The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the amounts reported in these financial
statements and the accompanying notes. The actual results could differ from
those estimates.
2. ACQUISITION OF CEC RESOURCES LTD.
On February 17, 2000, Carbon completed the acquisition of approximately 97% of
the common stock of CEC. An offer for exchange of Carbon common stock for CEC
common stock resulted in the issuance of 1,482,826 shares of Carbon common stock
to holders of CEC common stock. The acquisition was accounted for as a purchase.
The adjusted purchase price of $13,811,000 was comprised of the following:
-35-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Current liabilities assumed $ 1,041,000
Open hedge contracts assumed 553,000
Deferred income taxes 2,645,000
Long-term debt assumed 2,599,000
Professional fees incurred 455,000
Carbon common stock exchanged 6,518,000
-----------------
Total purchase price $ 13,811,000
=================
The following unaudited pro forma information presents a summary of the
consolidated results of operations as if the CEC acquisition had occurred at the
beginning of the period presented. Because Carbon had minimal operating
activities prior to November 1, 1999, the pro forma information presented is for
the year ended December 31, 2000 only.
FOR THE YEAR
ENDED
DECEMBER 31, 2000
----------------------
Total revenue $ 18,469,000
Net income $ 1,549,000
Earnings per share:
Basic $ 0.26
Diluted $ 0.26
These unaudited pro forma results have been prepared for comparative purposes
only and do not purport to be indicative of results of operations that actually
would have resulted had the CEC acquisition occurred at the beginning of the
period presented, or future results of operations of the consolidated entities.
3. LONG-TERM DEBT
U.S. FACILITY - The Company moved its credit facility from U.S. Bank National
Association to Wells Fargo Bank West, National Association in the third quarter
of 2000.
The facility is an oil and gas reserve based line-of-credit and had a borrowing
base of $16.1 million with outstanding borrowings of $12.5 million at December
31, 2000. The facility is secured by certain U.S. oil and gas properties of the
Company and is scheduled to convert to a term note on October 1, 2002. This
facility is scheduled to have a maturity date of either the economic half life
of the Company's remaining U.S. based reserves on the last day of the revolving
period, or October 1, 2006, whichever is earlier. The facility bears interest at
a rate equal to LIBOR plus 1.75% or Wells Fargo Bank West Prime, at the option
of the Company. The Company's average borrowing rate was approximately 8.5% at
December 31, 2000. The borrowing base is based upon the lender's evaluation of
the Company's proved oil and gas reserves, generally determined semi-annually.
-36-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Scheduled maturities of indebtedness under the U.S. facility for the next five
years are as follows:
Year Maturities
-------- ---------------
(in thousands)
2001 $ -
2002 782,000
2003 3,129,000
2004 3,129,000
2005 3,129,000
Thereafter 2,347,000
The credit agreement contains various covenants, which prohibit or limit the
Company's ability to pay dividends, purchase treasury shares, incur
indebtedness, sell properties or merge with another entity. The Company is also
required to maintain certain financial ratios.
CANADIAN FACILITY - The facility with the Canadian Imperial Bank of Commerce
(CIBC), has a borrowing base of approximately $4.4 million with outstanding
borrowings of $2.6 million at December 31, 2000. The Canadian facility is
secured by the Canadian oil and gas properties of the Company. The revolving
phase of the Canadian facility expired on December 31, 2000 and the Company is
currently in negotiations with CIBC to extend the revolving phase to April 1,
2002. However, there can be no guarantee that the Company will be able to
successfully negotiate such an extension. If the revolving commitment is not
renewed, the loan will be converted into a term loan and will be reduced by
consecutive monthly payments over a period not to exceed 36 months. However,
subject to possible changes in the borrowing base, CIBC has agreed that it will
not require the Company to make any principal payments under the term loan
section of the facility until January 2002 at the earliest. As such, no amounts
under the CIBC facility have been classified as current in the December 31, 2000
balance sheet. The Canadian facility bears interest at the CIBC Prime rate plus
3/4%. The rate was approximately 8.25% at December 31, 2000.
-37-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Scheduled maturities of indebtedness under the Canadian facility for the next
five years are as follows:
Year Maturities
-------- --------------
(in thousands)
2001 $ -
2002 856,000
2003 855,000
2004 855,000
The Canadian facility contains various covenants which limit the Company's
ability to pay dividends, purchase treasury shares, incur indebtedness, sell
properties, or merge with another entity.
The agreement with CIBC also contains a $3.0 million swap facility that provides
at the Company's request and subject to market availability, commodity swaps
covering a portion of the Company's oil and gas production, forward exchange
contracts and firm gas purchase and sales transactions. The Company currently
utilizes the swap facility to hedge its Canadian production (See Note 1).
4. SALARY CONTINUATION PLAN
In 1999, BFC established a Salary Continuation Plan (the Plan). The Plan
provides for continuation of salary and health, dental, disability, and life
insurance benefits for a certain period of time, based upon employment contracts
or length of service if the employee is terminated within two years following
the effective date of BFC's acquisition by Carbon. The Plan was initially funded
with a deposit of $1,546,000 into an interest bearing employee trust account.
Distributions through December 31, 2000 have been $922,000 for employees who
were terminated or had their employment contracts terminated.
The employee trust account is restricted from disbursing funds except for the
payment of benefits or upon the insolvency of the Company. Trustee fees were
minimal for the year ended December 31, 2000. Any remaining amounts in the trust
will revert to the Company upon expiration of the trust.
5. COMMITMENTS AND CONTINGENCIES
OFFICE LEASE - The Company entered into various lease agreements, which provide
for total minimum rental commitments as follows:
United States Canada
------------- -------------
2001 $ 197,000 $ 83,000
2002 203,000 83,000
2003 208,000 76,000
2004 212,000 -
2005 53,000 -
------------- -------------
Total $ 873,000 $ 242,000
============= =============
TRANSPORTATION AGREEMENTS - The Company has entered into various natural gas
transportation agreements in Canada. The Company typically assigns these
transportation agreements to a buyer of the Company's production during the
term of the natural gas sales contract between the Company and the buyer. The
Company is typically paid on an index basis, net of transportation charges
incurred by the buyer. The rights and obligations under these transportation
agreements will revert back to the Company upon expiration of the natural gas
sales contracts.
-38-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company is subject to governmental and regulatory controls arising in the
ordinary course of business. The Company is also a party to various lawsuits
incidental to its business. It is the opinion of the Company's management that
there are no claims or litigation involving the Company that are likely to have
a material adverse effect on its financial position or results of operations.
6. STOCK OPTIONS AND AWARD PLANS
In 1999, the Company adopted a stock option plan. All salaried employees of the
Company and its subsidiaries are eligible to receive both incentive stock
options and nonqualified stock options. Directors and consultants who are not
employees of the Company or its subsidiaries are eligible to receive
nonqualified stock options, but not incentive stock options under the plan. The
option price for the incentive stock options granted under the plan is not to
be less than 100% of the fair market value of the share subject to the option.
The option price for the nonqualified stock options granted under the plan is
not to be less than 85% of the fair market value of the shares subject to the
options. The aggregate number of shares of common stock, which may be issued
under options granted pursuant to the plan, may not exceed 700,000 shares.
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, 2000 and 1999 and changes
during these periods is presented below:
For the Period from Inception
For the Year Ended (September 14, 1999) through
December 31, 2000 December 31, 1999
---------------------------- ------------------------------
Number Weighted- Number Weighted-
of Average of Average
Option Exercise Option Exercise
Shares Price Shares Price
------------- ----------- ------------- ------------
Outstanding at beginning of period 115,000 $ 5.50 - $ -
Granted 520,500 5.29 115,000 5.50
Exercised - - - -
Forfeited (45,000) 5.78 - -
------------- -------------
Outstanding at end of year 590,500 5.30 115,000 5.50
============= =============
Options exercisable at year end 276,166 -
Shares available for grant at year end 109,500 585,000
Weighted-average fair value of options
granted during the year $ 1.51 $ 1.28
-39-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information about the Company's stock options
outstanding at December 31, 2000:
Options Outstanding Options Exercisable
- ---------------------------------------------------------------------- --------------------------------
Weighted-
Options Average Weighted- Options Weighted-
Range of Outstanding Remaining Average Exercisable Average
Exercise at Contractual Exercise at Exercise
Prices Year end Life Price Year end Price
- ---------------- -------------- -------------- -------------- -------------- --------------
$4.19 - $5.86 590,500 6.5 $ 5.30 276,166 $ 5.01
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 income (loss)
and income (loss) per share would have been as follows:
For the Period
from Inception
For the Year (September 14, 1999)
Ended through
December 31, 2000 December 31, 1999
----------------------- ------------------------
(in thousands except per share data)
Net income (loss):
As reported $ 1,456 $ (491)
Pro forma 1,276 (504)
Net income (loss) per share:
As reported:
Basic $ 0.25 $ (0.12)
Diluted 0.25 (0.12)
Pro forma:
Basic $ 0.22 $ (0.12)
Diluted 0.22 (0.12)
-40-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of each option grant is estimated on the date of the grant using
the Black-Scholes option pricing model with the following assumptions:
2000 1999
---------- ----------
Expected option life - years 3.50 5.00
Risk-free interest rate 6.36% 5.97%
Dividend yield 0.00% 0.00%
Volatility 25.79% 24.00%
In 1999, the Company adopted a restricted stock plan for selected employees,
directors and consultants of the Company and its subsidiaries. The aggregate
number of shares of common stock which may be issued under the plan may not
exceed 300,000 shares. The number of shares granted under this plan were 27,500
and 40,000 for 2000 and 1999, respectively. The Company recognized compensation
expense related to these grants of $116,000 for the year ended December 31,
2000. The shares vest ratably over 36 months.
7. INCOME TAXES
The following table sets forth the difference between the provision for income
taxes and the amounts computed by applying the statutory federal rate:
For the Period
from Inception
For the Year (September 14, 1999)
Ended through
December 31, 2000 December 31, 1999
----------------------- ----------------------
(in thousands)
Tax expense at 35% of income before income
taxes $ 743 $ (172)
State income taxes 17 -
Change in the valuation allowance against
deferred tax asset (192) 192
Impact of higher statutory rates on
Canadian income 151 -
Canadian resource allowance (375) -
Canadian Crown payments (net of Alberta
Royalty Tax Credit) 455 -
Other (132) (20)
----------------------- ----------------------
$ 667 $ -
======================= ======================
-41-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred income taxes generally result from recognizing income and expenses at
different times for financial and tax reporting. In the U.S. the largest
differences are the tax effects of the capitalization of certain development,
exploration and other costs, recording proceeds from the sale of properties in
the full cost pool and the provision for impairment of oil and gas properties.
In Canada, the largest difference results from accelerated recovery of capital
expenditures for tax purposes. The following table sets forth the Company's
long-term tax assets and liabilities at December 31, 2000 and 1999.
December 31, 2000
---------------------------------------------------------
United States Canada Total
---------------- ---------------- ---------------
(in thousands)
Deferred tax asset:
Net operating loss carryforward $ 921 $ - $ 921
Other 26 53 79
---------------- ---------------- ---------------
Gross deferred tax assets 947 53 1,000
Deferred tax liability:
Property and equipment (991) (2,993) (3,984)
---------------- ---------------- ---------------
Gross deferred tax liabilities (991) (2,993) (3,984)
---------------- ---------------- ---------------
Net deferred tax asset (liability) $ (44) $ (2,940) $ (2,984)
================ ================ ===============
December 31, 1999
---------------------------------------------------------
United States Canada (1) Total
---------------- ---------------- ---------------
(in thousands)
Deferred tax asset:
Net operating loss carryforward $ 297 $ - $ 297
Other 90 - 90
---------------- ---------------- ---------------
Gross deferred tax assets 387 - 387
Deferred tax liability:
Property and equipment (195) - (195)
---------------- ---------------- ---------------
Gross deferred tax liabilities (195) - (195)
Valuation allowance (192) - (192)
---------------- ---------------- ---------------
Net deferred tax asset (liability) $ - $ - $ -
================ ================ ===============
- ---------------------
(1) Canadian deferred tax assets and liabilities are presented only for
December 31, 2000 as the Company acquired CEC in February 2000.
As of December 31, 2000, the Company had a net operating loss carryforwards for
federal income tax purposes of $2.4 million which expire in the years 2019 and
2020.
-42-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. PROPERTIES SUBJECT TO TAX CREDIT AGREEMENT
During 1995, BFC entered into an agreement to sell 99% of its interest in 14
coal gas wells located in New Mexico that qualified for IRC section 29 tax
credits. Under the terms of the agreement, BFC is to receive 99% of the net cash
flow on the properties until certain cumulative production levels are reached,
at which time the counter party will receive 100% of the net cash flow until the
second production level is reached. Upon reaching the second level, 100% of the
cash flows will revert to BFC for substantially the remaining life of the
properties.
-43-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. BUSINESS AND GEOGRAPHICAL SEGMENTS
Segment information has been prepared in accordance with Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and
Related Information" (SFAS No. 131). During 2000, Carbon had two reportable and
geographic segments: BFC and CEC, representing oil and gas operations in the
United States and Canada, respectively. The segments are strategic business
units which operate in unique geographic locations. The segment data presented
below was prepared on the same basis as Carbon's consolidated financial
statements.
For the Period
For the Year from February 18
Ended through
December 31, 2000 December 31, 2000 Consolidated
United States Canada Totals
---------------------- --------------------- ----------------------
Oil and gas sales $ 11,054,000 $ 6,590,000 $ 17,644,000
Marketing and other, net 245,000 (70,000) 175,000
---------------------- --------------------- ----------------------
Total revenues 11,299,000 6,520,000 17,819,000
Oil and gas production costs 3,774,000 2,009,000 5,783,000
Depreciation and depletion 4,042,000 1,494,000 5,536,000
General and administrative, net 1,989,000 1,260,000 3,249,000
Interest expense, net 917,000 187,000 1,104,000
---------------------- --------------------- ----------------------
Total operating expenses 10,722,000 4,950,000 15,672,000
Minority interest in net income - 24,000 24,000
Income tax 44,000 623,000 667,000
---------------------- --------------------- ----------------------
Net income $ 533,000 $ 923,000 $ 1,456,000
====================== ===================== ======================
---------------------- --------------------- ----------------------
Total assets $ 44,279,000 $ 18,201,000 $ 62,480,000
====================== ===================== ======================
-44-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. MAJOR CUSTOMERS
For the year ended December 31, 2000, revenues from one customer of the
Company's U.S. operations and one customer of the Company's Canadian operations
represented approximately 16% and 20%, respectively, of the Company's
consolidated revenues.
For the period from inception (September 14, 1999) through December 31, 1999,
revenues from three customers of the Company's U.S. operations represented 28%,
12% and 12%, respectively, of the Company's consolidated revenues.
Management believes that the loss of any individual purchaser would not have a
long-term material adverse impact on the financial position or results of
operations of the Company.
11. 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 carrying amounts
of such financial instruments approximate fair value due to their short
maturities. As a result of the variable interest rates on the Company's debt
facilities at December 31, 2000, 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 1).
12. TRADING ACTIVITIES
The Company engages in natural gas trading activities which involve purchasing
natural gas from third parties and selling natural gas to other parties. These
transactions are typically short-term in nature and involve positions whereby
the underlying quantities generally offset. The Company has reduced its efforts
concerning the marketing of third party natural gas and anticipates that this
will continue in 2001. Trading income associated with these activities is
presented on a net basis in the financial statements. The following table sets
forth the gross trading activities.
For the Period
from Inception
(September 14,
For the Year 1999)
Ended through
December 31, 2000 December 31, 2000
------------------- --------------------
(in thousands)
Revenues, gross $ 5,445 $ 1,032
Operating expenses, gross 5,515 1,028
------------------- --------------------
Net trading income (loss) $ (70) $ 4
=================== ====================
13. SUBSEQUENT EVENTS
-45-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On January 5, 2001, the Company closed the sale of its entire working interest
and related leasehold rights in the San Juan Basin. The effective date of the
sale was September 1, 2000 and the purchase price was $7.5 million, subject to
certain adjustments.
On February 6, 2001, CEC completed its offer to purchase shares of CEC common
stock that were not owned by Carbon. Of the approximate 39,000 shares of CEC
common stock that were not previously acquired by Carbon, approximately 34,000
shares of CEC common stock were purchased by CEC as a result of this offer.
After the offer, Carbon owns 99.7% of the common stock of CEC.
14. DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
(A) Costs Incurred in Oil and Gas Producing Activities
The following table sets forth costs incurred in oil and gas property
acquisition, exploration and development activities for the year ended December
31, 2000 and the period from inception (September 14, 1999) through December 31,
1999.
United
States Canada Total
------------- ------------- --------------
(in thousands)
2000 (1)
- ---------
Acquisition of properties (2):
Proved properties $ - $ 14,176 $ 14,176
Unproved properties 1,217 161 1,378
Exploration (3) 2,895 19 2,914
Development (4) 1,495 3,627 5,122
------------- ------------- --------------
Total $ 5,607 $ 17,983 $ 23,590
============= ============= ==============
1999 (5)
- ---------
Acquisition of properties:
Proved properties $ 24,535 $ - $ 24,535
Unproved properties 7,879 - 7,879
Exploration 347 - 347
Development 138 - 138
------------- ------------- --------------
Total $ 32,899 $ - $ 32,899
============= ============= ==============
- ----------------------------
(1) Canadian results for 2000 are the results of CEC subsequent to its
acquisition by Carbon in February 2000.
(2) Property acquisition costs include costs incurred to purchase, lease
or otherwise acquire a property.
(3) Exploration costs include the costs of geological and geophysical
activity, dry holes and drilling and equipping exploratory wells.
(4) Development costs include costs incurred to gain access to and prepare
development well locations for drilling and to drill and equip development
wells and costs for supporting production facilities consisting primarily
of natural gas gathering systems.
(5) United States results for 1999 are the results of the Company from its
inception (September 14, 1999) through December 31, 1999.
-46-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(B) Aggregate Capitalized Costs
The following table sets forth the aggregate capitalized costs relating to oil
and gas activities at the end of each of the years indicated.
December 31, 2000
---------------------------------------------------
United
States Canada Total
-------------- -------------- ---------------
Oil and gas properties, full cost method:
Unevaluated properties not being amortized $ 6,412 $ 164 $ 6,576
Evaluated costs 32,094 17,453 49,547
-------------- -------------- ---------------
Total capitalized costs 38,506 17,617 56,123
Less - Accumulated DD&A (4,553) (1,485) (6,038)
-------------- -------------- ---------------
Net capitalized costs $ 33,953 $ 16,132 $ 50,085
============== ============== ===============
December 31, 1999
---------------------------------------------------
United
States Canada (1) Total
-------------- -------------- ---------------
Oil and gas properties, full cost method:
Unevaluated properties not being amortized $ 7,879 $ - $ 7,879
Evaluated costs 25,020 - 25,020
-------------- -------------- ---------------
Total capitalized costs 32,899 - 32,899
Less - Accumulated DD&A (617) - (617)
-------------- -------------- ---------------
Net capitalized costs $ 32,282 $ - $ 32,282
============== ============== ===============
------------------------
(1) Canadian aggregate capitalized costs are presented only for December 31,
2000 as the Company acquired CEC in February 2000.
The Company anticipates that substantially all unevaluated costs will be
classified as evaluated costs within five years.
-47-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(C) Estimated Proved Oil and Gas Reserves
The table below sets forth the estimated quantities of year end proved reserves
at December 31, 2000 and 1999. The reserve estimates for properties located in
the United States were prepared by Ryder Scott Company, an independent reservoir
engineering firm, and the Canadian reserve estimates were prepared by Sproule
Associates Limited, independent geological petroleum engineering consultants.
Oil and Liquids Natural Gas
----------------------------------- ----------------------------------
(MBbl) (MMcf)
United United
States Canada (1) Total States Canada (1) Total
--------- ----------- ---------- --------- ----------- ---------
Balance, September 14, 1999 - - - - - -
Revisions of previous estimates 2 - 2 250 - 250
Purchases of reserves in place 235 - 235 31,331 - 31,331
Production (9) - (9) (569) - (569)
--------- -------- --------- --------- --------- ---------
Balance, December 31, 1999 228 - 228 31,012 - 31,012
Revisions of previous estimates 278 - 278 4,179 - 4,179
Extensions, discoveries and additions 70 145 215 283 7,749 8,032
Purchases of reserves in place - 537 537 - 17,535 17,535
Production (69) (53) (122) (3,374) (1,679) (5,053)
--------- -------- --------- --------- --------- ---------
Balance, December 31, 2000 507 629 1,136 32,100 23,605 55,705
========= ======== ========= ========= ========= =========
Proved developed reserves (2):
December 31, 1999 212 - 212 26,232 - 26,232
December 31, 2000 382 560 942 26,422 20,276 46,698
Balance, December 31, 2000
Proved reserves - Canada, after Crown
royalty interests 461 18,867
Balance, December 31, 2000
Proved developed reserves - Canada, after
Crown royalty interests 411 16,193
- ------------------------
(1) Canadian reserves are presented only for 2000 as the Company acquired CEC
in February 2000. Estimates of proved Canadian reserves presented in this
table are net before Crown royalty interests.
(2) Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods.
In accordance with applicable requirements of the Securities and Exchange
Commission (SEC), estimates of the Company's proved reserves and future net
revenues are made using sale prices estimated to be in effect as of the date of
the reserve estimates and are held constant throughout the life of the
properties (except to the extent contractual arrangements in existence at year
end specifically provide for escalation). Price declines decrease reserve values
by lowering the future net revenues attributable to the revenues and may reduce
the quantities of reserves that are recoverable on an economic basis. Price
increases may have the opposite effect. A significant decline in prices of
natural gas or oil could have a material adverse effect on the Company's
financial condition and results of operations. Future prices received for
production and future production costs may vary, perhaps significantly, from the
prices and costs assumed for purposes of these estimates.
-48-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 gas reserve engineering is a subjective process of
estimating underground accumulations of natural gas and oil 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
interpretations and judgment. 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 declines 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 of the Company will decline as reserves are produced.
Reserves generated from future activities of the Company are therefore highly
dependent upon the level of success in acquiring or discovering additional
reserves and the costs incurred in doing so.
(D) Standardized Measure
The standardized measure schedule is presented pursuant to the disclosure
requirements of the SEC and Statement of Financial Accounting Standards No. 69,
"Disclosures About Oil and Gas Producing Activities" (SFAS No. 69).
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, 2000 and 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, 2000 and 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 tax expenses are estimated by applying the
statutory tax rate of 35% in the United States and a combined Federal and
Provincial rate of 44.62% in Canada with recognition of tax basis, net
operating loss carryforwards and other statutory deductions. Estimates for
future general and administrative and interest expense have not been
considered. For standardized measure purposes, the Company estimates future
income taxes using the "year-by-year" method. For ceiling test purposes, the
Company estimates future income taxes using the "short-cut" method.
Discounted amounts are based on a 10% annual discount rate.
-49-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED STATEMENTS
The following table sets forth the Company's standardized measure of discounted
future net cash flows at December 31, 2000 and 1999.
December 31, 2000
-----------------------------------------------------
United
States Canada Total
-------------- --------------- --------------
(in thousands)
Future oil and gas revenue $ 326,156 $ 186,815 $ 512,971
Future production costs (51,331) (14,828) (66,159)
Future development costs (7,923) (2,719) (10,642)
Future income tax expense (75,844) (65,986) (141,830)
-------------- --------------- -------------
Future net cash flows 191,058 103,282 294,340
10% annual discount for estimated
timing of cash flows (79,804) (27,872) (107,676)
-------------- --------------- --------------
Standardized measure of discounted
future net cash flows $ 111,254 $ 75,410 $ 186,664
============== =============== ==============
The computation of the standardized measure of discounted future net cash flow
relating to proved oil and gas reserves at December 31, 2000 was based on
average oil and liquids prices of $25.50 per barrel in the United States and
$21.73 per barrel in Canada, and average natural gas prices of $9.76 per Mcf in
the United States and $9.00 per Mcf in Canada.
December 31, 1999
-----------------------------------------------------
United
States Canada (1) Total
-------------- --------------- --------------
(in thousands)
Future oil and gas revenue $ 68,542 $ - $ 68,542
Future production costs (19,473) - (19,473)
Future development costs (5,916) - (5,916)
Future income tax expense (772) - (772)
-------------- --------------- --------------
Future net cash flows 42,381 - 42,381
10% annual discount for estimated
timing of cash flows (16,952) - (16,952)
-------------- --------------- --------------
Standardized measure of discounted
future net cash flows $ 25,429 $ - $ 25,429
============== =============== ==============
- ---------------------
(1) The standardized measure of discounted future net cash flows are not
presented for the Canadian reserves as the Company acquired CEC in February
2000.
-50-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED STATEMENTS
The computation of the standardized measure of discounted future net cash flow
relating to proved oil and gas reserves as of December 31, 1999 was based on
average oil prices of $24.41 per barrel and natural gas prices of $2.05 per Mcf.
The standardized measure of discounted future net cash flows should not be
construed to be an estimate of the fair value of the Company's proved reserves.
Changes in the demand for oil and gas, price changes, reserve recovery variances
and other factors make such estimates inherently imprecise and subject to
revision.
The tables below set forth the principle sources of changes in the standardized
measure of discounted future net cash flows for the year ended December 31, 2000
and the period from inception (September 14, 1999) through December 31, 1999.
December 31, 2000
----------------------------------------------------
United
States Canada (1) Total
------------- --------------- ---------------
(in thousands)
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at beginning of year $ 25,429 $ - $ 25,429
Changes resulting from:
Sales and transfers of oil and gas produced, net of
production costs (10,302) (6,961) (17,263)
Net change in sales price and future production costs 113,753 - 113,753
Net changes in future development costs (1,269) - (1,269)
Net changes due to extensions, discoveries and improved
recovery 2,243 35,084 37,327
Revision of previous quantity estimates 27,019 - 27,019
Purchase of reserves in place - 76,377 76,377
Accretion of discount 2,619 - 2,619
Net change in income tax (41,502) (39,094) (80,596)
Other (6,736) 10,004 3,268
------------ --------------- ---------------
Net changes 85,825 75,410 161,235
------------ --------------- ---------------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at end of year $ 111,254 $ 75,410 $ 186,664
============ =============== ===============
- ----------------------
(1) Changes in Canadian reserves for 2000 represent changes since the
Company's acquisition of CEC in February 2000.
-51-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED STATEMENTS
December 31, 1999
-------------------------------------------------------
United
States Canada (1) Total
--------------- --------------- ---------------
(in thousands)
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at inception (September 14, 1999) $ - $ - $ -
Changes resulting from:
Sales and transfers of oil and gas produced, net of
production costs (1,140) - (1,140)
Net change in sales price and future production costs (7,248) - (7,248)
Revision of previous quantity estimates 23 - 23
Purchase of reserves in place 34,136 - 34,136
Accretion of discount 341 - 341
Other (683) - (683)
--------------- --------------- ---------------
Net changes 25,429 - 25,429
--------------- --------------- ---------------
Standardized measure of discounted future net cash flows relating
to proved oil and gas reserves, at end of year $ 25,429 $ - $ 25,429
=============== =============== ===============
- ----------------------
(1) Changes in Canadian reserves for 1999 are not presented as the Company
acquired CEC in February 2000.
-52-
CARBON ENERGY CORPORATION
NOTES TO CONSOLIDATED STATEMENTS
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table sets forth the Company's quarterly results of operations for
2000. For 1999, the Company's operating activities prior to November 1, 1999
were minimal.
2000
------------------------------------------------------------
Mar 31 Jun 30 Sep 30 Dec 31
------------ ------------ ------------ ------------
(in thousands expect per share data)
Operating revenues $ 3,233 $ 3,903 $ 4,363 $ 6,320
Operating expenses $ 1,022 $ 1,226 $ 1,578 $ 1,957
Operating margin $ 2,211 $ 2,677 $ 2,785 $ 4,363
Net income $ 230 $ 118 $ 172 $ 936
Basic earnings per share $ 0.04 $ 0.02 $ 0.03 $ 0.16
Diluted earnings per share 0.04 0.02 0.03 0.15
In the fourth quarter of 2000, the Company commenced reporting its marketing and
other activities on a net basis. The above table reflects this methodology.
The following table sets forth the Company's quarterly results of operations
as originally reported.
2000
--------------------------------------------
Mar 31 Jun 30 Sep 30
------------ ------------ ------------
(in thousands)
Operating revenues $ 4,710 $ 4,744 $ 5,179
Operating expenses $ 2,499 $ 2,067 $ 2,394
Operating margin $ 2,211 $ 2,677 $ 2,785
-53-
BONNEVILLE FUELS CORPORATION
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
-54-
INDEX TO FINANCIAL STATEMENTS
PAGE
INDEPENDENT AUDITOR'S REPORT..........................................................................................56
CONSOLIDATED BALANCE SHEETS - October 31, 1999 and December 31, 1998..................................................57
CONSOLIDATED STATEMENTS OF OPERATIONS - For the Period From January 1, 1999 through October 31, 1999 and the Years
Ended December 31, 1998 and 1997.............................................................................58
CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY - For the Period From January 1, 1997
through October 31, 1999.....................................................................................59
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.............................................................................60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS............................................................................61
-55-
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
-56-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
OCTOBER 31, DECEMBER 31,
----------------------- ----------------------
1999 1998
----------------------- ----------------------
ASSETS
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
======================= ======================
See accompanying notes to these consolidated financial statements.
-57-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE TEN
MONTHS ENDED FOR THE YEAR ENDED
OCTOBER 31, DECEMBER 31,
-------------------- -------------------------------------
1999 1998 1997
-------------------- ----------------- ------------------
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
==================== ================= ==================
See accompanying notes to these consolidated financial statements.
-58-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY
FOR THE PERIOD FROM JANUARY 1, 1997 THROUGH OCTOBER 31, 1999
COMMON STOCK ADDITIONAL
--------------------- PAID-IN RETAINED
SHARES PAR VALUE CAPITAL EARNINGS TOTAL
---------- --------- ------------- ------------- ------------
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
========== ========= ============= ============= ============
See accompanying notes to these consolidated financial statements.
-59-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE TEN
MONTHS ENDED FOR THE YEAR ENDED
OCTOBER 31, DECEMBER 31,
----------------- -------------------------------------------
1999 1998 1997
----------------- --------------------- --------------------
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 $ -
================= ===================== ====================
See accompanying notes to these consolidated financial statements.
-60-
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 of salvage values. The total cumulative
amount accrued as additional depletion for plugging and abandonment is $612,000
at October 31, 1999.
-61-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 values on
certain producing properties in 1998 and re-assessment of reserve 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 expense 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.
-62-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DEFERRED LOAN COSTS - Costs associated with the Company's note payable have been
deferred and are being amortized using the effective interest method over the
original term of the note.
GAS BALANCING - The Company uses the sales method of accounting for amounts
received from natural gas sales resulting from production credited to the
Company in excess of its revenue interest share. Under this method, all proceeds
from production credited to the Company are recorded as revenue until such time
as the Company has produced its share of related estimated remaining reserves.
Thereafter, additional amounts received are recorded as a liability.
INCOME TAXES - The Company accounts for income taxes under the liability method
which requires recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns. Under this method, deferred tax assets and
liabilities are determined based on the difference between the financial
statement and tax basis 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.
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, BPC 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.
-63-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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 have 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.
-64-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. EXPLORATION EXPENSE
Exploration expense consists of the following:
For the
Ten Months
Ended For the Year Ended
October 31, December 31,
------------------- ----------------- ------------------
1999 1998 1997
------------------- ----------------- ------------------
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
=================== ================= ==================
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
================
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.
-65-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. INCOME TAXES
The components of the net deferred tax assets are as follows:
As of As of
October 31, December 31,
--------------- ----------------
1999 1998
--------------- ----------------
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 $ - $ -
=============== ================
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.
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.
-66-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. FINANCIAL INSTRUMENTS
SFAS Nos. 107 and 127 require certain entities to disclose the fair value of
certain financial instruments in their financial statements. Accordingly,
management's best estimate is that the carrying amount of cash, receivables,
notes payable, accounts payable, undistributed revenue, and accrued expenses
approximates the fair value of these instruments. See Note 8 for a discussion
regarding the fair value of energy financial instruments.
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,
an 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
-67-
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 Bonneville'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 Bonneville'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)
October 31, December 31, December 31,
1999 1998 1997
----------------- ----------------- -----------------
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
================= ================= =================
-68-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
(THOUSANDS OF DOLLARS)
October 31, December 31, December 31,
1999 1998 1997
---------------------- ----------------- ------------------
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
====================== ================= ==================
COSTS INCURRED IN PROPERTY ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES
(IN THOUSANDS)
Ten Months
Ended Year Ended Year Ended
October 31, December 31, December 31,
1999 1998 1997
----------------------- ----------------- ------------------
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
======================= ================= ==================
-69-
BONNEVILLE FUELS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CAPITALIZED COSTS RELATED TO OIL AND GAS
PRODUCING ACTIVITIES
(IN THOUSANDS)
October 31, December 31,
1999 1998
----------------- -----------------
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
================= =================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
-70-
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 2001 Annual Meeting of Shareholders, to be filed, is
incorporated by reference into this Report.
-71-
PART IV
ITEM 14. 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, 2000: None.
(c) Exhibits:
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------- ---------------------------------------------------------------------
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 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.
-72-
10.7 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 Credit agreement dated as of September 22, 2000 between Bonneville
Fuels Corporation and Wells Fargo Bank West, National Association,
incorporated by reference in Exhibit 10.1 of the Company's Quarterly
Report on Form 10-Q, No. 1-15639, filed November 14, 2000.
10.9 Financing commitment dated as of September 15, 2000 between CEC
Resources Ltd. and Canadian Imperial Bank of Commerce, incorporated by
reference to Exhibit 10.2 of the Company's Quarterly Report on Form
10-Q, No. 1-15639, filed November 14, 2000.
23.1 Consent of Arthur Andersen LLP *
23.2 Consent of Hein + Associates LLP *
23.3 Consent of Ryder Scott Company, L.P. *
23.4 Consent of Sproule Associates Limited *
24 Power of Attorney *
* Filed herewith
-73-
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: April 2, 2001.
CARBON ENERGY CORPORATION
By: /s/ PATRICK R. MCDONALD
--------------------------------------------
Patrick R. McDonald, President and
Chief Executive Officer
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:
Date Name and Title Signature
- ---------------------- --------------------------- ----------------------------------------
April 2, 2001 Cortlandt S. Dietler, )
Director )
) /s/ Patrick R. McDonald
----------------------------------------
April 2, 2001 David H. Kennedy, ) Patrick R. McDonald, for himself and
Director ) as Attorney-in-Fact for the named
) directors who together constitute all
April 2, 2001 Bryan H. Lawrence, ) of the members of Registrant's Board
Director ) of Directors
)
April 2, 2001 Peter A. Leidel, )
Director )
)
April 2, 2001 Patrick R. McDonald, )
Director )
)
April 2, 2001 Harry A. Trueblood, Jr., )
Director )
-74-
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------------------ ------------------------------------------------------------------------------------------------
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Hein + Associates LLP
23.3 Consent of Ryder Scott Company, L.P.
23.4 Consent of Sproule Associates Limited
24 Power of Attorney
-75-