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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[Mark One]
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 2001
or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from __________ to __________
Commission file number 000-31819
Canaan Energy Corporation
(Exact name of registrant as specified in its charter)
Oklahoma 73-1300132
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
211 North Robinson, Suite 1000N
Oklahoma City, Oklahoma 73102
(Address of principal executive offices) (Zip Code)
(405) 604-9200
Registrant's telephone number, including area code
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
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None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
Preferred Share Purchase Rights
(Title of Class)
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_]
Indicate 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
amendments to this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
registrant, computed by using the closing sale price of the registrant's common
stock as of March 26, 2002 was $39,842,000. On that date, the number of
outstanding shares, $0.01 par value, was 4,353,646.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K is
incorporated by reference from Registrant's definitive proxy statement to be
filed pursuant to Regulation 14A for the Registrant's 2002 Annual Meeting of
Stockholders.
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TABLE OF CONTENTS
Item Page
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PART I
1. BUSINESS....................................................... 1
2. PROPERTIES..................................................... 6
3. LEGAL PROCEEDINGS.............................................. 13
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............ 13
PART II
5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS...................................................... 14
6. SELECTED FINANCIAL DATA........................................ 15
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS........................................ 17
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..... 28
8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA..................... 29
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE......................................... 29
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............. 30
11. EXECUTIVE COMPENSATION......................................... 30
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. 30
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................. 30
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 31
SIGNATURES........................................................... 33
PART I
ITEM 1. Business
The Company
Canaan Energy Corporation ("Canaan" and the "Company"), formerly known as
Coral Reserves Group, Ltd., is an independent oil and natural gas company
headquartered in Oklahoma City, Oklahoma. Canaan was formed in March 1987 as an
Oklahoma corporation by Leo E. Woodard and John K. Penton. Mr. Woodard
continues to serve the Company as Chief Executive Officer and Mr. Penton serves
as President.
From inception, Canaan engaged in and attained growth through the
acquisition and exploitation of producing properties. Between 1990 and 1996
Canaan formed eight limited partnerships ("Partnerships"). Coral Reserves, Inc.
("Coral Inc.") and Coral Reserves Energy Corp. ("Coral Corp."), subsidiaries of
Canaan, (collectively referred to as the "General Partners") served as general
partners of the Partnerships and Canaan provided management services to Coral
Inc. and Coral Corp. The purposes of the Partnerships were to acquire producing
oil and natural gas properties primarily in Oklahoma and to conduct limited
additional development activity relating to the acquired properties. Canaan
Securities, Inc. ("CSI"), an unaffiliated broker/dealer, served as placement
agent in connection with the private placement of the limited partnerships
interests in the Partnerships.
In 1997, Canaan and the General Partners began to consider the possibility
of combining the Partnerships into a publicly held oil and natural gas company
in order to achieve the benefits of a corporate entity with a larger asset base
and greater growth potential than available to any individual partnership. In
February 1999, Indian Oil Company ("Indian"), a privately held Oklahoma
corporation engaged in oil and natural gas exploration, development and
production, primarily in Oklahoma, Canaan and the General Partners entered into
an agreement for Canaan to acquire all the outstanding stock of Indian. Shortly
thereafter, management initiated a plan to effect a series of combination
transactions whereby Canaan would acquire all of the limited partners'
interests in the Partnerships and 100% of the stock of Coral Inc., Coral Corp.,
CSI and Indian with registered common shares of Canaan. Canaan and the other
entities entered into a plan of combination in February 2000 providing for the
terms of the combination transactions.
On October 23, 2000, the combination transactions were overwhelmingly
approved at meetings of the former stockholders of Indian, Coral Inc., Coral
Corp., CSI and the limited partners. Canaan issued 4,368,815 shares of our
common stock as consideration for the acquired entities. Canaan also paid a
stock dividend of 562,368 shares to our stockholders of record immediately
prior to the transaction for the purpose of increasing Canaan's existing shares
to the amount allocated to it under the terms of the combination transaction.
Trading of Canaan's common shares on NASDAQ National Market System under the
ticker symbol of "KNAN" commenced on October 26, 2000.
As of December 31, 2001, Canaan operated 190 of the 949 wells in which it
owned a working interest, and these operated wells accounted for 35% of total
net production based on estimated production for January 2002. For the month of
January 2002, the Company's daily net production averaged 20.8 MMcfe,
consisting of 18.2 MMcf of natural gas and 435 Bbls of oil. Total net proved
reserves as of December 31, 2001 were 94.9 Bcfe, of which 91% were natural gas,
with proved developed reserves representing 77% of the total and proved
undeveloped reserves accounting for the remaining 23%.
All historical information in this document relating to Canaan includes
information relating to the Partnerships and the General Partners. Canaan's
historical financial statements have been restated as if Canaan had owned such
interests since their inception.
Business Strategy
Canaan's business strategy is to generate strong and consistent growth in
reserves, production, operating cash flows and earnings. This strategy will be
implemented through the following:
Natural Gas Focus. We emphasize growth in natural gas reserves and
believe that the long-term supply and demand fundamentals for natural gas
are favorable for continued strength in natural gas prices.
1
Natural gas continues to gain recognition as an efficient, clean and
environmentally-friendly fuel source alternative. This is particularly true
for electricity generation facilities, which are increasingly turning to
natural gas for their power consumption needs. About 91% of our reserve base
is comprised of natural gas, making us substantially more leveraged to
natural gas than the industry average.
Impact Acquisitions. We seek acquisitions that are geographically
concentrated in our core areas where we possess considerable operating
expertise and realize economies of scale. We principally target acquisitions
which have significant development potential, are in close proximity to
existing properties, have a high degree of operatorship and can be
integrated with minimal incremental administrative cost. The Vintage
Petroleum, Inc. acquisition in late 2001, as discussed below, is a prime
example of this type of acquisition.
Diversification Through Joint Ventures. We participate with industry
partners to diversify and enhance growth of our core areas. During 2001,
Canaan entered into a joint venture with a successful operator in the South
Texas onshore region. The opportunities acquired through this joint venture
included 3-D seismic data and technology that are being used to identify
high impact drilling prospects. The Company expects to begin drilling in
this region in mid-2002. The potential reserves attributable to this South
Texas venture, as in the Mid-Continent region, are primarily longer
producing, natural gas reserves. Canaan will continue to seek drilling
opportunities in this area with the ultimate goal of developing the South
Texas region as a new core area for Canaan.
Identification and Development of Prospects. We aggressively exploit the
value in our oil and natural gas property base through an active development
drilling program. The development drilling program has and will be an
important source of low-risk production growth and is conducted in areas
where multiple productive oil and natural gas wells have been drilled,
thereby reducing dry hole risks. Canaan also employs aggressive land
strategies to increase ownership in existing properties with development
potential and, to obtain acreage in areas of interest through acquisitions,
leases or farm-ins. During 2001, we participated in the drilling of 58
development wells with a 97% success rate. For 2002, we plan to continue our
development program in the Mid-Continent area and begin developing high
impact drilling prospects in the South Texas area.
Canaan has accumulated interests in 319,816 developed and 45,834
undeveloped gross acres with 250 identified potential drilling locations and
90 square miles of 3-D seismic. Of these locations, 65 had been assigned
proved undeveloped reserves at December 31, 2001.
Geographically-Concentrated Property Base. We own working interests in
949 wells located primarily in the Mid-Continent area. As a result of this
geographically-concentrated property base, the opportunity to generate
positive results through the application of improved production technologies
and to achieve economies of scale is enhanced while the risk of material
adverse financial consequences from unexpected production interruptions is
minimized. We have three field offices in our core areas and employ
approximately 24 pumpers and other field personnel to provide onsite
management of our properties.
Canaan intends to finance its growth through various methods including bank
and other borrowings, private equity offerings and cash flow from operations.
Canaan may pursue public equity and/or debt offerings when industry and market
conditions will allow the successful placement of such securities.
2001 Significant Developments
Our activities in 2001 included building a corporate team to manage a larger
public company. Prior to the closing of the combination transaction in October
2000, we had 14 employees. Since that time, through March 26, 2002, we added 34
employees, including former Indian employees, a number of geological,
engineering and land personnel. In 2001, we participated in the drilling of 58
gross (10.5 net) wells, of which we operated 7 gross (4.8 net) wells, at an
aggregate capital cost of $12.4 million.
2
During 2001, Canaan entered into a joint venture with a successful operator
in the South Texas onshore region as described below. In December 2001, the
Company acquired from Vintage Petroleum, Inc. for $2.1 million, five operated,
producing wells in Custer County, Oklahoma. This strategic Mid-Continent
acquisition in our Deep Anadarko Basin area also includes the upside potential
of two proved undeveloped and two nonproved locations. Netherland, Sewell &
Associates, Inc. ("NSAI"), independent reservoir engineers, estimated proved
reserves of 3.0 Bcfe as of December 31, 2001 attributable to this acquisition
reflecting an attractive acquisition price of approximately $0.70 per Mcfe.
In November 2001, we exercised a right of first refusal to purchase 560,169
shares of our common stock, totaling approximately 11% of our shares
outstanding, for $12 per share or a total of $6.7 million. These shares were
owned by certain former shareholders of Indian and had been offered to
Chesapeake Energy Corporation, an Oklahoma City based oil and gas company that
had previously expressed an interest in acquiring Canaan.
Subsequent to November 2001, Chesapeake acquired 333,149 shares, or 7.65%,
of our common stock from former Indian shareholders. In March 2002, Chesapeake
publicly announced its intention to commence a tender offer for our common
stock at $12 per share. We have engaged CIBC World Markets Corp. as our
financial advisor to assist us in evaluating this proposal as well as our other
strategic alternatives which may maximize value for all shareholders.
Marketing
The ability of Canaan to market oil and natural gas generally depends on
factors beyond its control. The potential effects of governmental regulation
and market factors, including alternative domestic and imported energy sources,
available pipeline capacity and general market conditions are not entirely
predictable.
Natural Gas. Natural gas is generally sold pursuant to individually
negotiated natural gas purchase contracts, which vary in length from spot
market sales of a single day to term agreements that may extend several years.
Customers who purchase natural gas include marketing affiliates of the major
pipeline companies, natural gas marketing companies and a variety of commercial
entities, public authorities and industrial and institutional end-users who
ultimately consume the natural gas. Natural gas purchase contracts define the
terms and conditions unique to each of these sales. The price received for
natural gas sold on the spot market may vary daily, reflecting changing market
conditions. The deliverability and price of natural gas are subject to both
governmental regulation and supply and demand forces. During the past several
years, regional surpluses and shortages of natural gas have occurred, resulting
in wide fluctuations in prices. Prices received by the Company for natural gas
production during the years ended December 31, 2001 and 2000 varied from $1.58
to $12.93 per Mcf and from $1.31 to $11.26 per Mcf, respectively.
The lengths of the contracts vary widely. During the year ended December 31,
2001, 60% of the Company's natural gas was sold under long-term contracts, with
40% of its natural gas sold under short-term or spot market contracts.
Substantially all of Canaan's natural gas is sold under contracts providing for
market sensitive terms.
Crude Oil. Oil produced from Canaan's properties is sold at the prevailing
field price to one or more of a number of unaffiliated purchasers in the area.
Generally, purchase contracts for the sale of oil are cancelable on 30-days
notice. The price paid by these purchasers is generally an established, or
"posted," price that is offered to all producers. For the years ended December
31, 2001 and 2000, the price for the Company's oil ranged from $15.99 to $31.00
per Bbl and from $16.25 to $36.75 per Bbl, respectively. During the last
several years, prices paid for crude oil have fluctuated substantially. Future
oil prices are difficult to predict due to the impact of worldwide economic
trends, supply and demand variables and such non-economic factors as the impact
of political considerations on OPEC pricing policies and the possibility of
supply interruptions. Oil production comprised approximately 14% of Canaan's
total oil and natural gas production calculated on an equivalent Mcf basis for
2001. Therefore, an increase or decrease in oil prices has a minimal effect on
Canaan's revenues when compared to the effect of changes in the price of
natural gas.
3
Principal Customers
During the year ended December 31, 2001, sales of oil and natural gas to one
purchaser, Transok, LLC, accounted for 13% of the Company's total oil and
natural gas revenues.
During the year ended December 31, 2000, there were no purchasers accounting
for 10% or more of the Company's total oil and natural gas sales.
During the year ended December 31, 1999, sales of oil and natural gas to
three purchasers, Conoco, Inc., Texaco Exploration & Production, Inc. and
Twister Gas Services, LLC, accounted for 11%, 10% and 10%, respectively, of the
Company's total oil and natural gas revenues.
Canaan does not believe that the loss of any of its customers would have a
material adverse effect on the results of operations of the Company.
Competition
The oil and natural gas industry is extremely competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and natural gas reserves. Canaan's competitive position
depends on its geological, geophysical and engineering expertise, financial
resources, ability to develop properties and ability to select, acquire and
develop proved reserves. Canaan competes with a substantial number of other
companies having larger technical staffs and greater financial and operational
resources. Many such companies not only engage in the acquisition, exploration,
development and production of oil and natural gas reserves, but also carry on
refining operations, generate electricity and market refined products. Canaan
also competes with major and independent oil and natural gas companies in the
marketing and sale of oil and natural gas to transporters, distributors and end
users. The oil and natural gas industry competes with other industries
supplying energy and fuel to industrial, commercial and individual consumers.
Canaan 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. Such equipment may be in short supply from time to time. Finally,
companies not previously investing in oil and natural gas may choose to acquire
reserves to establish a firm supply or simply as an investment. Such companies
also provide competition for Canaan.
Canaan's business is affected not only by such competition, but also by
general economic developments, governmental regulations and other factors that
affect its ability to market oil and natural gas production. Canaan's financial
position and resources may also adversely affect its competitive position. Lack
of available funds or financing alternatives will prevent Canaan from executing
its operating strategy and from deriving the expected benefits therefrom.
Regulation
Exploration and Production. The exploration, production and sale of oil and
natural gas are subject to various types of local, state and federal laws and
regulations. These laws and regulations govern a wide range of matters,
including the drilling and spacing of wells, allowable rates of production,
restoration of surface areas, plugging and abandonment of wells and
requirements for the operation of wells. These regulations may adversely affect
the rate at which wells produce oil and natural gas.
Environmental Matters. The discharge of oil, natural gas or other
pollutants into the air, soil or water may give rise to liabilities to the
government and third parties and may require Canaan to incur costs to remedy
discharges. Natural gas, oil or other pollutants, including salt-water brine,
may be discharged in many ways, including from a well or drilling equipment at
a drill site, leakage from pipelines or other gathering and transportation
facilities, leakage from storage tanks and sudden discharges from damage or
explosion at natural gas facilities of oil and natural gas wells. Discharged
hydrocarbons may migrate through soil to water supplies or adjoining property,
giving rise to additional liabilities.
4
A variety of federal and state laws and regulations govern the environmental
aspects of natural gas and oil production, transportation and processing and
may, in addition to other laws, impose liability in the event of discharges,
whether or not accidental, failure to notify the proper authorities of a
discharge and other noncompliance with those laws. Compliance with such laws
and regulations may increase the cost of oil and natural gas exploration,
development and production, although Canaan does not currently anticipate that
compliance will have a material adverse effect on capital expenditures or
earnings of Canaan. Failure to comply with the requirements of the applicable
laws and regulations could subject Canaan to substantial civil and/or criminal
penalties and to the temporary or permanent curtailment or cessation of all or
a portion of our operations.
Canaan does not believe that its environmental risks will be materially
different from those of comparable companies in the oil and natural gas
industry. Canaan believes its present activities substantially comply, in all
material respects, with existing environmental laws and regulations.
Nevertheless, Canaan cannot be certain that environmental laws will not result
in a curtailment of production or material increase in the cost of production,
development or exploration or otherwise adversely affect Canaan's financial
condition and results of operations. Although Canaan maintains liability
insurance coverage for liabilities from pollution, environmental risks
generally are not fully insurable.
Marketing and Transportation. The interstate transportation and sale for
resale of natural gas is regulated by the Federal Energy Regulatory Commission
under the Natural Gas Act of 1938. The sale and transportation of natural gas
also is subject to regulation by various state agencies. The Natural Gas
Wellhead Decontrol Act of 1989 eliminated all natural gas price regulation
effective January 1, 1993. In addition, FERC recently has proposed several
rules and orders concerning transportation and marketing of natural gas. The
impact of these rules and other regulatory developments on Canaan cannot be
predicted.
In 1992, FERC finalized Order 636, and also has promulgated regulations
pertaining to the restructuring of the interstate transportation of natural
gas. Pipelines serving this function have since been required to "unbundle" the
various components of their service offerings, which include gathering,
transportation, storage and balancing services. In their current capacity,
pipeline companies must provide their customers with only the specific service
desired, on a non-discriminatory basis. Although Canaan is not an interstate
pipeline, Canaan believes the changes brought about by Order 636 have increased
competition in the marketplace, resulting in greater market volatility.
Various rules, regulations and orders, as well as statutory provisions, may
affect the price of natural gas production and the transportation and marketing
of natural gas.
Operating Hazards and Uninsured Risks
The Company's operations are subject to the usual hazards incident to the
exploration for and production of oil and natural gas, such as blowouts,
cratering, abnormally pressured formations, explosions, uncontrollable flows of
oil, natural gas or well fluids into the environment, fires, pollution,
releases of toxic natural gas and other environmental hazards and risks. These
hazards can result in substantial losses to the Company due to personal injury
and loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damage or suspension of operations.
The Company maintains insurance of various types to cover its operations. In
addition, the Company maintains operator's extra expense coverage which applies
to the care, custody and control of drilling wells. The Company's insurance
does not cover every potential risk associated with the drilling and production
of oil and natural gas. In particular, coverage is not obtainable for certain
types of environmental hazards. The occurrence of a significant adverse event,
the risks of which are not fully covered by insurance, could have a material
adverse effect on the Company's financial condition and results of operations.
Moreover, no assurance can be given that the Company will be able to maintain
adequate insurance in the future at rates it considers reasonable.
5
The Company maintains levels of insurance customary in the industry to limit
its financial exposure in the event of a substantial environmental claim
resulting from sudden and accidental discharges; however, 100% coverage is not
maintained. Unreimbursed expenditures in 2001, 2000 and 1999 were immaterial.
Employees
At March 26, 2002, Canaan had 48 full-time employees, eight of whom work out
of various field offices. The Company also employees four contract employees
providing geological, land, investor relations and clerical services. None of
these employees is represented by a union and Canaan believes that it maintains
good relations with its employees.
ITEM 2. Properties
Office Facilities
Canaan currently leases for its corporate headquarters 24,652 square feet on
the 10/th/ floor in One Leadership Square located in the downtown area of
Oklahoma City. These facilities are adequate for our current operations.
The Company also leased 1,440 square feet of temporary office space on the
third floor in One Leadership Square from October 1, 2001, until February 28,
2002.
Oil and Natural Gas Properties
General
The Company's properties are primarily in the Mid-Continent area, with a
preference for natural gas producing properties. Within the Mid-Continent area,
the core areas are the Deep Anadarko Basin, the Anadarko Shelf, the Arkoma
Basin, and South-Central Oklahoma. Development and exploitation of acreage
acquired through a joint venture in the South Texas onshore region, as
discussed below, are expected to result in another core area for the Company.
The remaining properties are located in various states including Colorado,
Kansas, New Mexico, Nebraska, Texas and Wyoming. As of December 31, 2001, the
Company owned working interests in 949 gross wells, 190 of which it operates.
The Company also owned interests in 59 wells in which the Company has a revenue
interest other than as a working interest owner. As of December 31, 2001, the
Company owned working interests in 270 gross (69.2 net) producing oil wells and
662 (125.1 net) producing natural gas wells, as well as 8 gross (2.4 net) oil
and 9 gross (3.1 net) natural gas wells that were shut-in. A well is
categorized under state reporting regulations as an oil well or a natural gas
well based upon the ratio of natural gas to oil production when it first
commenced production, and such designation may not be indicative of current
production.
Net average daily production during 2001 was 495 Bbls of oil and 18 MMcf of
natural gas, or 21 MMcfe of equivalent production. Canaan participated in the
drilling of 58 gross development oil and natural gas wells, of which 56, or
97%, were successfully completed during 2001. The Company has allocated $10
million for its 2002 drilling program, subject to revision based upon results,
oil and natural gas prices and other factors. Approximately $4 million of this
total has been allocated to drilling in South Texas, a new core area for the
Company, and $6 million has been allocated to the historically successful
Mid-Continent area. During 2002, the Company expects to participate in the
drilling of about 22 gross wells (7.0 net) wells. The wells in the
Mid-Continent area will be a combination of proved undeveloped locations and
higher risk wells in existing field areas. The wells outside of the
Mid-Continent area will be higher risk wells identified using 3-D seismic data
in and around existing field areas.
6
Information by Area
The following table sets forth certain information regarding the four
Mid-Continent core areas and the other states as of December 31, 2001:
Deep South-
Anadarko Anadarko Central Other Total
Property Data Basin Arkoma Shelf Oklahoma States Company
------------- -------- ------- -------- -------- ------ -------
Total Proved Reserves (MMcfe)............. 51,643 16,560 11,764 12,223 2,698 94,888
Percentage of Total Proved Reserves....... 54.4% 17.5% 12.4% 12.9% 2.8% 100.0%
Total Proved PV-10 (pretax)($M)........... $30,792 $13,146 $ 8,195 $ 9,156 $1,417 $62,706
Percentage of Total Proved PV-10(1)....... 49.1% 21.0% 13.1% 14.6% 2.2% 100.0%
Gross Producing Wells..................... 353 98 196 154 131 932
Net Producing Wells....................... 45.0 27.6 61.4 38.8 21.4 194.2
Gross Operated Producing Wells............ 10 23 113 36 -- 182
Current Daily Net Production (MMcfe)(2)... 8.7 4.4 3.2 3.2 1.3 20.8
Percentage of Current Daily Net
Production(1)........................... 42.0% 21.2% 15.6% 15.1% 6.1% 100.0%
Number of Gross Proved Undeveloped
Locations............................... 55 3 3 4 -- 65
Number of Net Proved Undeveloped Locations 12.0 1.7 0.7 1.3 -- 15.7
Percentage of Net Proved Undeveloped
Locations............................... 76.4% 0.8% 4.5% 8.3% -- 100.0%
Net Proved Undeveloped Reserves (MMcfe)... 17,849 2,522 801 914 -- 22,086
Percentage of Net Proved Undeveloped
Reserves................................ 80.8% 11.4% 3.7% 4.1% -- 100.0%
Estimated Future Development Cost ($M).... $16,122 $ 1,080 $ 626 $ 1,085 -- $18,913
- --------
(1) Present value of estimated future net cash flows before income taxes
discounted at 10%. The Standardized Measure of Discounted Future Net Cash
Flows was $49,709,000.
(2) Current Daily Net Production is based on average daily production for the
month of January 2002.
The Mid-Continent core areas' proved reserves of 92.2 Bcfe represented 97%
of the Company's total proved reserves as of December 31, 2001. Production was
94% of the Company's average daily net production for January 2002. All of the
proved undeveloped drilling locations are in the Mid-Continent area.
The Deep Anadarko Basin properties had proved reserves of 51.6 Bcfe,
representing 54% of the Company's total proved reserves as of December 31,
2001. Production was 42% of the Company's average daily net production for
January 2002. The Company's 55 proved undeveloped locations in this area
represent 81% of the Company's proved undeveloped reserves as of December 31,
2001. Production in this area is primarily natural gas and condensate from
Pennsylvanian age reservoirs that include the Red Fork, Skinner, Atoka and
Morrow sandstones at depths of 10,000 to 14,000 feet. This area has had
extensive increased density drilling activity and the Company has identified
numerous additional increased density drilling locations. The majority of the
2002 planned drilling activity in the Mid-Continent region will be in this area.
The Arkoma Basin properties in eastern Oklahoma and western Arkansas had
proved reserves of 16.6 Bcfe, representing 18% of the Company's total proved
reserves as of December 31, 2001. Production from this area was 21% of the
Company's average daily net production for January 2002. The three proved
undeveloped locations in this area represent 11% of the Company's proved
undeveloped reserves as of December 31, 2001. Production in this area is
natural gas from numerous Pennsylvanian age sandstone reservoirs and the
Devonian/ Silurian age Hunton reservoir at depths of 2,000 to 9,000 feet. The
two primary fields in this area are the Company operated Massard Field in
Arkansas and the non-operated Red Oak-Norris Field in Oklahoma. All currently
identified proved undeveloped locations are in the Massard Field. For 2002, the
Company plans to drill at least two wells in the Massard Field.
7
The Anadarko Shelf properties located in north central and northwestern
Oklahoma had proved reserves of 11.8 Bcfe as of December 31, 2001. This
represented 12% of the Company's total proved reserves as of December 31, 2001.
Production from this area was 16% of the Company's average daily net production
for January 2002. The properties in this area account for 113 of the 190
Company operated wells. Production in this area is natural gas and oil from a
variety of reservoirs ranging from the Permian Chase Group down to the
Devonian/Silurian Hunton Formation. Producing depths in the area are generally
3,000 to 9,000 feet.
The South-Central Oklahoma properties proved reserves of 12.2 Bcfe
represented 13% of the Company's total proved reserves as of December 31, 2001.
Production from this area was 15% of the Company's average daily net production
for January 2002. The four proved undeveloped locations in this area
represented 4% of the proved undeveloped reserves as of December 31, 2001.
Production in this area is natural gas and oil from numerous reservoirs ranging
in age from Pennsylvanian to Ordovician. The Company plans to participate in
the drilling of several wells in this area in 2002, most of which will be
proposed by other operators.
During 2001, Canaan entered into a joint venture with a successful operator
in the South Texas onshore region. The opportunities acquired through the joint
venture included 90 miles of 3-D seismic data and technology currently being
used to identify high impact drilling prospects with the ultimate goal of
establishing another core area for the Company. The Company's reserves
attributable to the South Texas onshore area, as in the Mid-Continent region,
are primarily longer producing, natural gas reserves. The Company expects to
begin participating in this new core area in mid-2002.
Acquisition Activity
In December 2001, the Company acquired from Vintage Petroleum, Inc. for $2.1
million, five operated, producing wells in Custer County, Oklahoma. This
strategic Mid-Continent acquisition in our Deep Anadarko Basin area also
includes the upside potential of two proved undeveloped and two nonproved
locations. Netherland, Sewell & Associates, Inc. ("NSAI"), independent
reservoir engineers, estimated proved reserves of 3.0 Bcfe as of December 31,
2001 attributable to this acquisition reflecting an attractive acquisition
price of $0.70 per Mcfe.
Oil and Natural Gas Reserves
The following table sets forth certain information on the total proved
natural gas and oil reserves and the PV-10 of estimated future net revenues of
total proved natural gas and oil reserves as of December 31, 2001 based on the
report of NSAI. The calculations used by NSAI in preparation of such report
were prepared using geological and engineering methods generally accepted by
the petroleum industry and in accordance with SEC guidelines.
As of December 31, 2001
------------------------------------------
Natural
Natural Gas
Gas Oil Equivalents PV-10(1)
------- ------- ----------- --------------
(MMcf) (MBbls) (MMcfe) (in thousands)
Proved developed reserves.. 65,453 1,225 72,802 $57,863
Proved undeveloped reserves 21,273 135 22,086 4,843
------ ----- ------ -------
Total proved reserves...... 86,726 1,360 94,888 $62,706
====== ===== ====== =======
- --------
(1) Present value of estimated future net cash flows before income taxes
discounted at 10%. The standardized measure of discounted future net cash
flows was $49,709,000.
These reserve estimates were calculated by using methods prescribed by the
SEC, including year-end prices of $2.58 per Mcf for natural gas and $18.48 per
Bbl for oil.
There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and their values, including many factors beyond
our control. The reserve data included in this document represents
8
only estimates. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data, the precision of the engineering and geological
interpretation and judgment. As a result, estimates of different engineers
often vary. The estimates of reserves, future cash flows and present value are
based on various assumptions, including those prescribed by the SEC, and are
inherently imprecise. Actual future production, cash flows, taxes, development
expenditures, operating expenses and quantities of recoverable oil and natural
gas reserves may vary substantially from our estimates. Also, the use of a 10%
discount factor for reporting purposes may not necessarily represent the most
appropriate discount factor, given actual interest rates and risks to which our
business or the oil and natural gas industry in general are subject.
Quantities of proved reserves are estimated based on economic conditions,
including oil and natural gas prices in existence at the date of assessment.
Our reserves and future cash flows may be subject to revisions, based upon
changes in economic conditions, including oil and natural gas prices, as well
as due to production results, results of future development, operating and
development costs and other factors. Downward revisions of our reserves could
have an adverse effect on our financial condition and operating results.
Canaan has not filed any reports with other federal agencies which contain
an estimate of its net proved oil and natural gas reserves.
Cost Incurred and Drilling Results
The following table shows information regarding the costs incurred by Canaan
from acquisition and development activities during the periods indicated.
Year ended December 31,
--------------------------------
2001 2000 1999
----------- ----------- --------
Property acquisition costs $ 5,669,532 $51,857,378 $ 6,094
Development costs......... 15,982,657 2,135,315 894,028
----------- ----------- --------
Total..................... $21,652,189 $53,992,693 $900,122
=========== =========== ========
Canaan has acquired or drilled or participated in the drilling of wells as
set out in the table below for the periods indicated. Canaan has not
participated in any exploratory drilling.
Year ended December 31,
-------------------------------
2001 2000 1999
---------- ---------- ---------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ---
Acquired wells:
Natural gas.............. 6 1.6 287 52.2 2 0.4
Oil...................... 1 0.1 83 18.4 3 0.3
Dry...................... -- -- -- -- -- --
--- ---- --- ---- --- ---
Total.................... 7 1.7 370 70.6 5 0.7
=== ==== === ==== === ===
Development well drilling:
Natural gas.............. 47 7.0 4 0.2 2 0.1
Oil...................... 9 3.0 2 0.9 -- --
Dry...................... 2 0.5 -- -- 2 0.2
--- ---- --- ---- --- ---
Total.................... 58 10.5 6 1.1 4 0.3
=== ==== === ==== === ===
Present Activities
As of December 31, 2001, Canaan was involved in the drilling, testing or
completing of four gross (0.6 net) development wells.
9
Acreage
The following table shows the developed and undeveloped oil and natural gas
lease and mineral acreage as of December 31, 2001 owned by Canaan. Excluded is
acreage in which an interest is limited to royalty, overriding royalty and
other similar interests.
Developed Undeveloped
-------------- -------------
Gross Net Gross Net
------- ------ ------ ------
Oklahoma
Deep Anadarko......... 173,991 24,003 13,139 5,028
Anadarko Shelf........ 43,995 10,977 9,276 7,087
Arkoma................ 20,000 4,633 6,954 871
South-Central Oklahoma 21,173 4,795 5,124 1,881
Texas.................. 6,607 2,063 11,341 4,253
Other States........... 54,050 12,020 -- --
------- ------ ------ ------
Total............... 319,816 58,491 45,834 19,120
======= ====== ====== ======
Productive Well Summary
The following table shows the ownership of Canaan in productive wells at
December 31, 2001. Gross oil and natural gas wells include 11 wells with
multiple completions. Wells with multiple completions are counted only once for
purposes of the following table.
Productive
Wells
-----------
Gross Net
----- -----
Natural gas 711 125.1
Oil........ 275 69.1
--- -----
Total... 986 194.2
=== =====
Title to Properties
Substantially all of Canaan's property interests are held pursuant to leases
from third parties. Title to properties is subject to royalty, overriding
royalty, carried, net profits, working and other similar interests and
contractual arrangements customary in the oil and natural gas industry, liens
incident to operating agreements, liens relating to amounts owed to the
operator, liens for current taxes not yet due and other encumbrances. The
Company believes that such burdens neither materially detract from the value of
such properties nor from the respective interests therein, nor materially
interfere with their use in the operation of the business. Substantially all of
the Company's oil and natural gas properties are mortgaged to secure borrowings
under the Company's bank credit facility. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Capital
Expenditures, Capital Resources and Liquidity."
As is customary in the industry in the case of undeveloped properties,
little investigation of record title is made at the time of acquisition (other
than a preliminary review of local records). Investigations, including a title
opinion of local counsel, are generally made prior to the consummation of an
acquisition of a producing property and before commencement of drilling
operations.
DEFINITIONS
When the following words are used in the text of this document, they have
the following meaning:
"Average Sales Price" means total revenues from the sale of oil or natural
gas or on a per Mcfe basis for the applicable period divided by the units of
production for the applicable period.
10
"Bbl" means one stock tank barrel, or 42 U.S. gallons liquid volume, used in
this document in reference to oil or other liquid hydrocarbons.
"Bcf" means billion cubic feet.
"Bcfe" means billion cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
"Btu" means British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
"Bbtu" means billion Btus.
"Capital Expenditures" means costs associated with exploratory and
development drilling, including exploratory dry holes; leasehold acquisitions;
seismic data acquisitions; geological, geophysical and land-related overhead
expenditures; delay rentals; producing property acquisitions; and other
miscellaneous capital expenditures.
"Completion Costs" means as to any well, all those costs incurred after the
decision to complete the well as a producing well. Generally, these costs
include all costs, liabilities and expenses, whether tangible or intangible,
necessary to complete a well and bring it into production, including
installation of service equipment, tanks and other materials necessary to
enable the well to deliver production.
"Developed Acreage" means the number of acres which are allocated or
assignable to producing wells or wells capable of production.
"Development Location" means a location on which a development well can be
drilled.
"Development Well" means a well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive in an attempt to recover proved undeveloped reserves.
"Drilling Unit" means an area specified by governmental regulations or
orders or by voluntary agreement for the drilling of a well to a specified
formation or formations which may combine several smaller tracts or subdivides
a large tract, and within which there is usually some right to share in
production or expense by agreement or by operation of law.
"Dry Hole" means a well found to be incapable of producing either oil or
natural gas in sufficient quantities to justify completion as an oil or natural
gas well.
"EBITDA" is defined as earnings or loss before interest, income taxes,
depreciation and amortization and impairment. EBITDA is a financial measure
commonly used in the oil and natural gas industry as an indicator of a
Company's ability to service and incur debt. However, EBITDA should not be
considered in isolation or as a substitute for net income, cash flows provided
by operating activities or other data prepared in accordance with generally
accepted accounting principles, or as a measure of a company's profitability or
liquidity. EBITDA is a component of one of the debt covenants contained in the
Company's credit facility agreement. EBITDA measures as presented may not be
comparable to other similarly titled measures of other companies.
"Estimated Future Net Revenues" means revenues from production of oil and
natural gas, net of all production-related taxes, lease operating expenses,
capital costs and abandonment costs.
"Exploratory Well" means a well drilled to find and produce oil or natural
gas in an unproved area, to find a new reservoir in a field previously found to
be productive of oil or natural gas in another reservoir, or to extend a known
reservoir.
11
"Future Development Cost" means the amount of estimated future capital
expenditures related to the development of proved undeveloped properties.
"Gross Acre" means an acre in which a working interest is owned.
"Gross Well" means a well in which a working interest is owned.
"Infill Drilling" means drilling for the development and production of
proved undeveloped reserves that lie within an area bounded by producing wells.
"Lease Operating Expense" means all direct costs associated with and
necessary to operate a producing property.
"Lifting Costs" means the expenses of lifting oil and natural gas from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
"MBbls" means thousand barrels.
"MBtu" means thousand Btus.
"Mcf" means thousand cubic feet.
"Mcfe" means thousand cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
"MMBbls" means million barrels.
"MMBtu" means million Btus.
"MMcf" means million cubic feet.
"MMcfe" means million cubic feet of natural gas equivalent, determined using
the ratio of one Bbl of oil or condensate to six Mcf of natural gas.
"Natural Gas Liquids" means liquid hydrocarbons that have been extracted
from natural gas, e.g., ethane, propane, butane and natural gasoline.
"Net Acres or Net Wells" means the sum of the fractional working interests
owned in gross acres or gross wells.
"Oil and Natural Gas Lease" means an agreement whereby the grantee receives
for a period of time of the full or partial interest in oil and natural gas
properties, oil and natural gas mineral rights, fee rights or other rights of
the grantor granting the grantee the right to drill for, produce and sell oil
and natural gas upon payment of rentals, bonuses and/or royalties. Oil and
Natural gas Leases are generally acquired from private landowners and federal
and state governments.
"Overriding Royalty Interest" means an interest in an oil and natural gas
property entitling the owner to a share of oil and natural gas production free
of well or production costs.
"PV-10", when used with respect to oil and natural gas reserves, means the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production, future development costs and future
abandonment costs, using prices and costs in effect as of the date of the
report or estimate, without giving effect to non-property related expenses such
as income taxes, general and administrative expenses and
12
debt service or to depreciation, depletion and amortization, discounted using
an annual discount rate of 10%. PV-10 is not the same as the "Standard Measure
of Discounted Future Net Cash Flows" as prescribed by Statement of Financial
Accounting Standards No. 69 promulgated by the Financial Accounting Standards
Board because it does not take into consideration future income taxes.
"Productive Well" means a well that is producing oil or natural gas or that
is capable of production.
"Proved Developed Reserves" means proved reserves that are expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and natural gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery are included as proved
developed reserves only after testing by pilot project or after the operation
of an installed program as confirmed through production response that increased
recovery will be achieved.
"Proved Reserves" means the estimated quantities of crude oil, natural gas
and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions; i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
"Proved Undeveloped Reserves" means proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances can estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid injection or
other improved recovery techniques are contemplated, unless such techniques
have been proved effective by actual tests in the area and in the same
reservoir.
"Recompletion" means the completion for production of an existing well bore
in a formation different from that in which the well has previously been
completed.
"Royalty Interest" means an interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas production or the
proceeds of the sale, free of the costs of production.
"3-D Seismic" means the method by which a three dimensional image of the
earth's substance is created through the interpretation of aerially collected
seismic data. 3-D surveys allow for a more detailed understanding of the
subsurface than do conventional surveys and contribute significantly to field
appraisal, development and production.
"Undeveloped Acreage" means lease acreage 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.
"Working Interest" means the operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
ITEM 3. Legal Proceedings
The Company expects to be involved from time to time in various legal and
administrative proceedings and threatened legal and administrative proceedings
incidental to the ordinary course of its business. As of December 31, 2001, we
were not involved in any litigation that could have a material adverse effect
on Canaan's business, financial condition, results of operations or cash flows.
ITEM 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of the security holders during the
fourth quarter of fiscal year 2001.
13
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's common stock commenced trading on the NASDAQ National Market
System under the symbol "KNAN" on October 26, 2000. Because there is a
relatively small public float and limited trading in Canaan's common stock, the
sale of a substantial number of shares in a short period of time may adversely
affect the market price. The following table sets forth the high and low
closing sales price for the periods indicated as quoted by NASDAQ.
Quarter ended High Low
------------- ------- ------
2000
December 31....................... $15.000 $8.875
2001
March 31.......................... 11.375 8.000
June 30........................... 13.980 8.810
September 30...................... 12.950 7.050
December 31....................... 11.000 6.950
2002
March 31 (through March 26, 2002). 12.750 9.150
As of March 26, 2002, there were 322 stockholders of record.
Dividends
Canaan has not paid cash dividends on its common stock and does not expect
to pay any cash dividends in the foreseeable future. It intends to retain its
earnings to provide funds for operations and expansion of its business.
Moreover, pursuant to the terms of the Company's credit facility, the Company
is prohibited from declaring or paying any cash dividends on its common stock.
Canaan's future dividend policy is subject to the discretion of the board of
directors and will depend upon a number of factors, including future earnings,
debt service, capital requirements, restrictions contained in our credit
facility, business conditions, the Company's financial condition and other
factors that the board of directors deems relevant.
14
ITEM 6. Selected Financial Data
The following table presents a summary of selected financial and operating
data with respect to the Company as of and for each of the five years in the
period ended December 31, 2001, as restated to give effect to the 2000
reorganization of interests under common control in a manner similar to a
pooling of interests between the Company, the Partnerships and the General
Partners as described in Note 1 of Notes to Consolidated Financial Statements.
The financial data was derived from the audited consolidated financial
statements of the Company. This information is not necessarily indicative of
the Company's future performance. The financial data set forth below should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Consolidated Financial Statements
and the notes thereto of the Company.
Selected Financial Data
Year ended December 31,
----------------------------------------------------------------
2001 2000(1) 1999 1998 1997
------------ ----------- ----------- ----------- -----------
Operations Data:
Revenues:
Oil and natural gas sales...................... $ 28,381,315 $17,991,577 $10,915,499 $ 9,518,568 $11,011,903
Expenses:
Lease operating................................ 4,536,071 2,088,854 1,564,587 1,529,919 1,422,079
Production taxes............................... 1,852,158 1,458,425 835,198 788,471 781,767
General and administrative costs............... 4,912,178 2,858,097 1,886,324 1,795,391 1,938,394
Merger costs................................... -- 1,350,686 -- -- --
Depreciation and amortization.................. 7,352,018 2,891,344 2,594,206 3,220,543 2,643,641
Reduction in carrying value of oil and natural
gas properties................................ 21,748,000 -- -- 1,881,000 --
Interest....................................... 2,674,652 1,259,628 497,182 203,604 177,830
------------ ----------- ----------- ----------- -----------
Total expenses.............................. 43,075,077 11,907,034 7,377,497 9,418,928 6,963,711
------------ ----------- ----------- ----------- -----------
Other income, principally interest............... 367,296 162,966 131,895 323,989 674,101
------------ ----------- ----------- ----------- -----------
Earnings (loss) before income taxes.............. (14,326,466) 6,247,509 3,669,897 423,629 4,722,293
Income taxes..................................... (5,437,000) 4,228,000 26,000 34,000 57,000
------------ ----------- ----------- ----------- -----------
Net earnings (loss).............................. $ (8,889,466) $ 2,019,509 $ 3,643,897 $ 389,629 $ 4,665,293
============ =========== =========== =========== ===========
Earnings (loss) per average common share
outstanding--basic.............................. $ (1.83) $ 0.52 $ 1.01 $ 0.11 $ 1.31
============ =========== =========== =========== ===========
Earnings (loss) per average common share
outstanding--diluted............................ $ (1.83) $ 0.52 $ 1.01 $ 0.11 $ 1.31
============ =========== =========== =========== ===========
Weighted average common shares outstanding--
basic........................................... 4,868,075 3,872,566 3,621,219 3,621,219 3,570,220
============ =========== =========== =========== ===========
Weighted average common shares outstanding--
diluted......................................... 4,868,075 3,878,482 3,621,219 3,621,219 3,570,220
============ =========== =========== =========== ===========
Cash Flow and Other Data:
Net cash provided by operating activities........ $ 17,295,210 $ 7,067,580 $ 5,861,734 $ 6,383,125 $ 7,265,280
Net cash provided by (used in) investing
activities...................................... (22,757,689) 201,994 (6,893,085) (7,024,701) (4,843,968)
Net cash provided by (used in) financing
activities...................................... 1,560,772 (2,283,059) (1,413,092) (5,948,653) 2,399,071
EBITDA*.......................................... 17,448,204 10,398,481 6,761,285 5,728,776 7,543,764
Balance Sheet Data (as of period end):
Cash and cash equivalents........................ $ 2,579,843 $ 6,481,550 $ 1,495,035 $ 3,939,478 $10,529,707
Oil and natural gas properties, net.............. 66,452,075 71,211,428 20,910,796 22,125,626 20,186,922
Total assets..................................... 75,520,245 85,773,165 30,727,969 28,055,741 33,475,021
Long term debt, including current portion........ 42,264,683 33,964,683 7,112,489 2,239,088 2,239,089
Stockholders' equity............................. 20,701,986 36,330,680 21,987,952 24,243,197 30,154,671
15
Selected Operating Data
Year ended December 31,
--------------------------------------------------------------
2001 2000(1) 1999 1998 1997
----------- ------------ ----------- ----------- -----------
Natural Gas and Oil Sales:
Natural gas sales:
Wellhead pricing........................... $25,530,158 $ 16,253,202 $ 8,043,397 $ 7,289,598 $ 7,968,889
Effect of fixed-price contract settlements. (1,667,656) (1,721,810) -- -- --
----------- ------------ ----------- ----------- -----------
Total................................... $23,862,502 $ 14,531,392 $ 8,043,397 $ 7,289,598 $ 7,968,889
=========== ============ =========== =========== ===========
Oil sales:
Wellhead pricing........................... $ 4,531,855 $ 4,203,959 $ 2,722,974 $ 1,998,642 $ 2,876,609
Effect of fixed-price contract settlements. -- (850,577) -- -- --
----------- ------------ ----------- ----------- -----------
Total................................... $ 4,531,855 $ 3,353,382 $ 2,722,974 $ 1,998,642 $ 2,876,609
=========== ============ =========== =========== ===========
Production:
Natural gas production (Mcf)................. 6,561,791 4,137,499 3,717,376 3,854,164 3,209,479
Oil production (Bbls)........................ 180,624 143,095 153,624 153,712 145,621
Equivalent production (Mcfe)................. 7,645,535 4,996,069 4,639,120 4,776,436 4,083,205
Average Sales Price*:
Natural gas price (per/Mcf):
Wellhead pricing........................... $ 3.89 $ 3.93 $ 2.16 $ 1.89 $ 2.48
Effect of fixed-price contract settlements. (0.25) (0.42) -- -- --
----------- ------------ ----------- ----------- -----------
Total................................... $ 3.64 $ 3.51 $ 2.16 $ 1.89 $ 2.48
=========== ============ =========== =========== ===========
Oil price (per/Bbl):
Wellhead................................... $ 25.09 $ 29.38 $ 17.72 $ 13.00 $ 19.75
Effect of fixed-price contract settlements. -- (5.94) -- -- --
----------- ------------ ----------- ----------- -----------
Total................................... $ 25.09 $ 23.44 $ 17.72 $ 13.00 $ 19.75
=========== ============ =========== =========== ===========
Average sales price (per Mcfe):
Wellhead pricing........................... $ 3.93 $ 4.09 $ 2.32 $ 1.94 $ 2.66
Effect of fixed-price contract settlements. (0.22) (0.51) -- -- --
----------- ------------ ----------- ----------- -----------
Total................................... $ 3.71 $ 3.58 $ 2.32 $ 1.94 $ 2.66
=========== ============ =========== =========== ===========
Operating Costs (per Mcfe):
Lease operating expense...................... $ 0.59 $ 0.42 $ 0.34 $ 0.32 $ 0.35
Production taxes............................. 0.24 0.29 0.18 0.17 0.19
General and administrative expense........... 0.64 0.57 0.41 0.38 0.47
Depreciation and amortization--Oil & natural
gas properties.............................. 0.95 0.57 0.56 0.67 0.64
Estimated Net Proved Reserves
(as of period end):
Natural gas (Mcf)............................ 86,726,000 94,627,000 37,546,000 36,152,000 32,218,000
Oil (Bbls)................................... 1,360,000 1,970,000 1,443,000 995,000 956,000
Total (Mcfe)................................. 94,888,000 106,445,000 46,204,000 42,122,000 37,954,000
- --------
* See Definitions
(1) The Company acquired Indian and CSI in October 2000. See Note 3 of Notes to
Consolidated Financial Statements.
16
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following discussion is intended to assist in an understanding of
Canaan's financial position as of December 31, 2001 and 2000, and its results
of operations for each year in the three-year period ended December 31, 2001.
The financial statements and notes thereto included elsewhere in this document
contain additional information and should be referred to in conjunction with
this discussion.
General
Canaan is an Oklahoma corporation formerly known as Coral Reserves Group,
Ltd., organized in March 1987 for the purpose of originating, evaluating,
engineering, negotiating, closing and managing producing oil and natural gas
property acquisitions on a contract basis for several limited partnerships
sponsored by others. Since 1990, our primary activities have consisted of
acquiring, developing, producing and operating oil and natural gas properties.
From 1990 to 2000, we managed eight limited partnerships ("Partnerships") on
behalf of two affiliated managing general partners ("General Partners"). In
October 2000, we completed a business combination by which we acquired the
Partnerships, the General Partners, Canaan Securities, Inc. ("CSI"), an
unaffiliated broker-dealer and Indian Oil Company ("Indian"), an independent
oil and natural gas company headquartered in Oklahoma City, Oklahoma. We issued
4,368,815 shares of our common stock as consideration for the acquired
entities. We also paid a stock dividend of 562,368 shares to our shareholders
of record immediately prior to the transaction for the purpose of increasing
Canaan's existing shares to the amount allocated to it under the terms of the
combination transaction. We have continued and will continue the combined
businesses of the Partnerships, the General Partners and Indian in a manner
similar to the business activities of such entities prior their acquisition.
Historically, we have utilized cash flows from operations and debt to fund
our capital expenditure programs. We intend to fund future capital expenditures
through cash flows from operations, borrowings under our credit facility and
other capital market activity in the public or private securities markets. We
believe that increased cash flows attributable to the acquisitions of the
Partnerships and Indian have better positioned us to pursue many of the
prospects arising as a result of our ongoing activities.
Our acquisition of the Partnerships and the General Partners was accounted
for as a reorganization of interests under common control in a manner similar
to pooling of interests, and the acquisitions of Indian and CSI were accounted
for as purchases. Accordingly, our financial statements have been prepared as
if we had owned the Partnerships and General Partners since their inception.
Results of operations for Indian and CSI have been included in our financial
statements for the months of November and December 2000 and all of 2001.
Critical Accounting Policies
In December 2001, the Securities and Exchange Commission encouraged public
companies to include in their annual report information on critical accounting
policies. These policies have been defined as those that are very important to
the portrayal of the company's financial condition and results, and require
management's most difficult, subjective or complex judgments.
Below is information on what Canaan believes is its most critical accounting
policy.
Full Cost Ceiling Calculations. Canaan follows the full cost method of
accounting for its oil and natural gas properties. The full cost method
subjects companies to quarterly calculations of a "ceiling", or limitation on
the amount of properties that can be capitalized on the balance sheet. If
Canaan's capitalized costs are in excess of the calculated ceiling, the excess
must be written off as an expense.
Canaan's discounted present value of estimated future net revenues from its
proved oil and natural gas reserves is a major component of the ceiling
calculation, and represents the component that requires the most
17
subjective judgments. Estimates of reserves are forecasts based on engineering
data, projected future rates of production and the timing of future
expenditures. The process of estimating oil and natural gas reserves requires
substantial judgment, resulting in imprecise determinations, particularly for
new discoveries. Different reserve engineers may make different estimates of
reserve quantities based on the same data. All of Canaan's reserve estimates
are prepared by Netherland, Sewell and Associates, Inc.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. In the past three years, Canaan's annual revisions to its
reserve estimates resulted in an upward average revision of approximately 9% of
the previous year's estimate. However, there can be no assurance that
significant revisions will not be necessary in the future. If future
significant revisions are necessary that reduce previously estimated reserve
quantities, it could result in a full cost property writedown. In addition to
the impact of the estimates of proved reserves on the calculation of the
ceiling, estimates of proved reserves are also a significant component of the
calculation of the full cost pool amortization.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil and natural gas reserves that are included in the
discounted present value of the reserves do not require judgment. The ceiling
calculation dictates that prices and costs in effect as of the last day of the
period are generally held constant indefinitely. Therefore, the future net
revenues associated with the estimated proved reserves are not based on
Canaan's assessment of future prices or costs, but rather are based on such
prices and costs in effect as of the end of each quarter when the ceiling
calculation is performed. In calculating the ceiling, Canaan does not adjust
the end-of-period price by the effect of cash flow hedges in place. At December
31, 2001, Canaan had no cash flow hedges in place.
Because the ceiling calculation dictates that prices in effect as of the
last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been cyclical and, on any particular
day at the end of a quarter, can be either substantially higher or lower than
Canaan's long-term price forecast that is a barometer for true fair value.
Therefore, oil and natural gas property writedowns that result from applying
the full cost ceiling limitation, and that are caused by fluctuations in price
as opposed to reductions to the underlying quantities of reserves, should not
be viewed as absolute indicators of a reduction of the ultimate value of the
related reserves.
Canaan recorded a writedown of it's oil and gas properties as of December
31, 2001. The properties were reduced by $21.7 million. The year-end 2001
prices used to calculate the ceiling were based on an oil price of $18.48 per
barrel, and a natural gas price of $2.58 per Mcf. If oil or natural gas prices
at the end of future quarters drop below these year-end 2001 prices, or if
Canaan reduces its estimates of proved reserve quantities, further writedowns
would likely occur.
There is an acceptable alternative method for accounting for oil and gas
properties under generally accepted accounting principles which is referred to
as the "successful efforts" method of accounting. Under this method, costs
associated with unsuccessful exploratory drilling efforts are immediately
expensed and costs for successful exploratory wells and all development costs
are capitalized and amortized over the future production period on a field by
field basis. Properties are also tested at the end of each accounting period
for impairment on a field by field basis using a method similar to the
calculation of the full cost ceiling limitation. We have selected the full cost
method of accounting as opposed to the successful efforts method because we
believe it is easier to apply the principles, easier to understand the results,
and because we believe that the full-cost method fully measures the complete
costs associated with the acquisition, exploration, exploitation, and
development of oil and gas properties, particularly the capitalization of
general and administrative costs directly related to our drilling efforts.
While we have not historically drilled exploratory wells, we may do so in the
future. We consider that the costs of drilling of unsuccessful exploratory
wells would a part of our overall costs to find and develop reserves, so the
use of the full-cost method is consistent with how we would evaluate our
results.
18
Year Ended December 31, 2001 Compared with the Year Ended December 31, 2000
For the year ended December 31, 2001, we recorded a net loss of $8,889,466,
or $1.83 per share, on total revenues of $28,381,315. These results compare
with net earnings for 2000 of $2,019,509 or $.52 per share, on total revenues
of $17,991,577. In the fourth quarter of 2001, the Company recorded a
$21,748,000 pre-tax charge from applying the full cost pool ceiling test as
prescribed by the SEC for companies using the full cost method of accounting.
This charge was offset by a related $8,264,000 deferred tax benefit. Exclusive
of the net full cost pool ceiling write down charge, the Company generated net
earnings of $4,594,608 or $0.94 per share for the year ended December 31, 2001.
Revenues. Revenues from oil and natural gas sales increased by 58%, or
$10,389,738, to $28,381,315 in 2001, as compared to $17,991,577 in 2000. This
increase was the result of a 53% increase in production on a Mcfe basis,
primarily attributable to the acquisition of Indian. Natural gas production
increased 59% from 4,137,499 Mcf in 2000 to 6,561,791 Mcf in 2001. Oil
production increased 26% from 143,095 Bbls in 2000 to 180,624 Bbls in 2001. The
average price realized for natural gas increased by 4%, or $0.13 per Mcf, to
$3.64 per Mcf in 2001, as compared to $3.51 per Mcf in 2000. Hedging contract
settlements decreased our average price for natural gas by $0.25 per Mcf in
2001 and $0.42 in 2000. The average price realized for oil increased by 7%, or
$1.65 per Bbl, to $25.09 in 2001, as compared to $23.44 per Bbl in 2000.
Hedging contract settlements decreased our average price for oil by $5.94 per
Mcf in 2000. The oil hedging contract arrangements expired in December 2000;
therefore, there were no reductions to our average oil price in 2001. There
were no hedging arrangements in place at December 31, 2001.
Lease operating expense. Lease operating expense increased by 117%, or
$2,447,217, to $4,536,071 in 2001, as compared to $2,088,854 in 2000. This
increase is due primarily to the acquisition of Indian in October 2000. The
remainder of the increase is due to repairs and workovers in 2001. On a Mcfe
basis, lease operating expense increased 41% in 2001 to $0.59 per Mcfe from
$0.42 per Mcfe in 2000. This per unit increase is due primarily to higher
operating costs associated with the acquired Indian wells, and to increased
workover and repair activity.
Gross production taxes. Gross production taxes increased 27%, or $393,733
to $1,852,158 in 2001, as compared to $1,458,425 in 2000. This increase was
primarily the result of increased oil and natural gas revenues in 2001, as
previously discussed. Gross production taxes as a percentage of revenues were
7% in 2001 versus 8% in 2000. Production taxes are generally calculated based
on gross oil and natural gas revenues prior to any hedging adjustments. These
production tax rates calculated on revenues prior to any hedging adjustments
were 7% in both 2001 and 2000.
Depreciation and amortization expense. Depreciation and amortization
expense increased $4,460,674 or 154% to $7,352,018 in 2001 as compared to
$2,891,344 in 2000. Depreciation and amortization expense from oil and natural
gas properties increased 153%, or $4,365,963, to $7,228,307 in 2001 compared to
$2,862,344 in 2000, due to the acquisition of the Indian properties and the
associated increased production during 2001. Depreciation and amortization
expense per equivalent Mcf was $0.96 for 2001 versus $0.58 for 2000. This
increase was due primarily to the purchase of the Indian properties, which were
recorded at their fair market value on the acquisition date in October 2000 and
to the reduced reserve level at the end of 2001 reflecting the reduced oil and
gas prices from 2000 levels.
General and administrative expense. General and administrative expenses
increased $2,054,081, or 72%, to $4,912,178 in 2001 as compared to $2,858,097
for 2000. The principal components of the increase were salaries and
professional fees, which increased 79%, or $1,711,959 from $2,168,633 in 2000
to $3,880,592 in 2001. General and administrative expenses per Mcfe were $0.64
in 2001 as compared to $0.57 in 2000. We closed the acquisitions of the
Partnerships, Indian and CSI on October 23, 2000, and with the concurrent
registration of our common stock, began operation as a public company.
Beginning on that date, we significantly increased our professional staff in
anticipation of future growth in both drilling and acquisition activities.
19
Additionally, we began to incur expenses related to our operation as a public
company that had not been incurred prior to October of 2000. We believe our
general and administrative expense per Mcfe will decline as we increase
production in future periods.
Interest expense. Interest expense increased $1,415,024, or 112%, from
$1,259,628 in 2000 to $2,674,652 in 2001. Average bank debt outstanding for
2001 was $34,656,350 as compared to $20,538,586 for 2000. Weighted average
interest rates for 2001 decreased to 7.52% for 2001 as compared to 9.23% for
2000.
Income taxes. Income tax expense decreased $9,665,000 from a $4,228,000
provision in 2000 to a $5,437,000 benefit in 2001. In 2000, we recorded a
$3,387,000 charge to deferred taxes, relating to the difference in the tax and
financial bases of the oil and gas properties added through the acquisition of
the Partnerships. This one-time charge was partially offset by the tax benefit
of pre-acquisition Partnership income not subject to tax, which amounted to
$1,695,000. Excluding net effect of these two one-time items in 2000, our
effective tax rates were 38% in 2001 and 41% in 2000. We believe that we will
utilize the net operating loss carryforwards prior to their expiration.
Year Ended December 31, 2000 Compared with the Year Ended December 31, 1999
For the year ended December 31, 2000, we recorded earnings of $2,019,509, or
$0.52 per share, on total revenues of $17,991,577. These results compare with
earnings for 1999 of $3,643,897, or $1.01 per share, on total revenues of
$10,915,499. This 45% decrease in earnings was primarily due to one-time
charges relating to the acquisitions of the Partnerships related to recognition
of deferred income taxes and transaction costs, as more fully described below.
Net earnings excluding the aforementioned items were $4.7 million, or $1.22 per
share, for the year ended December 31, 2000, which was 135% higher than
reported earnings per share.
Revenues. Revenues from oil and natural gas sales increased by 65%, or
$7,076,078, to $17,991,577 in 2000, as compared to $10,915,499 in 1999. This
increase was the result of higher natural gas production, primarily
attributable to the acquisition of Indian, and to an increase in average oil
and gas prices received during 2000. Natural gas production increased 11% from
3,717,376 Mcf in 1999 to 4,137,499 Mcf in 2000. Oil production declined 7% from
153,624 Bbls in 1999 to 143,095 Bbls in 2000. The average price realized for
natural gas increased by 62%, or $1.35 per Mcf, to $3.51 per Mcf in 2000, as
compared to $2.16 per Mcf in 1999. Hedging contract settlements decreased our
average price for natural gas by $0.42 per Mcf in 2000. The average price
realized for oil increased by 32%, or $5.72 per Bbl, to $23.44 in 2000, as
compared to $17.72 per Bbl in 1999. Hedging contract settlements decreased our
average price for oil by $5.94 per Bbl in 2000.
Lease operating expense. Lease operating expense increased by 34%, or
$524,267, to $2,088,854 in 2000, as compared to $1,564,587 in 1999. The lease
operating expense attributable to the acquired Indian properties accounted for
$371,216, or 71% of the 2000 increase. On an Mcfe basis, lease operating
expense increased 24% in 2000 to $0.42 per Mcfe from $0.34 per Mcfe in 1999.
Gross production taxes. Gross production taxes increased 75%, or $623,227,
to $1,458,425 in 2000, as compared to $835,198 in 1999. This increase was
primarily the result of increased oil and natural gas revenues in 2000, as
discussed previously. Gross production taxes are generally calculated based on
gross oil and natural gas revenues prior to any hedging adjustments.
Depreciation and amortization expense. Depreciation and amortization
expense increased 11%, or $297,138, to $2,891,344 in 2000, from $2,594,206 in
1999. Depreciation and amortization expense from oil and natural gas properties
increased 10%, or $268,707, to $2,850,321 in 2000 compared to $2,581,614 in
1999, due to the acquisition of the Indian properties and the associated
increased production during 2000. Depreciation and amortization expense per
equivalent Mcf was virtually unchanged at $0.57 for 2000 versus $0.56 for 1999.
Depreciation resulting from nonoil and natural gas properties increased $28,898
as a result of assets added during the year, including those through the
acquisition of Indian.
20
General and administrative expense. General and administrative expenses
increased $971,773, or 52%, to $2,858,097 in 2000 as compared to $1,886,324 for
1999. The principal components of the increase were salaries and related
expenses, which increased $826,152 in 2000, and engineering fees, which
increased $108,189 in 2000.
Merger costs. We incurred $1,350,686 in merger costs in 2000. These costs
consisted of legal, accounting and other costs incidental to the acquisition of
the Partnerships and the General Partners. As previously discussed, the
acquisitions were accounted for as a reorganization of entities under common
control in a manner similar to a pooling of interests. Accordingly, these costs
were accumulated and expensed in the fourth quarter of 2000, the period in
which the acquisitions were completed.
Interest expense. Interest expense increased $762,446, or 153%, from
$497,182 in 1999 to $1,259,628 in 2000. Our bank debt increased for the last
two months of 2000 with the assumption of $23,639,994 in additional bank debt
from the Indian acquisition. The average interest rate associated with our bank
debt increased during 2000 as compared to 1999, further contributing to the
increase in interest expense.
Income taxes. Income tax expense increased $4,202,000 to $4,228,000 in 2000
from $26,000 in 1999. The primary component of the increase was a $3,387,000
charge for deferred income taxes, relating to the difference in the tax and
financial bases of the oil and gas properties added in 2000 through the
acquisition of the Partnerships. The increase due to this one-time charge was
partially offset by the tax benefit of pre-acquisition Partnership income not
subject to tax, which amounted to $1,695,000. The remainder of the increase was
due primarily to increased taxable income and the loss of the benefit of
graduated tax rates. Our effective tax rate was 68% and 1% in 2000 and 1999,
respectively.
Capital Expenditures, Capital Resources and Liquidity
As of December 31, 2001 and 2000, we had cash balances of $2,579,843 and
$6,481,550, respectively. Working capital decreased from $9,188,802 at December
31, 2000 to $3,953,479 at December 31, 2001, due principally to lower oil and
natural gas prices as well as lower cash balances due to the funding of
drilling with the use of operating cash flows.
For 2001, net cash provided by operating activities was $17,295,210 as
compared to cash provided of $7,067,580 in 2000. This increase was primarily
the result of improved pre-tax earnings from increased production. EBITDA
increased $7,049,723 or 68%, from $10,398,481 in 2000 to $17,448,204 in 2001
also from increased production.
Net cash used by investing activities in 2001 was $22,757,689, as compared
to $201,994 cash provided from investing activities in 2000, resulting in a
$22,959,683 increase in cash used during 2001. This change was primarily the
result of the commencement of our development drilling activities in 2001 as
well as our acquisition of undeveloped acreage.
Net cash provided from financing activities increased $3,843,831 from
$2,283,059 cash used in 2000 to $1,560,772 cash provided in 2001. The increase
in cash provided from financing activities was due to net borrowings on
long-term debt of $8,300,000. This was offset by the purchase of treasury stock
for $6,739,228 during late 2001.
Capital expenditures. Our capital expenditures to date have focused
primarily on the development of oil and natural gas properties in the
Mid-Continent Region, as well as acquisitions of proved developed producing oil
and natural gas properties located in the same area.
Our projected capital expenditures for 2002 are estimated to be $10 million,
with approximately one half of our drilling budget dedicated to low-risk
projects in the Anadarko Basin area of the Mid Continent Region, an
21
area in which we have considerable expertise and have had an outstanding
success rate. We expect to deploy the balance of our drilling budget in a newly
established core area located in South Texas. Projects in this area are
expected to yield higher reserve quantities and initial production rates, with
minimal additional risk. Actual expenditures will be dependent on the
availability of capital, as discussed in greater detail below, and may vary
depending on the results of our drilling program. During 2002, we will also
continue to aggressively seek out producing property acquisitions, whose
characteristics meet with our growth parameters. However, the size and timing
of these acquisitions cannot be forecasted with any degree of certainty.
Capital Resources. Our cash requirements have been met primarily in the
past through cash generated from operations, and through available credit from
our revolving bank credit facility. Our current credit facility provides for a
borrowing base of $45,000,000, with no monthly principal payments currently
required, based on our oil and natural gas reserves. The credit facility has a
maturity date of October 2003, and contains terms that give us the option
either of borrowing at the LIBOR rate plus a margin of 1.5% to 2.5% or at a
base rate approximating the prime rate plus a margin ranging from 0% to 0.75%
depending on the amount of advances outstanding in relation to the borrowing
base. The credit facility contains various negative and affirmative covenants
limiting additional indebtedness, sale of assets, mergers and consolidations,
dividends and distributions and requires the maintenance of various financial
ratios. Borrowings under the agreement are secured by substantially all of the
Company's oil and natural gas properties. At December 31, 2001, we had
$42,264,683 advanced under the credit facility and our available credit was
approximately $2,700,000.
For the quarter ended December 31, 2001, the Company's Tangible Net Worth
Ratio and Debt to EBITDA Ratio did not comply with that required under the
credit agreement. In February 2002, the bank lending group granted the Company
a one-time waiver of the default created by the Company's noncompliance with
these two ratio requirements. All other financial ratios calculated under the
credit agreement were within their required ranges. On March 29, 2002, the bank
group amended the credit agreement, lowering the requirements for the Tangible
Net Worth Ratio, effective December 31, 2001, and the Debt to EBITDA Ratio,
effective with the quarter ending June 30, 2002. Additionally, the bank group
granted a one-time waiver of the default projected by the Company to be created
by the expected noncompliance with the Debt to EBITDA Ratio and Debt Service
Coverage Ratio for the quarter ended March 31, 2002. We expect to be in
compliance with all financial covenants during the remainder of 2002 based upon
current forecasts of natural gas prices. If prices substantially decline, we
may have to curtail our capital expenditures or increase our equity to maintain
compliance. There can be no assurance that the bank lending group will grant
waivers of default arising from any future noncompliance with prescribed
financial ratios when, or if they occur.
Our historical ratios for our financial covenants for each quarter of 2001
are as follows:
March 31, June 30, September 31, December 31,
2001 2001 2001 2001
--------- --------- ------------- ------------
Current Ratio.............. 5.27 to 1 5.51 to 1 8.78 to 1 2.35 to 1
Debt Service Coverage Ratio 2.74 to 1 2.45 to 1 2.37 to 1 1.25 to 1
Tangible Net Worth Ratio... 125.32% 127.91% 126.78% 63.76%
Debt to EBITDA Ratio....... .99 to 1 1.78 to 1 5.04 to 1 4.29 to 1
Giving effect to the March 2002 amendments, our ratio requirements are as
follows:
. Current Ratio (greater than) 1.00 to 1
. Debt Service Coverage Ratio (greater than) 1.10 to 1
. Tangible Net Worth (greater than) $17,000,000
. Debt To EBITDA Ratio (less than) 3.75 to 1
22
The credit facility provides for semi-annual borrowing base
redeterminations, the next of which is scheduled to occur as of April 1, 2002.
The borrowing base could be redetermined at a level near or below the amount of
our current advances, which could result in either the loss of available
resources from the credit line or a use of working capital to repay a shortfall
between the new borrowing base and the current advances outstanding. Commodity
prices may not produce sufficient cash flow to allow us to internally finance
our 2002 forecasted capital expenditures. We are and have been exploring
various sources of capital to supplement cash flow. These sources include, but
are not limited to, additional bank credit at higher interest rates, private
equity sales, and sale of common stock through the public equity markets. Our
ability to attract capital from these sources may affect our ability to meet
the forecasted capital spending levels previously discussed.
During February and March 2002, Canaan entered into financial natural gas
price hedging instruments which represented approximately 3,210,000 MMBtu of
natural gas production at a weighted average price of $2.86 per MMBtu. The
hedged natural gas volumes represent approximately 48% of Canaan's 2002
estimated natural gas production on an Mcfe basis. The 2002 hedging instruments
settle monthly beginning April 30, 2002 and ending on January 31, 2003.
Cash flow from operations will be dependent upon our future performance,
which will be subject to prevailing economic conditions and to financial and
business conditions and other factors, many of which are beyond our control. We
expect the availability under our revolving bank credit facility to grow in the
future as we increase the value of our assets. However, the amount of credit
granted by the bank group is affected by the same economic, financial and
business conditions which affect cash flow, as discussed above. In the future,
we also intend to seek additional capital through offerings of additional
equity securities. There can be no assurance, however, that the lenders will
extend or increase the borrowing limits under the credit facility or that such
equity offerings can be successfully completed. Should sufficient financing not
be available from these or other sources, implementation of Canaan's business
plan would be delayed and, accordingly, Canaan's growth strategy could be
adversely affected.
A summary of Canaan's contractual obligations as of December 31, 2001, is
provided in the following table.
Year ended December 31,
-------------------------------------------------------------
2006 and
2002 2003 2004 2005 thereafter Total
-------- ----------- -------- -------- ---------- -----------
Long-term debt.. $ -- $42,264,683 $ -- $ -- $ -- $42,264,683
Operating leases 391,718 376,857 387,609 380,018 2,105,452 3,641,654
-------- ----------- -------- -------- ---------- -----------
Total........ $391,718 $42,641,540 $387,609 $380,018 $2,105,452 $45,906,337
======== =========== ======== ======== ========== ===========
Impact of Issued Accounting Standards Not Yet Adopted
In June and July 2001, the Financial Accounting Standards Board issued new
pronouncements: Statement 141, "Business Combinations," Statement 142,
"Goodwill and Other Intangible Assets," and Statement 143, "Accounting for
Asset Retirement Obligations." Statement 141, which requires the purchase
method of accounting for all business combinations, applies to all business
combinations initiated after June 30, 2001 and to all business combinations
accounted for by the purchase method that are completed after June 30, 2001.
Statement 142 requires that goodwill as well as other intangible assets be
tested annually for impairment and is effective for fiscal years beginning
after December 15, 2001. Statement 143 requires entities to record the fair
value of a liability for an asset retirement obligation in the period in which
it is incurred and a corresponding increase in the carrying amount of the
related long-lived asset. Statement 143 is effective for fiscal years beginning
after June 15, 2002. The provisions of Statement 141 and 142 will not apply to
the Company unless it enters into a future business combination. As of January
1, 2002, the Company has adopted both statements. The Company is currently
assessing the impact of Statement 143 on its financial condition and results of
operations and does not expect to have a material effect upon adoption in 2003.
23
In August 2001, the Financial Accounting Standards Board issued FASB
Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (Statement 144), which supersedes both FASB Statement No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets,
to be Disposed of (Statement 121) and the accounting and reporting provisions
of APB Opinion No. 30, "Reporting the Results of Operations-Reporting the
Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions" (Opinion 30), for the disposal
of a segment of a business (as previously defined in that Opinion). Statement
144 retains the fundamental provisions in Statement 121 for recognizing and
measuring impairment losses on long-lived assets held for use and long-lived
assets to be disposed of by sale, while also resolving significant
implementation issues associated with Statement 121.
The Company was required to adopt Statement 144 no later than the year
beginning after December 15, 2001, and adopted its provisions on January 1,
2002. There was no effect from the adoption of Statement 144 for long-lived
assets held for use or for disposal on the Company's financial statements
because the Company utilizes the full cost method of accounting for oil and
natural gas exploration and development activities and the impairment
assessment under Statement 144 was largely unchanged from Statement 121.
Forward Looking Statements
This document includes certain statements that may be deemed to be "forward
looking statements" within the meaning of Section 27A of the Securities Act of
1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical facts, included in
this document that address activities, events or developments that Canaan
Energy Corporation, an Oklahoma Corporation, expects, believes or anticipates
will or may occur in the future are forward looking statements. They include
statements regarding the Company's drilling plans and objectives, related
exploration and development costs, number and location of planned wells,
reserve estimates and values, statements regarding the quality of the Company's
properties and potential reserve and production levels. These statements are
based on certain assumptions and analyses made by the Company in the light of
its experience and perception of historical trends, current conditions,
expected future developments and other factors it believes appropriate in the
circumstances, including the assumption that there will be no material change
in the operating environment for the Company's properties and that there will
be no material acquisitions or divestitures. Such statements are subject to a
number of risks, including but not limited to commodity price risks, drilling
and production risks, risks related to weather and unforeseen events,
governmental regulatory risks and other risks, many of which are beyond the
control of the Company. For all of these reasons, actual results or
developments may differ materially from those projected in the forward-looking
statements. The Company assumes no obligation to update the forward-looking
statements to reflect events or circumstances occurring after the date of the
statement.
Risks Related to the Oil and Natural Gas Industry
The following risk factors could have an effect on our future results of
operations and financial condition:
A substantial decrease in oil and natural gas prices would have a material
impact on us.
The Company's future financial condition and results of operations are
dependent upon the prices Canaan receives for its oil and natural gas
production. Oil and natural gas prices historically have been volatile and
likely will continue to be volatile in the future. This price volatility also
affects Canaan's common stock price. In 2000, Canaan received natural gas and
oil prices at the wellhead ranging from $1.31 to $11.26 per Mcf and $16.25 to
$36.75 per Bbl, respectively. In 2001, Canaan received natural gas and oil
prices ranging from $1.58 to $12.93 per Mcf and $15.99 to $31.00 per Bbl,
respectively. The Company cannot predict oil and natural gas prices and prices
may increase or decline in the future. The following factors have an influence
on oil and natural gas prices:
. relatively minor changes in the supply of and demand for oil and natural
gas;
. storage availability;
24
. weather conditions;
. market uncertainty;
. domestic and foreign governmental regulations;
. the availability and cost of alternative fuel sources;
. the domestic and foreign supply of oil and natural gas;
. the price of foreign oil and natural gas;
. political conditions in oil and natural gas producing regions, including
the Middle East; and
. overall economic conditions.
We may encounter difficulty in obtaining equipment and services.
Higher oil and gas prices and increased oil and gas drilling activity, such
as those we experienced in 2000, generally stimulate increased demand and
result in increased prices and unavailability for drilling rigs, crews,
associated supplies, equipment and services. While we are currently
experiencing no difficulty obtaining drilling rigs, crews, associated supplies,
equipment and services because of a recent decrease in prices and in activity,
such difficulty could occur in the future. These shortages could also result in
increased costs, delays in timing of anticipated development or cause interests
in oil and gas leases to lapse. We cannot be certain that we will be able to
implement our drilling plans or at costs that will be as estimated or
acceptable to us.
Estimating our reserves and future net cash flows is difficult to do with any
certainty.
There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and their values, including many factors beyond
our control. The reserve data included in this report represents only
estimates. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data, the precision of the engineering and geological
interpretation and judgment. As a result, estimates of different engineers
often vary. The estimates of reserves, future cash flows and present value are
based on various assumptions, including those prescribed by the Securities and
Exchange Commission, and are inherently imprecise. Actual future production,
cash flows, taxes, development expenditures, operating expenses and quantities
of recoverable oil and natural gas reserves may vary substantially from our
estimates. Also, the use of a 10% discount factor for reporting purposes may
not necessarily represent the most appropriate discount factor, given actual
interest rates and risks to which our business or the oil and natural gas
industry in general are subject.
Quantities of proved reserves are estimated based on economic conditions,
including oil and natural gas prices in existence at the date of assessment. A
reduction in oil and natural gas prices not only would reduce the value of any
proved reserves, but also might reduce the amount of oil and natural gas that
could be economically produced, thereby reducing the quantity of reserves. Our
reserves and future cash flows may be subject to revisions, based upon changes
in economic conditions, including oil and natural gas prices, as well as due to
production results, results of future development, operating and development
costs and other factors. Downward revisions of our reserves could have an
adverse affect on our financial condition and operating results.
Our future performance depends upon our ability to find or acquire additional
oil and natural gas reserves that are economically recoverable.
Unless we successfully replace the reserves that we produce, our reserves
will decline, resulting eventually in a decrease in oil and natural gas
production and lower revenues and cash flows from operations. The business of
exploring for, developing or acquiring reserves is capital intensive. We may
not be able to make the necessary capital investment to maintain or expand our
oil and natural gas reserves if cash flows from operations are
25
reduced, due to lower oil and natural gas prices or otherwise, or if external
sources of capital become limited or unavailable. Our ability to replace
reserves in 2002 is dependent on our obtaining additional financing from
external sources as we do not believe cash flow from operations or availability
under our existing credit line will be sufficient. In addition, our drilling
activities are subject to numerous risks, including the risk that no
commercially productive oil or natural gas reserves will be encountered. We
expect to also pursue property acquisition opportunities. We cannot assure you
that we will successfully consummate any future acquisition, that we will be
able to acquire producing oil and natural gas properties that contain
economically recoverable reserves or that any future acquisition will be
profitably integrated into our operations.
We may incur write-downs of the net book values of our oil and natural gas
properties which would adversely affect our shareholders' equity and earnings
The full cost method of accounting, which we follow, requires that we
periodically compare the net book value of our oil and natural gas properties,
less related deferred income taxes, to a calculated "ceiling." The ceiling is
the estimated after-tax present value of the future net revenues from proved
reserves using a 10% annual discount rate and using constant prices and costs.
Any excess of net book value of oil and natural gas properties is written off
as an expense and may not be reversed in subsequent periods even though higher
oil and natural gas prices may have increased the ceiling in these future
periods. A write-off constitutes a charge to earnings and reduces stockholders'
equity, but does not impact our cash flows from operating activities. Future
write-offs may occur which would have a material adverse effect on our net
income in the period taken, but would not affect our cash flows. Even though
such write-offs do not affect cash flow, they can be expected to have an
adverse effect on the price of our publicly traded securities.
During 2001 Canaan reduced the carrying value of its oil and gas properties
by $21,748,000 ($13,484,000, net of tax), due to the full cost ceiling
limitations. The reduction was primarily the result of lower prices. The
ceiling calculation dictates that prices in effect as of the last day of the
applicable quarter are held constant indefinitely. Accordingly, the resulting
value is not indicative of the true fair value of the reserves.
Operational risks in our business are numerous and could materially impact us.
Our operations involve operational risks and uncertainties associated with
drilling for, and production and transportation of, oil and natural gas, all of
which can affect our operating results. Our operations may be materially
curtailed, delayed or canceled as a result of numerous factors, including:
. the presence of unanticipated pressure or irregularities in formations;
. accidents;
. title problems;
. weather conditions;
. compliance with governmental requirements; and
. shortages or delays in the delivery of equipment.
Also, our ability to market oil and natural gas production depends upon
numerous factors, many of which are beyond our control, including:
. capacity and availability of oil and natural gas systems and pipelines;
. effect of federal and state production and transportation regulations; and
. changes in supply of and demand for oil and natural gas.
We do not insure against all potential losses and could be materially
impacted by uninsured losses.
Our operations are subject to the risks inherent in the oil and natural gas
industry, including the risks of fire, explosions, blow-outs, pipe failure,
abnormally pressured formations and environmental accidents, such as oil
26
spills, gas leaks, salt water spills and leaks, ruptures or discharges of toxic
gases. If any of these risks occur in our operations, we could experience
substantial losses due to:
. injury or loss of life;
. severe damage to or destruction of property, natural resources and
equipment;
. pollution or other environmental damage;
. clean-up responsibilities;
. regulatory investigation and penalties; and
. other losses resulting in suspension of our operations.
In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. We do not maintain
insurance for damages arising out of exposure to radioactive material. Even in
the case of risks against which we are insured, our policies are subject to
limitations and exceptions that could cause us to be unprotected against some
or all of the risk. The occurrence of an uninsured loss could have a material
adverse effect on our financial condition or results of operations.
Governmental regulations could adversely affect our business.
Our business is subject to certain federal, state and local laws and
regulations on taxation, the exploration for and development, production and
marketing of oil and natural gas and environmental and safety matters. Many
laws and regulations require drilling permits and govern the spacing of wells,
rates of production, prevention of waste and other matters. These laws and
regulations have increased the costs of our operations. In addition, these laws
and regulations, and any others that are passed by the jurisdictions where we
have production, could limit the total number of wells drilled or the allowable
production from successful wells which could limit our revenues. Laws and
regulations relating to our business frequently change and future laws and
regulations, including changes to existing laws and regulations, could
adversely affect our business.
Environmental liabilities could adversely affect our business.
In the event of a release of oil, natural gas or other pollutants from our
operations into the environment, we could incur liability for personal
injuries, property damage, cleanup costs and governmental fines. We could
potentially discharge these materials into the environment in any of the
following ways:
. from a well or drilling equipment at a drill site;
. leakage from gathering systems, pipelines, transportation facilities and
storage tanks;
. damage to oil and natural gas wells resulting from accidents during
normal operations; and
. blowouts, cratering and explosions.
In addition, because we may acquire interests in properties that have been
operated in the past by others, we may be liable for environmental damage,
including historical contamination, caused by such former operators. Additional
liabilities could also arise from continuing violations or contamination not
discovered during our assessment of the acquired properties.
Competition in the oil and natural gas industry is intense and we are smaller
and have a more limited operating history than many of our competitors.
We compete with major integrated oil and natural gas companies and
independent oil and natural gas companies in all areas of operation. In
particular, we compete for property acquisitions and for the equipment and
labor required to operate and develop these properties. Most of our competitors
have substantially greater financial and other resources than we have. In
addition, larger competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than we can, which
would adversely affect our
27
competitive position. These competitors may be able to pay more for exploratory
prospects and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than we can. Further, our competitors may
have technological advantages and may be able to implement new technologies
more rapidly than we can. Our ability to explore for natural gas and oil
prospects and to acquire additional properties in the future will depend on our
ability to conduct operations, to evaluate and select suitable properties and
to consummate transactions in this highly competitive environment. In addition,
most of our competitors have operated for a much longer time than we have and
have demonstrated the ability to operate through industry cycles.
We have not paid dividends and do not anticipate paying any dividends on our
common stock in the foreseeable future.
We anticipate that we will retain all future earnings and other cash
resources for the future operation and development of our business. We do not
intend to declare or pay any cash dividends in the foreseeable future. Payment
of any future dividends will be at the discretion of our board of directors
after taking into account many factors, including our operating results,
financial condition, current and anticipated cash needs and other factors. The
declaration and payment of any future dividends is currently prohibited by our
credit agreement and may be similarly restricted in the future.
We may incur significant anti-takeover expenses in 2002.
Chesapeake Energy Corporation recently announced its intention to conduct a
tender offer for all of the outstanding shares of common stock of Canaan for
$12.00 per share. We have engaged a financial advisor, CIBC World Markets
Corp., to assist us in evaluating this proposal as well as evaluating all of
our other strategic alternatives which are available to maximize shareholder
value. We expect to incur fees for financial advisory services and other
professional services relating to the possible tender offer and related
process. Depending on how these developments occur, the costs to respond to
this tender offer proposal and other strategic alternatives that may be
presented may be significant and have an adverse affect on our cash flow and
net income for 2002. Such costs may also reduce the amount that we will be able
to spend on our drilling program in 2002.
We are subject to anti-takeover provisions in our charter that could delay or
prevent an acquisition of our company, even if such an acquisition would be
beneficial to our shareholders.
Our certificate of incorporation, our bylaws, Oklahoma law, our shareholders
rights plan and management contracts contain provisions which could make it
more difficult for a third party to acquire us even if doing so might be
beneficial to our shareholders. These provisions include:
. a classified board, the members of which serve staggered three year terms
and may be removed by shareholders only for cause;
. a prohibition on shareholders calling special meetings and acting by
written consent;
. a requirement for advance notice of shareholder proposals and director
nominations;
. restrictions on business combinations with interested shareholders and
limitations on voting power of control share acquisitions;
. a recently adopted shareholders rights plan which deters potential
acquirers from attempting to gain control of the company without prior
board approval; and
. contracts providing severance benefits to management in the event of a
change in control.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
The following information provides quantitative and qualitative information
about Canaan's potential exposure to market risks. The term "market risk"
refers to the risk of loss arising from adverse changes in oil and natural gas
prices and interest rates. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of reasonably
possible losses.
28
Commodity Price Risk. Canaan's major market risk exposure will be in the
pricing applicable to its oil and natural gas production. Realized pricing will
be primarily driven by the prevailing worldwide price for crude oil and spot
market prices applicable to its U.S. natural gas production. Pricing for oil
and natural gas production has been volatile and unpredictable for several
years.
Canaan expects to periodically enter into financial hedging activities with
respect to a portion of forecasted oil and natural gas production through
financial price swaps whereby the Company receives a fixed price for production
and pays a variable market price to the contract counter party. These financial
price-hedging activities are intended to reduce exposure to oil and natural gas
price fluctuations. Realized gains or losses from the settlement of these
financial hedging instruments are recognized in oil and natural gas sales when
the associated production occurs. The gains and losses realized because of
these hedging activities are substantially offset in the cash market when the
hedged commodity is delivered.
During 2000, Canaan entered into financial oil and natural gas price hedging
instruments which represented approximately 1,610,400 MMBtu of natural gas
production at the average rate of 134,200 MMBtu per month at a weighted average
price of $2.748 per MMBtu and approximately 105,787 Bbls of oil production at
the average rate of 8,816 Bbls per month at a weighted average price of $22.00
per Bbl. The hedged volumes represented approximately 39% of the total natural
gas production and 74% of the total oil production for the year ended December
31, 2000. The Company had settled all financial hedging arrangements by May 31,
2001.
During 2001, Canaan entered into financial natural gas price hedging
instruments which represented approximately 498,300 MMBtu of natural gas
production (or 6% of Canaan's 2001 estimated natural gas production on an Mcfe
basis) at the average rate of 99,660 MMBtu per month at a weighted average
price of $2.97 per MMBtu. This hedging arrangement ended May 31, 2001 resulting
in a $1,667,656 negative impact during 2001 to the Company's natural gas
revenues. At December 31, 2001, Canaan had no hedging arrangements of its oil
and natural gas production in place.
Interest Rate Risk. Canaan had long-term debt outstanding of $42.3 million
as of December 31, 2001. All of the debt outstanding at December 31, 2001 bears
interest at floating rates which averaged 4.75% as of December 31, 2001. A 10%
increase in short-term interest rates on the floating-rate debt outstanding at
December 31, 2001 would equal approximately 47.5 basis points. Such an increase
in interest rates would have increased Canaan's interest expense by
approximately $201,000 assuming amounts borrowed at December 31, 2001 were
outstanding for the entire year.
The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
ITEM 8. Financial Statements and Supplemental Data
The financial statements are set forth herein commencing on page F-1.
ITEM 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure
Not applicable.
29
PART III
ITEM 10. Directors and Executive Officers of the Registrant
The information required under Item 10 will be incorporated by reference to
Canaan's proxy statement for the 2002 annual meeting of stockholders to be
filed with the SEC not later than 120 days after December 31, 2001.
ITEM 11. Executive Compensation
The information required under Item 11 will be incorporated by reference to
Canaan's proxy statement for the 2002 annual meeting of stockholders to be
filed with the SEC not later than 120 days after December 31, 2001.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 will be incorporated by reference to
Canaan's proxy statement for the 2002 annual meeting of stockholders to be
filed with the SEC not later than 120 days after December 31, 2001.
ITEM 13. Certain Relationships and Related Transactions
The information required under Item 13 will be incorporated by reference to
Canaan's proxy statement for the 2002 annual meeting of stockholders to be
filed with the SEC not later than 120 days after December 31, 2001.
30
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as a part of this Annual Report on
Form 10-K.
1. Financial Statements. See Financial Statements and Supplemental Data
beginning immediately following the signature page of this report.
2. Schedules. All schedules have been omitted since the schedules are
either not required or the required information is not present or is not
present in amounts sufficient to require submission of the schedule or
because the information required is included in the consolidated financial
statements and notes thereto.
3. Exhibits. The following documents are filed as a part of this
report, all of which, except as otherwise indicated, are incorporated by
reference from the Canaan Energy Corporation's Registration Statement on
Form S-4, File No. 333-30322 ("Form S-4") with the same Exhibit numbers.
Exhibit
Number Description
- ------ -----------
2.1 --Plan of Combination, dated as of February 11, 2000, by and between the Registrant, Coral
Reserves, Inc., Coral Reserves Energy Corp., Indian Oil Company, Canaan Securities, Inc. and the
Partnerships.
2.1(a) --Amendment No. 1 to Plan of Combination dated May 5, 2000
2.1(b) --Amendment No. 2 to Plan of Combination dated July 20, 2001
2.2 --Agreement and Plan of Merger dated February 15, 1999, Between Registrant, Indian Oil
Company, Coral Reserves, Inc. and Coral Reserves Energy Corp. and First Amendment dated
February 15, 1999.
3.1(a) --Amended and Restated Certificate of Incorporation of Registrant.
3.1(b) --Amended and Restated Bylaws of the Registrant.
3.1(c) --Certificate of Designation of Series A Junior Participating Preferred Stock of the Registrant and
filed herewith
4.1 --Rights Agreement dated as of March 13, 2002 (UMB Bank, N.A. as rights agent) (incorporated by
reference to Exhibit 99.2 of Form 8-K dated March 18, 2002).
10.1** --Stock Option Plan of the Registrant.
10.2 --Form of Indemnification Agreement by and between the Registrant and non-employee directors.
10.3** --Form of Change of Control Agreement (revised and supercedes the previously filed form) by and
between the Registrant and executive officers (Messrs. Woodard, Penton, Mewbourn and Henson)
and filed herewith.
10.4 --Shareholders' Agreement between Registrant and certain shareholders of Registrant and certain
former shareholders of Indian Oil Company.
10.5 --Restated and Consolidated Credit Agreement dated October 23, 2000 by and between the
Registrant and a lending group lead by Bank One, Oklahoma, N.A. (Incorporated by reference to
Exhibit 10.1 to the Registrant's Form 8-K filed with the SEC on November 6, 2000).
10.5(a) --First Amendment to Restated and Consolidated Credit Agreement dated October 9, 2001 by and
between the Registrant and a lending group lead by Bank One, Oklahoma, N.A. as filed herewith.
10.5(b) --Second Amendment to Restated and Consolidated Credit Agreement dated November 21, 2001 by
and between the Registrant and a lending group lead by Bank One, Oklahoma, N.A. (incorporated
by reference to Exhibit 10.1 in the Registrant's Form 8-K filed with the SEC on January 15, 2002)
31
Exhibit
Number Description
- ------ -----------
10.6 --Stock Purchase Agreement among Coral Reserves Group, Ltd., Coral Reserves, Inc., Coral
Reserves Energy Corp. and Michael Mewbourn dated November 30, 1998 (Exhibit 10.10 in
Form S-4).
10.7** --Employment Agreement dated November 1, 2000 between Anthony "Skeeter" Lasuzzo and
Canaan Energy Corporation (incorporated by reference to Exhibit 10.7 in the Registrant's
Form 10-K filed with the SEC for the year ending December 31, 2000).
10.7(a) --Letter agreement effective March 12, 2002 between Anthony "Skeeter" Lasuzzo and Canaan
Energy Corporation confirming termination of employment and resignation as a Board member of
Mr. Lasuzzo and filed herewith.
10.8 --Office Lease at Leadership Square, Oklahoma City, OK, Between LSQ Investors, L.L.C.
(Landlord) and Canaan Energy Corporation (Tenant) dated December 4, 2000 (incorporated by
reference to Exhibit 10.8 in Registrant's Form 10-K filed with the SEC for the year ending
December 31, 2000)
10.8(a) --First Amendment to Office Lease at Leadership Square, Oklahoma City, OK, between LSQ
Investors, L.L.C. (Landlord) and Canaan Energy Corporation (Tenant) dated July 18, 2001 and
filed herewith.
10.8(b) --Second Amendment to Office Lease at Leadership Square, Oklahoma City, OK, between LSQ
Investors, L.L.C. (Landlord) and Canaan Energy Corporation (Tenant) dated October 8, 2001 and
filed herewith.
- --------
** Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report.
4. Reports on Form 8-K
A Current Report on Form 8-K dated November 21, 2001 was filed January 15,
2002 pursuant to Items 5 reporting the repurchase of Canaan common stock from
former Indian Oil Company shareholders pursuant to a shareholders agreement.
32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on behalf of the undersigned, thereunto duly authorized.
CANAAN ENERGY CORPORATIOn
By: /s/ LEO E. WOODARD
-----------------------------
Leo E. Woodard
Chairman and Chief Executive
Officer
April 1, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ LEO E. WOODARD Chairman and Chief Executive April 1, 2002
- ----------------------------- Officer
Leo E. Woodard
/s/ JOHN K. PENTON President and Director April 1, 2002
- -----------------------------
John K. Penton
/s/ MICHAEL S. MEWBOURN Senior Vice President, Chief April 1, 2002
- ----------------------------- Financial Officer and
Michael S. Mewbourn Director
/s/ THOMAS H. HENSON Officer and Director April 1, 2002
- -----------------------------
Thomas H. Henson
/s/ MISCHA GORKUSCHA Director April 1, 2002
- -----------------------------
Mischa Gorkuscha
/s/ RANDY HARP Director April 1, 2002
- -----------------------------
Randy Harp
/s/ SCOTT RAYBURN Director April 1, 2002
- -----------------------------
Scott Rayburn
/s/ KEVIN WHITE Director April 1, 2002
- -----------------------------
Kevin White
33
CANAAN ENERGY CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Financial Statements Page
--------------------------------- ----
Reports of Independent Auditors................. F-2
Consolidated Balance Sheets:
December 31, 2001 and 2000................... F-13
Consolidated Statements of Operations:
Years ended December 31, 2001, 2000 and 1999. F-14
Consolidated Statements of Cash Flows:
Years ended December 31, 2001, 2000 and 1999. F-15
Consolidated Statements of Stockholders' Equity:
Years ended December 31, 2001, 2000 and 1999. F-16
Notes to Consolidated Financial Statements...... F-17
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Canaan Energy Corporation:
We have audited the accompanying consolidated balance sheets of Canaan
Energy Corporation and subsidiaries as of December 31, 2001 and 2000, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the years in the three-year period ended December 31, 2001.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits. We did not audit the 1999 financial
statements of the Coral Limited Partnerships or the General Partners of the
Coral Limited Partnerships (Note 1), which statements reflect total revenues
constituting 99% of the related consolidated total revenues in 1999. The 1999
financial statements of the Coral Limited Partnerships and the General Partners
of the Coral Limited Partnership were audited by other auditors whose reports
have been furnished to us, and our opinion, insofar as it relates to the
amounts included for the Coral Limited Partnerships and the General Partners of
the Coral Limited Partnership in 1999 is based solely on the reports of the
other auditors.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 and the reports of the other auditors provide a reasonable basis for our
opinion.
In our opinion, based on our audits and the reports of the other auditors,
the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Canaan Energy Corporation and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, Canaan
Energy Corporation changed its method of accounting for derivative instruments
and hedging activities in 2001.
KPMG LLP
Oklahoma City, Oklahoma
March 1, 2002, except as to note 10 which is as of March 13, 2002 and note 8
which is as of March 29, 2002
F-2
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Natural Gas Income Fund 1990 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Natural Gas Income Fund 1990 Limited Partnership for
the year ended December 31, 1999. These financial statements are the
responsibility of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Natural Gas Income Fund 1990 Limited Partnership as of December 31,
1999, and for the year ended December 31, 1999 in conformity with generally
accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-3
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Natural Gas Income Fund 1991 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Natural Gas Income Fund 1991 Limited Partnership for
the year ended December 31, 1999. These financial statements are the
responsibility of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Natural Gas Income Fund 1991 Limited Partnership as of December 31,
1999, and for the year ended December 31, 1999 in conformity with generally
accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-4
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Natural Gas Income Fund 1992 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Natural Gas Income Fund 1992 Limited Partnership for
the year ended December 31, 1999. These financial statements are the
responsibility of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Natural Gas Income Fund 1992 Limited Partnership as of December 31,
1999, and for the year ended December 31, 1999 in conformity with generally
accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-5
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Natural Gas Income Fund 1993 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Natural Gas Income Fund 1993 Limited Partnership for
the year ended December 31, 1999. These financial statements are the
responsibility of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Natural Gas Income Fund 1993 Limited Partnership as of December 31,
1999, and for the year ended December 31, 1999 in conformity with generally
accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-6
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves 1993 Institutional Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves 1993 Institutional Limited Partnership for the year
ended December 31, 1999. These financial statements are the responsibility of
the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves 1993 Institutional Limited Partnership as of December 31, 1999, and
for the year ended December 31, 1999 in conformity with generally accepted
accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-7
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Energy Income Fund 1995 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Energy Income Fund 1995 Limited Partnership for the
year ended December 31, 1999. These financial statements are the responsibility
of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Energy Income Fund 1995 Limited Partnership as of December 31, 1999,
and for the year ended December 31, 1999 in conformity with generally accepted
accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-8
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves Energy Income Fund 1996 Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Energy Income Fund 1996 Limited Partnership for the
year ended December 31, 1999. These financial statements are the responsibility
of the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Energy Income Fund 1996 Limited Partnership as of December 31, 1999,
and for the year ended December 31, 1999 in conformity with generally accepted
accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-9
INDEPENDENT AUDITOR'S REPORT
To the Partners
Coral Reserves 1996 Institutional Limited Partnership
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves 1996 Institutional Limited Partnership for the year
ended December 31, 1999. These financial statements are the responsibility of
the Partnership's Managing General Partner. 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 audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral 1996
Institutional Limited Partnership as of December 31, 1999, and for the year
ended December 31, 1999 in conformity with generally accepted accounting
principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-10
INDEPENDENT AUDITOR'S REPORT
To the Stockholders
Coral Reserves, Inc.
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves, Inc. for the year ended 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 generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves, Inc. as of December 31, 1999, and for the year ended December 31,
1999 in conformity with generally accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-11
INDEPENDENT AUDITOR'S REPORT
To the Stockholders
Coral Reserves Energy Corp.
Oklahoma City, Oklahoma
We have audited the statements of operations, partners' equity and cash
flows of Coral Reserves Energy Corp. for the year ended 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 generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free
from 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 financial statements referred to above present fairly,
in all material respects, the results of operations and cash flow of Coral
Reserves Energy Corp. as of December 31, 1999, and for the year ended December
31, 1999 in conformity with generally accepted accounting principles.
William T. Zumwalt, CPA, Inc.
Tulsa, Oklahoma
March 10, 2000
F-12
CANAAN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------
2001 2000
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents............................................... $ 2,579,843 $ 6,481,550
Accounts receivable..................................................... 3,783,670 7,569,328
Income tax receivable................................................... 2,534,000 --
Other assets............................................................ 22,157 101,726
------------ ------------
Total current assets................................................ 8,919,670 14,152,604
------------ ------------
Property and equipment, at cost, based on the full cost method of
accounting for oil and natural gas properties.......................... 115,809,831 91,690,784
Less accumulated depreciation and amortization...................... 49,357,756 20,258,478
------------ ------------
66,452,075 71,432,306
------------ ------------
Other assets............................................................. 148,500 188,255
------------ ------------
Total assets........................................................ $ 75,520,245 $ 85,773,165
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade................................................................. $ 2,792,294 $ 1,324,812
Revenue and royalties due to others................................... 1,796,019 2,433,547
Accrued expenses........................................................ 377,878 99,536
Income taxes payable.................................................... -- 1,105,907
------------ ------------
Total current liabilities........................................... 4,966,191 4,963,802
------------ ------------
Long-term debt........................................................... 42,264,683 33,964,683
Deferred income taxes.................................................... 7,587,385 10,514,000
Stockholders' equity:
Common stock, $0.01 par value; 50,000,000 shares authorized, 4,931,815
and 4,353,646 shares issued and outstanding in 2001, respectively, and
4,931,815 and 4,916,315 shares issued and outstanding in 2000,
respectively.......................................................... 49,318 49,318
Additional paid-in capital.............................................. 57,027,781 57,027,781
Treasury stock, at cost, 578,169 and 15,500 shares as of December 31,
2001 and 2000, respectively........................................... (6,885,509) (146,281)
Retained earnings (accumulated deficit)................................. (29,489,604) (20,600,138)
------------ ------------
Total stockholders' equity.............................................. 20,701,986 36,330,680
------------ ------------
Total liabilities and stockholders' equity.......................... $ 75,520,245 $ 85,773,165
============ ============
See accompanying notes to financial statements.
F-13
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,
-------------------------------------
2001 2000 1999
------------ ----------- -----------
Revenues:
Oil and natural gas sales........................... $ 28,381,315 $17,991,577 $10,915,499
Costs and expenses:
Lease operating..................................... 4,536,071 2,088,854 1,564,587
Production taxes.................................... 1,852,158 1,458,425 835,198
Depreciation and amortization....................... 7,352,018 2,891,344 2,594,206
General and administrative expenses................. 4,912,178 2,858,097 1,886,324
Merger costs........................................ -- 1,350,686 --
Reduction in carrying value of oil and natural gas
properties........................................ 21,748,000 -- --
Interest expense.................................... 2,674,652 1,259,628 497,182
------------ ----------- -----------
Total costs and expenses........................ 43,075,077 11,907,034 7,377,497
------------ ----------- -----------
Other income, principally interest................... 367,296 162,966 131,895
------------ ----------- -----------
Earnings (loss) before income taxes.................. (14,326,466) 6,247,509 3,669,897
Income tax expense (benefit)......................... (5,437,000) 4,228,000 26,000
------------ ----------- -----------
Net earnings (loss).................................. $ (8,889,466) $ 2,019,509 $ 3,643,897
============ =========== ===========
Earnings (loss) per average common share
outstanding -- basic............................... $ (1.83) $ 0.52 $ 1.01
============ =========== ===========
Earnings (loss) per average common share
outstanding -- diluted............................. $ (1.83) $ 0.52 $ 1.01
============ =========== ===========
Weighted average common shares outstanding --basic... 4,868,075 3,872,566 3,621,219
============ =========== ===========
Weighted average common shares outstanding -- diluted 4,868,075 3,878,482 3,621,219
============ =========== ===========
See accompanying notes to financial statements.
F-14
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,
---------------------------------------
2001 2000 1999
------------ ------------ -----------
Cash flows from operating activities:
Net earnings (loss)....................................................... $ (8,889,466) $ 2,019,509 $ 3,643,897
Adjustments to reconcile net earnings (loss) to net cash provided by
operating activities, net of effects of acquisitions:
Depreciation and amortization.......................................... 7,352,018 2,891,344 2,594,206
Deferred income tax expense (benefit).................................. (4,316,615) 3,123,000 11,000
Amortization of debt issuance costs.................................... 67,657 11,074 --
Forgiveness of subscription receivable................................. -- 10,951 10,950
Reduction in carrying value of oil and natural gas properties.......... 21,748,000 -- --
(Increase) decrease in accounts receivable and other assets............ 1,331,227 (1,425,016) (613,792)
Increase in accounts payable, accrued expenses and
other liabilities..................................................... 2,389 436,718 215,473
------------ ------------ -----------
Net cash provided by operating activities........................... 17,295,210 7,067,580 5,861,734
------------ ------------ -----------
Cash flows from investing activities:
Proceeds from sales of property and equipment............................. 1,019 478,637 49,946
Acquisition of businesses, net of cash acquired........................... -- 1,696,469 --
Capital expenditures...................................................... (22,768,074) (2,613,434) (1,476,697)
Advances on notes receivable.............................................. -- -- (6,000,000)
Payments received on notes receivable..................................... -- 562,500 562,500
Net proceeds from affiliate contract services............................. 9,366 77,822 58,862
Costs related to business combinations.................................... -- -- (87,696)
------------ ------------ -----------
Net cash provided by (used in) investing activities................. (22,757,689) 201,994 (6,893,085)
------------ ------------ -----------
Cash flows from financing activities:
Borrowings on long-term debt.............................................. 8,300,000 34,589,683 4,497,000
Repayments of long-term debt.............................................. -- (31,377,483) --
Payment of debt issuance costs............................................ -- (199,329) --
Purchase of partnership units............................................. -- (636,592) --
Purchase of treasury stock................................................ (6,739,228) (146,281) --
Distributions to partners................................................. -- (4,513,057) (5,910,092)
------------ ------------ -----------
Net cash provided by (used in) financing activities................. 1,560,772 (2,283,059) (1,413,092)
------------ ------------ -----------
Net increase (decrease) in cash and cash equivalents.......................... (3,901,707) 4,986,515 (2,444,443)
Cash and cash equivalents at beginning of period.............................. 6,481,550 1,495,035 3,939,478
------------ ------------ -----------
Cash and cash equivalents at end of period.................................... $ 2,579,843 $ 6,481,550 $ 1,495,035
============ ============ ===========
Supplemental Cash Flow Information:
Cash payments for income taxes............................................ $ 2,274,426 $ 27,869 $ 53,000
============ ============ ===========
Cash payments for interest................................................ $ 2,345,495 $ 1,248,554 $ 497,182
============ ============ ===========
Supplemental Schedule of Noncash Financing Activities:
Issuance of common stock for acquisition of businesses.................... $ -- $ 17,608,198 $ --
============ ============ ===========
Assumption of debt from acquisition of business........................... $ -- $ 23,639,994 $ --
============ ============ ===========
Costs related to combination transaction incurred with accounts payable... $ -- $ -- $ 170,000
============ ============ ===========
See accompanying notes to financial statements.
F-15
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Number of
Shares of Common Retained Other
Common Additional Stock Earnings Compre-
Stock Common Paid-in Subscription (Accumulated hensive Treasury
Outstanding Stock Capital Receivable Deficit) Income (loss) Stock
----------- ------- ----------- ------------ ------------ ------------- -----------
Balance at December 31, 1998.............. 3,621,219 $36,212 $40,069,281 $(21,901) $(15,840,395) $ -- $ --
Net earnings............................ -- -- -- -- 3,643,897 -- --
Distributions........................... -- -- -- -- (5,910,092) -- --
Forgiveness of subscription
receivable............................. -- -- -- 10,950 -- -- --
--------- ------- ----------- -------- ------------ ----------- -----------
Balance at December 31, 1999.............. 3,621,219 36,212 40,069,281 (10,951) (18,106,590) -- --
Net earnings............................ -- -- -- -- 2,019,509 -- --
Distributions........................... -- -- -- -- (4,513,057) -- --
Purchase of partnership interests....... -- -- (636,592) -- -- -- --
Issuance of common stock................ 1,310,596 13,106 17,595,092 -- -- -- --
Purchase of treasury stock.............. (15,500) -- -- -- -- -- (146,281)
Forgiveness of subscription
receivable............................. -- -- -- 10,951 -- -- --
--------- ------- ----------- -------- ------------ ----------- -----------
Balance at December 31, 2000.............. 4,916,315 49,318 57,027,781 -- (20,600,138) -- (146,281)
Net loss................................ -- -- -- -- (8,889,466) -- --
Cumulative effect of change in
accounting principle, net of tax....... -- -- -- -- -- (1,578,899) --
Derivative losses reclassified into oil
and natural gas sales, net of tax...... -- -- -- -- -- 1,034,160 --
Changes in fair value of derivative
instruments, net of tax................ -- -- -- -- -- 544,739 --
--------- ------- ----------- -------- ------------ ----------- -----------
Comprehensive loss...................... -- -- -- -- -- -- --
Purchase of treasury stock.............. (562,669) -- -- -- -- -- (6,739,228)
--------- ------- ----------- -------- ------------ ----------- -----------
Balance at December 31, 2001.............. 4,353,646 $49,318 $57,027,781 $ -- $(29,489,604) $ -- $(6,885,509)
========= ======= =========== ======== ============ =========== ===========
Total
Stockholders'
Equity
-------------
Balance at December 31, 1998.............. $24,243,197
Net earnings............................ 3,643,897
Distributions........................... (5,910,092)
Forgiveness of subscription
receivable............................. 10,950
-----------
Balance at December 31, 1999.............. 21,987,952
Net earnings............................ 2,019,509
Distributions........................... (4,513,057)
Purchase of partnership interests....... (636,592)
Issuance of common stock................ 17,608,198
Purchase of treasury stock.............. (146,281)
Forgiveness of subscription
receivable............................. 10,951
-----------
Balance at December 31, 2000.............. 36,330,680
Net loss................................ (8,889,466)
Cumulative effect of change in
accounting principle, net of tax....... (1,578,899)
Derivative losses reclassified into oil
and natural gas sales, net of tax...... 1,034,160
Changes in fair value of derivative
instruments, net of tax................ 544,739
-----------
Comprehensive loss...................... (8,889,466)
Purchase of treasury stock.............. (6,739,228)
-----------
Balance at December 31, 2001.............. $20,701,986
===========
See accompanying notes to financial statements.
F-16
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
1. Organization and Basis of Presentation
Canaan Energy Corporation (Canaan) is engaged primarily in the acquisition,
development and production of oil and natural gas properties.
Prior to October 23, 2000, Canaan also managed eight oil and natural gas
limited partnerships (the "Coral Limited Partnerships") on behalf of Coral
Reserves, Inc. and Coral Reserves Energy Corporation, the general partners of
the Coral Limited Partnerships (the "General Partners"). Canaan and the General
Partners had the same ownership.
On October 23, 2000, Canaan acquired the Coral Limited Partnerships, the
General Partners, Canaan Securities, Inc. ("CSI"), an unaffiliated
broker/dealer which previously participated in marketing of the limited
partnership interests, and Indian Oil Company ("Indian"), an unaffiliated oil
and natural gas company. Canaan issued 4,368,815 shares of its common stock as
consideration for the acquired entities. It also paid a stock dividend of
562,368 shares to its shareholders of record immediately prior to the
combination transaction for the purpose of increasing Canaan's outstanding
shares to the amount allocated to it under the terms of the combination
transaction. The accompanying financial statements reflect the stock dividend
as if it had occurred as of the beginning of the earliest period presented. The
acquisition of the Coral Limited Partnerships and the General Partners was
accounted for as a reorganization of interests under common control in a manner
similar to a pooling of interests, and therefore the historical results,
including share and per share data, of Canaan have been restated to reflect the
combination with the Coral Limited Partnerships and the General Partners as if
the entities had been combined for all periods. Unless the context otherwise
indicates, all references to "Canaan" include the Coral Limited Partnerships
and the General Partners. The acquisitions of CSI and Indian were accounted for
as purchases. The results of CSI and Indian have been reflected in Canaan's
results only for the periods subsequent to the transaction date.
Accounting policies employed by Canaan reflect industry practices and
conform to accounting principles generally accepted in the United States of
America. The more significant of such policies are described below.
The consolidated financial statements include the financial statements of
Canaan and its wholly owned subsidiaries. All significant intercompany balances
and transactions have been eliminated in consolidation.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America, requires
management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the financial statements, and the reported amounts
of revenues and expenses during the reporting period. Actual amounts could
differ from those estimates.
Cash and Cash Equivalents
Canaan considers all highly liquid investments with maturities of three
months or less at time of purchase to be cash equivalents. Cash equivalents
consist of overnight investments in money market funds.
Fair Value of Financial Instruments
Canaan's financial instruments consist of cash and cash equivalents,
accounts receivable, accounts payable, accrued expenses, long-term debt and oil
and natural gas price swap contracts. Fair value of non-derivative
F-17
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
financial instruments approximates carrying value due to the short-term nature
of the instruments or that the associated interest rate is variable and resets
throughout the year. See "Hedging Activities" in Note 2 for estimated fair
values of the price swap contracts.
Property and Equipment
Canaan follows the full cost method of accounting for its oil and natural
gas properties. Accordingly, all costs incidental to the acquisition,
exploration, and development of oil and natural gas properties, including costs
of undeveloped leasehold, dry holes and leasehold equipment, are capitalized.
Also included are any internal costs that can be directly identified with
exploration and development activities, but does not include any costs related
to production, general corporate overhead or similar activities. Net
capitalized costs (capitalized costs less accumulated amortization and related
deferred income taxes) are limited to the estimated future net revenues using
period-end pricing, discounted at 10% per annum, from proved oil, natural gas
and natural gas liquids reserves plus the lower of cost or estimated fair value
of unproven properties subject to amortization less the effects of future
income taxes. In 2000, Canaan subjected all costs of unproven properties to
amortization, as such costs were insignificant. In 2001, these costs became
significant through purchases in South Texas and the Oklahoma Panhandle and are
now excluded from amortization, however, these costs are evaluated on a annual
basis for possible impairment purposes. Canaan also compares the carrying value
of its oil and natural gas properties to the calculated limitation at each
period end. Capitalized costs less accumulated amortization plus estimated
future expenditures (based on current costs) to be incurred in developing
proved reserves plus estimated dismantlement and abandonment costs, net of
estimated salvage values, if any, are amortized by an equivalent
unit-of-production method, converting natural gas to oil at the ratio
approximating their relative energy content of one barrel ("Bbl") of oil to six
thousand cubic feet ("Mcf") of natural gas. No gain or loss is recognized upon
disposal of oil and natural gas properties unless such dispositions
significantly alter the relationship between capitalized costs and proved oil
and natural gas reserves. Revenues from services provided to working interest
owners of properties in which Canaan also owns an interest (salt water disposal
services and production engineering services) in excess of related costs
incurred are accounted for as reductions of capitalized costs of oil and
natural gas properties.
Depreciation and amortization of other equipment are provided using the
straight-line method based on estimated useful lives of the related assets,
which range from 3 to 10 years.
Canaan accounts for its non-oil and natural gas long-lived assets in
accordance with the provisions of Financial Accounting Standards Board
Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and
Assets to be Disposed Of." Statement No. 121 requires that long-lived assets
and identifiable intangibles be reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset to future undiscounted net cash
flows expected to be generated by the asset. If such assets are considered to
be impaired, the impairment to be recognized is measured by the amount by which
the carrying amount of the assets exceeds the fair value of the assets. Assets
to be disposed of are reported at the lower of the carrying amount or fair
value less cost to sell.
Other Assets
Other assets as of December 31, 2001 and 2000 respectively, represent debt
issuance costs.
Revenue and Royalty Distributions Payable
For certain oil and natural gas properties, Canaan receives production
proceeds, from the purchaser and further distributes such amounts to other
revenue and royalty owners. Production proceeds applicable to other
F-18
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
revenue and royalty owners are reflected as revenue and royalty distributions
payable in the accompanying balance sheets. Canaan accrues revenue for only its
net interest in its oil and natural gas properties.
Hedging Activities
Canaan periodically enters into oil and natural gas price swap agreements to
manage its exposure to oil and natural gas price volatility. These contracts
have no cash requirements at inception and are with counter parties that Canaan
believes have minimal credit risk. The oil and natural gas reference prices
upon which the price hedging instruments are based reflect various market
indices that have a high degree of historical correlation with actual prices
received by Canaan.
Prior to January 1, 2001, Canaan accounted for its hedging contracts using
the deferral method of accounting. Under this method, realized gains and losses
from Canaan's price risk management activities were recognized in oil and
natural gas revenues when the associated production occurs and the resulting
cash flows were reported as cash flows from operating activities. In the event
of a loss of correlation between changes in oil and natural gas reference
prices under a hedging contract and actual oil and natural gas prices, a gain
or loss was recognized currently to the extent the hedging contract had not
offset changes in actual oil and natural gas prices.
The Financial Accounting Standards Board issued Statement 133, Accounting
for Derivative Instruments and Hedging Activities in 1998. Statement 133
establishes a new model for accounting for derivatives and hedging activities
and supersedes and amends a number of existing standards. Statement 133, (as
amended by Statement 137 and Statement 138) is effective for all fiscal
quarters of fiscal years beginning after June 15, 2000. The Company adopted the
provisions of Statement 133 as of January 1, 2001.
Statement 133, standardizes the accounting for derivative instruments by
requiring that all derivatives be recognized as assets and liabilities and
measured at fair value. The accounting for changes in the fair value of
derivatives (gains and losses) depends on (i) whether the derivative is
designated and qualifies as a hedge, and (ii) the type of hedging relationship
that exists. Changes in the fair value of derivatives that are not designated
as hedges or that do not meet the hedge accounting criteria in Statement 133
are required to be reported in earnings. In addition, all hedging relationships
must be designated, reassessed and documented pursuant to the provisions of
Statement 133. The Company recorded a liability of $2,546,611 as of January 1,
2001 for its natural gas price swap with the offsetting amount, net of $967,712
of income tax, recorded as a component of other comprehensive earnings (loss)
in stockholders' equity.
Revenue Recognition and Natural Gas Balancing
Oil and natural gas sales are recognized in the month in which the oil and
natural gas reserves are sold by Canaan.
During the course of normal operations, Canaan and other joint interest
owners of natural gas reservoirs will take more or less than their respective
ownership share of the natural gas volumes produced. These volumetric
imbalances are monitored over the lives of the wells' production capability. If
an imbalance exists at the time the wells' reserves are depleted, cash
settlements are made among the joint interest owners under a variety of
arrangements. Canaan follows the sales method of accounting for natural gas
imbalances. A liability is recorded only if Canaan's excess takes of natural
gas volumes exceed its estimated remaining recoverable reserves. No receivables
are recorded for those wells where Canaan has taken less than its ownership
share of natural gas production. Canaan's production imbalance position in
terms of volumes and value was not significant as of December 31, 2001 and 2000.
F-19
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Production Costs
Lease operating costs, including costs incurred to maintain or increase
production levels from an existing completion interval, along with production
related taxes are expensed as incurred.
Major Purchasers
Canaan markets its oil and natural gas production to numerous purchasers
under a variety of contracts. During the year ended December 31, 2001 there was
one purchaser, Transok, LLC, that accounted for 13% of the total oil and
natural gas revenues for 2001. During the year ended December 31, 2000, there
were no purchasers that accounted for greater than 10% of the Company total oil
and natural gas revenues. Canaan does not believe that the loss of any single
customer would have a material effect on the results of its operations.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated to
working interests of the oil and natural gas properties operated by Canaan, and
net of amounts capitalized pursuant to the full cost method of accounting.
Canaan capitalized $642,018 in general and administrative costs (all of which
were directly related to exploration and development activities) as the Company
commenced significant drilling activities during 2001. No general and
administrative costs were capitalized for the years ended December 31, 2000 and
1999 due to nominal exploration and development activities by Canaan.
General and administrative costs recovered through allocation to other
working interest owners approximated $933,638, $330,000 and $249,000 for the
years ended December 31, 2001, 2000 and 1999, respectively.
Income Taxes
Canaan accounts for income taxes using the asset and liability method. Under
the asset and liability method, deferred tax assets and liabilities are
recognized at the enacted tax rates for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and the respective tax bases and tax operating
losses and tax credit carry-forwards. The effect on deferred tax assets and
liabilities of a change in tax rates or tax status is recognized in income in
the period that includes the enactment date.
Stock Options
Canaan applies the intrinsic value-based method of accounting prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations, in accounting for its fixed plan stock
options. As such, compensation expense would be recorded on the date of grant
only if the current market price of the underlying stock exceeded the exercise
price. The Financial Accounting Standards Board Statement 123, "Accounting for
Stock-Based Compensation," established accounting and disclosure requirements
using a fair value-based method of accounting for stock-based employee
compensation plans. As allowed by Statement 123, Canaan has elected to continue
to apply the intrinsic value-based method of accounting described above, and
has adopted the disclosure requirements of Statement 123 which are included in
Note 3.
Earnings (Loss) Per Common Share
Basic earnings (loss) per share are computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
for the period. Diluted earnings per share reflect the
F-20
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
potential dilution that could occur if Canaan's dilutive outstanding stock
options were exercised (calculated using the treasury stock method), unless the
effect is antidilutive. There were no dilutive securities prior to November
2000 and due to the loss recognized in 2001, the effect of the stock options is
antidilutive to the 2001 calculation.
The following table reconciles the net loss and common shares outstanding
used in the calculations of basic and diluted loss per share for 2000.
Year ended December 31, 2000
--------------------------------------
Weighted
Net Earnings Average
Applicable to Common
Common Shares Net Earnings
Stockholders Outstanding per Share
------------- ----------- ------------
Basic earnings per share................................ $2,019,509 3,872,566 $0.52
Dilutive effect of potential common shares issuable upon
the exercise of outstanding stock options............. -- 5,916 --
---------- --------- -----
Diluted earnings per share.............................. $2,019,509 3,878,482 $0.52
========== ========= =====
Segment Information
Canaan manages its business by country, which results in one operating
segment during each of the years ended December 31, 2001, 2000 and 1999.
3. Business Combinations
Combination Transactions
On October 23, 2000, Canaan completed the business combination transactions
described in Note 1. As consideration for the acquired entities, Canaan issued
4,368,815 shares of its common stock to shareholders of the acquired entities.
As described in Note 1, the combination with the Coral Limited Partnerships and
the General Partners was accounted for as a reorganization of interests under
common control in a manner similar to a pooling of interests, and the
acquisitions of Indian and CSI were accounted for as purchases.
F-21
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Preliminary amounts with regard to deferred income taxes were finalized in
2001. The final adjustments of $1,390,000 did not affect the number of shares
Canaan issued to acquire Indian, however, the adjustments did impact the
allocation of the total purchase price to assets and liabilities. The
calculation of the total purchase price and the finalized allocation to assets
and liabilities for the acquisition of Indian have been included in the
following table.
Calculation and allocation of purchase price:
Calculation of purchase price:
Number of Canaan shares issued..................................... 1,132,000
Fair value of Canaan shares issued................................. $ 13.42
------------
Purchase price before transaction costs............................ $ 15,191,440
Transaction costs.................................................. 10,000
------------
Total purchase price for Indian.................................... $ 15,201,440
============
Allocated to:
Property and equipment............................................. $ 48,363,937
Current assets..................................................... 6,003,319
Other assets....................................................... 34,870
Current liabilities, excluding current maturities of long-term debt (2,954,692)
Current maturities of long-term debt............................... (23,639,994)
Long-term debt (note to Canaan).................................... (4,875,000)
Deferred income taxes.............................................. (7,731,000)
------------
$ 15,201,440
============
The calculation of the total purchase price and the allocation to assets for
the acquisition of CSI are as follows:
Calculation and allocation of purchase price:
Calculation of purchase price:
Number of Canaan shares issued......... 178,596
Fair value of Canaan shares issued..... $ 13.42
----------
Purchase price before transaction costs $2,396,758
Estimated transaction costs............ 10,000
----------
Total purchase price for CSI........... $2,406,758
----------
Allocated to:
Property and equipment................. $3,388,758
Deferred income taxes.................. (982,000)
----------
$2,406,758
==========
F-22
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Pro Forma Information (Unaudited)
Set forth in the following table is certain unaudited pro forma financial
information for the years ended December 31, 2000 and 1999. This information
has been prepared assuming the acquisitions of CSI and Indian were consummated
as of the beginning of each year, and is based on estimates and assumptions
deemed appropriate by Canaan. The pro forma information is presented for
illustrative purposes only. If the transactions had occurred in the past,
Canaan's operating results might have been different from those presented in
the following table. The pro forma information should not be relied upon as an
indication of the operating results that Canaan would have achieved if the
transactions had occurred on January 1, 1999. The pro forma information also
should not be used as an indication of the future results that Canaan will
achieve after the transactions.
2000 1999
-------- --------
(in thousands, except per
share data)
Revenues................................... $26,180 $19,966
======= =======
Net earnings............................... $ 2,123 $ 458
======= =======
Net earnings per share -- basic and diluted $ 0.55 $ 0.10
======= =======
4. Accounts Receivable
Accounts receivable consisted of the following:
December 31,
---------------------
2001 2000
---------- ----------
Oil and natural gas revenue accruals $2,845,134 $7,076,404
Joint interest billings............. 938,536 487,889
Receivables from officers........... -- 5,035
---------- ----------
Total............................... $3,783,670 $7,569,328
========== ==========
5. Note Receivable
Prior to the acquisition of Indian Oil Company, Canaan advanced $6,000,000
in return for a production payment note from Indian Oil Company. The minimum
monthly amount payable to Canaan was $56,250. The $4,875,000 balance of the
production payment note at October 23, 2000, was recognized as part of the
consideration paid by Canaan to acquire all of Indian's outstanding shares.
F-23
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
6. Property and Equipment
Property and equipment consisted of the following:
December 31,
--------------------------
2001 2000
------------ ------------
Oil and natural gas properties -- subject to amortization.... $111,751,680 $ 91,280,293
Oil and natural gas properties -- not subject to amortization 3,103,881 --
Accumulated depreciation and amortization.................... (49,045,170) (20,068,865)
------------ ------------
Net oil and natural gas properties........................ 65,810,391 71,211,428
------------ ------------
Other equipment.............................................. 954,270 410,491
Accumulated depreciation..................................... (312,586) (189,613)
------------ ------------
Net other equipment....................................... 641,684 220,878
------------ ------------
Property and equipment, net of accumulated depreciation and
amortization............................................... $ 66,452,075 $ 71,432,306
============ ============
All of the oil and natural gas properties not subject to amortization were
acquired in 2001.
Depreciation and amortization expense consisted of the following:
Year ended December 31,
--------------------------------
2001 2000 1999
---------- ---------- ----------
Depreciation and amortization of oil and natural gas
properties........................................ $7,228,307 $2,850,321 $2,581,614
Depreciation of other equipment..................... 123,711 39,890 10,992
Other amortization.................................. -- 1,133 1,600
---------- ---------- ----------
Total expense....................................... $7,352,018 $2,891,344 $2,594,206
========== ========== ==========
Reduction of Carrying Value of Oil and Gas Properties
Under the full cost method of accounting, the net book value of oil and gas
properties, less related deferred income taxes, may not exceed a calculated
"ceiling." The ceiling limitation is the discounted estimated after-tax future
net revenues from proved oil and gas properties plus the lower of cost or fair
value of unproved properties. The ceiling is imposed separately by country. In
calculating future net revenues, current prices and costs are generally held
constant indefinitely. The net book value, less related deferred tax
liabilities, is compared to the ceiling on a quarterly and annual basis. Any
excess of the net book value, less deferred taxes, is written off as an
expense. An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.
7. Accounting for Derivative Instruments and Hedging Activities
On September 24, 1999, Canaan entered into a natural gas price swap covering
100,375 Mcf of monthly production, or approximately 30% of its natural gas
production beginning October 1999 through September 2000. The price received
for this production was $2.60 per Mcf, while Canaan paid the counter-party a
floating index price. On November 18, 1999, Canaan entered into an oil price
swap covering 8,520 barrels of monthly oil
F-24
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
production or approximately 80% of its oil production beginning January 2000
through December 2000. The price received for this production was $22.00 per
barrel, while Canaan paid the counter-party a floating index price.
In April 2000, Canaan entered into an additional natural gas price swap
covering 100,375 Mcf of monthly production or approximately 30% of its natural
gas production from June 2000 through May 2001. The price received for this
production was $2.97 per Mcf, while Canaan paid the counter party a floating
index price.
The fair value of Canaan's natural gas and oil price hedging contracts
approximated ($2,546,611) at December 31, 2000. This asset (liability)
represents the estimated amount Canaan would receive (pay) to cancel the
contracts or transfer them to other parties. No deferred hedging gains or
losses were recorded as of December 31, 2000.
On January 1, 2001, the Company adopted the provisions of Statement of
Financial Accounting Standards Board Statement 133, "Accounting for Derivative
Instruments and Certain Hedging Activities" and Statement 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities, an Amendment of
SFAS No. 133." Statement 133 and Statement 138 require that all derivative
instruments be recorded on the balance sheet at their respective fair values.
In accordance with the transition provisions of Statement 133, the Company
recorded a net-of-tax cumulative-effect-type adjustment of a $1,578,899 loss in
accumulated other comprehensive loss to recognize at fair value all derivatives
that were designated as cash-flow hedging financial instruments.
All of the Company's derivatives that qualified for hedge accounting
treatment were "cash-flow" hedges. The Company designated its cash flow hedge
derivatives on the transition date. The Company formally documented the
relationships between the hedging instruments and hedged items, as well as its
risk-management objective and strategy for undertaking various hedge
transactions. This process included linking all derivatives that were
designated as cash-flow hedges to specific forecasted transactions. The Company
also assessed, both at the transition date and on an ongoing basis, whether the
derivatives that are used in hedging transactions were effective in offsetting
changes in cash flows of hedged items.
Changes in the fair value of a derivative that is effective and that is
designated and qualifies as a cash-flow hedge are recorded in other
comprehensive income, until earnings are affected by the variability in cash
flows of the designated hedged item.
During 2001, there were no gains or losses reclassified into earnings as a
result of the discontinuance of hedge accounting treatment for any of the
Company's derivatives.
By using derivative financial instruments to hedge exposures to changes in
commodity prices, the Company exposed itself to credit risk and market risk.
Credit risk is the failure of the counterparty to perform under the terms of
the derivative contract. To mitigate this risk, the hedging instruments were
placed with counterparties that the Company believes are minimal credit risks.
Market risk is the adverse effect on the value of a financial instrument
that results from a change in interest rates, commodity prices, or currency
exchange rates. The market risk associated with commodity-price contracts is
managed by establishing and monitoring parameters that limit the types and
degree of market risk that may be undertaken.
F-25
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
The Company periodically enters into financial hedging activities with
respect to a portion of its projected oil and natural gas production through
various financial transactions to manage its exposure to oil and gas price
volatility. These transactions include financial price swaps whereby the
Company will receive a fixed price for its production and pay a variable market
price to the contract counterparty. These financial hedging activities are
intended to support oil and gas prices at targeted levels and to manage the
Company's exposure to oil and gas price fluctuations. The oil and gas reference
prices upon which these price-hedging instruments are based reflect various
market indices that had a high degree of historical correlation with actual
prices received by the Company.
The Company does not hold or issue derivative instruments for trading
purposes. The Company's commodity-price swap in place as of January 1, 2001 was
designated as a cash flow hedge. The derivative instrument expired May 31,
2001. Changes in fair value of the derivative were reported on the balance
sheet in "Accumulated Other Comprehensive Income (AOCI)." These amounts have
been reclassified to oil and natural gas sales upon settlement with the
contract counterparty.
The Company assesses the effectiveness of its hedges, at least quarterly,
based on relative changes in fair value between the derivative instrument and
the hedged forecasted sale of oil and gas. For the year ended December 31,
2001, the Company recorded a net charge of $60,000 which represented the
ineffectiveness of the cash-flow hedge. The ineffectiveness was recorded in oil
and natural gas sales in the consolidated statement of operations.
All of the net deferred losses on derivative instruments, including the
transition adjustment, accumulated in AOCI were reclassified to earnings by May
31, 2001 (the expiration date of the price swap contract). At December 31,
2001, the Company did not have any financial hedging arrangements.
8. Long-Term Debt
Simultaneously with the closing of the transactions described in Note 1, the
Company entered into a new secured revolving credit facility with a group of
banks which provides for a borrowing base of $45,000,000, with no monthly
principal payments currently required, based on the Company's oil and natural
gas reserves. The credit facility has a maturity date of October 2003. The
terms of the facility give the Company the option of either borrowing at the
LIBOR rate plus a margin of 1.5% to 2.50% or at a base rate approximating the
prime rate plus a margin ranging from 0.0% to 0.75% depending on the amount of
advances outstanding in relation to the borrowing base. At December 31, 2001,
the Company had $30,000,000 of its total debt balance under the LIBOR interest
option, resulting in a rate on that date of 4.45%. The remainder of the debt
balance bore interest at the prime rate option, resulting in a rate 5.5% at
December 31, 2001. The credit facility contains various affirmative and
restrictive covenants limiting additional indebtedness, sales of assets,
mergers and consolidations, dividends and distributions and requires the
maintenance of various financial ratios. The credit facility is subject to a
commitment fee for the banks maintaining of funds available for Canaan. The
commitment fee ranges from 0.25% to 0.50%, based on the amount of the revolving
commitment in effect for the applicable period. Borrowings under the agreement
are secured by substantially all of the Company's oil and natural gas
properties. The credit facility provides for semi-annual borrowing base
redeterminations, the next of which is scheduled to occur as of April 1, 2002.
In connection with the completion of the combination transactions, the
Company borrowed $33,964,683 under the credit facility to refinance
approximately $31,377,000 in existing indebtedness (including approximately
$23,600,000 assumed in the Indian acquisition) and to pay for transaction
costs. The interest rate as of December 31, 2002 was 10.25%.
F-26
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
The Company's borrowings under this facility represent all of its borrowings
as of December 31, 2001 and 2000.
The credit facility is governed by a credit agreement between the Company
and the bank lending group. This agreement requires the Company to comply with
certain financial ratios on a quarterly reporting basis. These ratios, as
defined in the credit agreement, include a Current Ratio, Debt Service Coverage
Ratio, Tangible Net Worth Ratio and Debt to EBITDA Ratio. For the quarter ended
December 31, 2001, the Company's Tangible Net Worth Ratio and Debt to EBITDA
Ratio did not comply with that required under the credit agreement. In February
2002, the bank lending group granted the Company a one-time waiver of the
default created by the Company's noncompliance with these two ratio
requirements. All other financial ratios calculated under the credit agreement
were within their required ranges. In March 2002, the bank group amended the
credit agreement, lowering the ratio requirements for the Tangible Net Worth
Ratio, effective December 31, 2001, and the Debt to EBITDA Ratios, effective
with the quarter ending June 30, 2002. Additionally, the bank group granted a
one-time waiver of the default projected by the Company to be created by the
expected noncompliance with the Debt to EBITDA Ratio and Debt Service Coverage
Ratio for the quarter ended March 31, 2002.
Annual maturities of long-term debt subsequent to December 31, 2001 are as
follows:
2002 $ --
2003 42,264,683
-----------
$42,264,683
===========
9. Income Taxes
The components of income tax expense (benefit) were as follows:
Year Ended December 31,
-------------------------------
2001 2000 1999
----------- ---------- -------
Current income tax expense (benefit):
U.S. Federal........................... $ (971,000) $ 960,000 $11,000
State.................................. (149,000) 145,000 4,000
----------- ---------- -------
Total current tax expense (benefit).. (1,120,000) 1,105,000 15,000
----------- ---------- -------
Deferred income tax expense (benefit):
U.S. Federal........................... (3,756,000) 2,712,000 9,000
State.................................. (561,000) 411,000 2,000
----------- ---------- -------
Total deferred tax expense (benefit). (4,317,000) 3,123,000 11,000
----------- ---------- -------
Total income tax expense (benefit)... $(5,437,000) $4,228,000 $26,000
=========== ========== =======
F-27
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Total income tax expense for the respective years differed from the amounts
computed by applying the U.S. federal income tax rate to earnings before income
taxes as a result of the following:
Year Ended
December 31,
-------------
2001 2000 1999
---- ---- ----
U.S. statutory tax rate............................... 35% 35% 34%
State income taxes.................................... 3 3 4
Change in tax status of the Coral Limited Partnerships -- 54 --
Partnership income, not directly subject to income tax -- (27) (18)
Effect of graduated tax rates......................... -- -- (19)
Nonconventional fuel source tax credits............... -- -- (3)
Other................................................. -- 3 3
--- --- ---
Effective income tax rate............................. 38% 68% 1%
=== === ===
The tax effects of temporary differences that gave rise to the deferred tax
assets and liabilities at December 31, 2000 and 2001 are presented below:
2001 2000
------------ ------------
Deferred tax assets:
Net operating loss carryforwards................. $ 3,395,000 $ 1,475,000
Statutory depletion carryforwards................ 500,000 717,000
Effect of cash-basis tax reporting............... -- 45,000
------------ ------------
Total deferred tax assets...................... 3,895,000 2,237,000
Deferred tax liabilities -- property and equipment (11,482,000) (12,751,000)
------------ ------------
Net deferred tax liability........................ $ (7,587,000) $(10,514,000)
============ ============
Prior to the October 23, 2000 combination transactions, the Coral Limited
Partnerships had not recognized deferred income tax assets or liabilities since
any income tax liabilities were the responsibility of the individual partners.
As a result of the combination transaction on October 23, 2000, the Company
recognized approximately $3,387,000 of deferred income tax expense related to
the difference between financial carrying value and associated income tax basis.
On a pro forma basis, assuming the income from the Coral Partnerships was
fully taxed at corporate rates and the deferred tax assets and liabilities of
the Coral Partnerships had been recorded prior to 2000, income tax expense, net
earnings, and earnings per average common share would have been $2,537,000,
$3,711,000, and $0.96 per share, respectively, for the year ended December 31,
2000 (unaudited).
Prior to its purchase by Canaan, Indian had generated tax net operating
losses. These losses can be used to offset Canaan's taxable income. However,
the amount that can be used in any year is limited. The Indian net operating
loss carryforwards expire beginning in 2008 and extend through 2019.
Additionally, Canaan has generated tax net operating losses. The Canaan net
operating loss carryforwards expire in 2021. Management of Canaan believes that
Canaan will generate sufficient taxable income to allow the full utilization of
these net operating loss carryforwards.
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or not all of the deferred
tax assets will be realized. The ultimate realization of deferred tax
F-28
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences become deductible. Management
considers the scheduled reversal of deferred tax liabilities, projected future
taxable income, and tax planning strategies in making this assessment. Based
upon the level of historical taxable income and projections for future taxable
income over the periods which the deferred tax assets are deductible,
management believes it is more likely than not the Company will realize the
benefits of these deductible differences, net of the existing valuation
allowances at December 31, 2001.
10. Share Purchase Rights Plan
On March 13, 2002, Canaan's Board adopted a Share Purchase Rights Plan (the
"Plan") and declared a dividend distribution of preferred share purchase rights
to shareholders of record on March 25, 2002. The rights have no economic value
until a person or group has become an "Acquiring Person" by obtaining 15% or
more of the Company's outstanding common stock. If a person or group becomes an
Acquiring Person, the Rights entitle all holders except the Acquiring Person to
purchase an amount of preferred stock (or common stock if the Company so
determines) approximately equal in value to one share of common at a 50%
discount to market price. Canaan's Board has the authority to redeem the rights
for $0.01 per right, so as not to interfere with the completion of a Board
approved transaction. The Plan was designed and implemented to assist Canaan's
shareholders in realizing maximum value for their investment in the Company.
The Plan expires March 13, 2012.
11. Stock Option Plan
The Company has a stock option plan providing for the granting of options to
purchase up to 500,000 shares.
No stock options were granted by Canaan prior to November 27, 2000. On that
date, Canaan granted 412,500 options to members of the Company's management and
professional staff at $9.44 per share. The market value was the same as grant
price on the date of grant. Of the options granted, 25,000 vested at issuance
and 12,500 vest 50% on the third and fifth anniversary dates. All other options
granted to employees in 2000 vest at a rate of 25% upon each anniversary date.
During 2001, Canaan granted options for an additional 83,250 shares to the
professional staff at an average rate of $9.53. On the dates of grant, the
market value and grant price were the same. All the options granted to
employees during 2001 vest at a rate of 25% upon each anniversary date, except
for 25,000 options that vest 50% on the third and fifth anniversary dates.
Vested options to three non-employee directors aggregating 300 shares were
granted April 9, 2001 at an exercise price of $9.00 per share.
The Company applies APB Opinion No. 25 in accounting for its plan and
accordingly, no compensation cost has been recognized for its stock options in
the financial statements. Had the Company determined compensation cost based on
the fair value at the grant date for its stock options under Statement No. 123,
the Company's results would have been reduced to the pro forma amounts
indicated below:
2001 2000
----------- ----------
Net (loss) earnings As reported $(8,889,466) $2,019,509
Pro forma...................... $(9,310,146) $1,989,354
For 2001, fair value was determined using the Black-Scholes option pricing
model with the following assumptions: expected dividend yield of 0%, risk-free
interest rate of 3.25%, expected volatility of 24%, and an expected term of 5
years.
F-29
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
For 2000, fair value was determined using the Black-Scholes option pricing
model with the following assumptions: expected dividend yield of 0%, risk-free
interest rate of 6.65%, expected volatility of 27%, and an expected term of 5
years.
Stock option activity during 2001 and 2000 was as follows:
Number Weighted-average
of shares exercise price
--------- ----------------
Options outstanding at December 31, 1999 -- $ --
Granted................................ 412,500 9.44
Exercised.............................. -- --
Forfeited.............................. -- --
Expired................................ -- --
------- -----
Options outstanding at December 31, 2000 412,500 9.44
Granted................................ 83,250 9.53
Exercised.............................. -- --
Forfeited.............................. (500) 9.00
Expired................................ -- --
------- -----
Options outstanding at December 31, 2001 495,250 $9.46
======= =====
12. Employee Benefit Plan
Canaan maintains a qualified profit sharing plan pursuant to which it may
make discretionary contributions subject to Internal Revenue Code limits.
Benefits payable under the plan are limited to the amount of assets allocable
to the account of each plan participant. Canaan retains the right to modify,
amend or terminate the plan at any time. Canaan recorded $443,175, $184,000 and
$126,000 of expenses related to discretionary contributions to the plan for the
years ended December 31, 2001, 2000 and 1999, respectively.
13. Commitments and Contingencies
Canaan leases office space and equipment under operating leases expiring
over the next ten years. Future minimum lease payments under non-cancelable
operating leases having remaining terms in excess of one year as of December
31, 2001 are as follows:
2002............... $ 391,718
2003............... 376,857
2004............... 387,609
2005............... 380,018
2006 and thereafter 2,105,452
----------
Total.............. $3,641,654
==========
Rent expense for the years ended December 31, 2001, 2000 and 1999
approximated $345,439, $102,000 and $73,000, respectively.
The Company expects to be involved from time to time in various legal and
administrative proceedings and threatened legal and administrative proceedings
incidental to the ordinary course of its business. As of
F-30
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
December 31, 2001, Canaan was not involved in any litigation that could have a
material adverse effect on Canaan's business, financial condition, and results
of operations or cash flows.
14. Related Party Transactions
November 1998, Canaan issued 51,232 shares of its common stock to one of its
officers in exchange for a $32,851 promissory note. The note earned interest at
the annual rate equal to the discount rate charged by the New York Federal
Reserve Bank, re-determined semi-annually, and was secured by the common stock.
The note matured in November 2000; however, it allowed Canaan to forgive the
note as services were provided by the officer over the term of the note. Canaan
forgave $10,951 in 2000 and $10,950 of the note in 1999 and 1998. The note is
reflected in the accompanying balance sheets and statements of stockholders'
equity as a stock subscription receivable. Compensation expense was recorded
pro ratably over the term of the note. The shares issued to the officer have
rights equal to Canaan's other common shares. Canaan estimated the fair value
of the shares issued to the officer exceeded the principal balance of the
promissory note by $13,000, which was recorded as additional compensation
expense in 1998.
15. Oil and Natural Gas Operations
The following table reflects the costs incurred in oil and natural gas
property acquisition and development activities:
Year ended December 31,
--------------------------------
2001 2000 1999
----------- ----------- --------
Acquisition costs $ 5,669,532 $51,857,378 $ 6,094
Development costs 15,982,657 2,135,315 894,028
Results of Operations for Oil and Natural Gas Activities
Below is a summary of results of operations for oil and natural gas
producing activities. The results do not include any allocation of Canaan's
general corporate overhead and, therefore, are not necessarily indicative of
the contribution to net earnings of its oil and natural gas operations. Income
tax expense has been calculated by applying statutory income tax rates to oil
and natural gas sales after deducting costs, including depreciation and
amortization and considering permanent differences (for 1999 including
partnership income which was not subject to corporate income taxes), tax
credits and allowances related to oil and natural gas producing activities.
Year ended December 31,
--------------------------------------
2001 2000 1999
------------ ----------- -----------
Oil and natural gas sales............................... $ 28,381,315 $17,991,577 $10,915,499
Production and operating expenses....................... (6,388,229) (3,547,279) (2,399,785)
Depreciation and amortization........................... (7,228,307) (2,850,321) (2,581,614)
Reduction in carrying value of oil and natural gas
properties............................................ (21,748,000) -- --
Income tax benefit (expense)............................ 2,653,624 (4,044,000) (16,000)
------------ ----------- -----------
Results of operations from oil and natural gas producing
activities............................................ $ (4,329,597) $ 7,549,977 $ 5,918,100
------------ ----------- -----------
Depreciation and amortization per equivalent Mcf of
production............................................ $ 0.95 $ 0.57 $ 0.56
============ =========== ===========
F-31
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
16. Supplemental Information on Oil and Natural Gas Operations (Unaudited)
The following supplemental unaudited information regarding the oil and
natural gas activities of Canaan is presented pursuant to the disclosure
requirements promulgated by the Securities and Exchange Commission (SEC) and
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities".
Quantities of Oil and Natural Gas Reserves
Set forth below is a summary of the changes in the net quantities of crude
oil and natural gas and reserves for each of the years in the three-year period
ended December 31, 2001. Canaan's proved reserves at December 31, 2001, 2000
and 1999, were calculated by the independent petroleum consultants of
Netherland, Sewell & Associates, Inc. There are many uncertainties inherent in
estimating reserve quantities and in projecting future production rates and the
timing of future development cost expenditures. In addition, reserve estimates
of new discoveries are more imprecise than those of properties with a
production history. Accordingly, these estimates are subject to change as
additional information becomes available.
Proved oil and natural gas reserves are the estimated quantities of crude
oil, condensate, natural gas and natural liquids that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic conditions. Proved
developed oil and natural gas reserves are those reserves expected to be
recovered through existing equipment and operating methods.
Estimates of net quantities of proved reserves and proved developed reserves
of crude oil, including condensate and natural gas liquids, and natural gas, as
well as the changes in proved reserves during the periods indicated, are set
forth in the tables below. All reserves are located in the United States.
Changes in Proved Reserves
Natural Gas
Oil (Bbls) (Mcf)
---------- -----------
Proved reserves as of December 31, 1998 995,000 36,152,000
Extensions and discoveries............ 89,000 284,000
Revisions of previous estimates....... 461,000 4,661,000
Purchases of reserves................. 51,000 166,000
Production............................ (153,000) (3,717,000)
--------- ----------
Proved reserves as of December 31, 1999 1,443,000 37,546,000
Extensions and discoveries............ 55,000 1,605,000
Revisions of previous estimates....... 31,000 9,445,000
Purchases of reserves................. 584,000 50,168,000
Production............................ (143,000) (4,137,000)
--------- ----------
Proved reserves as of December 31, 2000 1,970,000 94,627,000
Extensions and discoveries............ 66,000 4,162,000
Revisions of previous estimates....... (513,000) (8,380,000)
Purchases of reserves................. 18,000 2,879,000
Production............................ (181,000) (6,562,000)
--------- ----------
Proved reserves as of December 31, 2001 1,360,000 86,726,000
========= ==========
Proved developed reserves as of
December 31, 1998..................... 897,000 31,120,000
December 31, 1999..................... 1,184,000 30,281,000
December 31, 2000..................... 1,727,000 72,393,000
December 31, 2001..................... 1,225,000 65,453,000
F-32
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
Standardized Measure of Discounted Future Net Cash Flows:
The following table reflects the standardized measure of discounted future
net cash flows relating to Canaan's interest in proved reserves:
December 31,
------------------------------------------
2001 2000 1999
------------- ------------- ------------
Future cash inflows............................... $ 249,173,000 $ 954,174,000 $112,692,000
Future development costs.......................... (20,635,000) (20,158,000) (4,601,000)
Future production costs........................... (109,987,000) (168,691,000) (37,667,000)
Future income tax expense......................... (24,574,000) (252,588,000) (18,682,000)
------------- ------------- ------------
Future net cash flows............................. 93,977,000 512,737,000 51,742,000
10% discount to reflect timing of cash flows...... (44,268,000) (262,006,000) (23,782,000)
------------- ------------- ------------
Standardized measure of discounted future net cash
flows........................................... $ 49,709,000 $ 250,731,000 $ 27,960,000
============= ============= ============
Future cash inflows are computed by applying year-end prices for each year
presented (averaging $18.48 and $26.10 per barrel of oil, adjusted for
transportation and other charges, and $2.58 and $9.54 per Mcf of natural gas at
December 31, 2001 and 2000, respectively) to the respective year-end quantities
of proved reserves, except where fixed and determinable price changes are
provided by contractual arrangements in existence at year-end. Future
development and production costs are computed by estimating the expenditures to
be incurred in developing and producing proved oil and natural gas reserves at
the end of each year, based on respective year-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
statutory rates to the future pre-tax net cash flows relating to proved
reserves, net of the tax basis of the properties involved giving effect to
permanent differences, tax credits and allowances relating to proved oil and
natural gas reserves.
Principal changes in the standardized measure of discounted future net cash
flows attributable to Canaan's proved reserves are as follows:
Year ended December 31,
-----------------------------------------
2001 2000 1999
------------- ------------- -----------
Beginning balance............................................... $ 250,731,000 $ 27,960,000 $20,111,000
Sales of oil and natural gas, net of production costs........... (21,993,000) (14,444,000) (8,283,000)
Net changes in year-end sales prices and production costs....... (301,932,000) 122,588,000 11,687,000
Extensions and discoveries, net of future development costs..... 2,022,000 6,052,000 1,473,000
Revisions of previous estimates, net of future development costs (9,063,000) 36,346,000 7,579,000
Development costs incurred during the period which reduced
future development costs...................................... 2,814,000 400,000 57,000
Purchase of reserves, net of future development costs........... 1,678,000 193,367,000 629,000
Sales of reserves in place, net of future development costs..... -- -- --
Accretion of discount........................................... 37,425,000 3,806,000 2,349,000
Net change in income taxes...................................... 110,519,000 (113,414,000) (6,724,000)
Other, primarily timing......................................... (22,492,000) (11,930,000) (918,000)
------------- ------------- -----------
Ending balance.................................................. $ 49,709,000 $ 250,731,000 $27,960,000
============= ============= ===========
F-33
CANAAN ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2001, 2000 and 1999
16. Quarterly Results (Unaudited)
Following is a summary of the unaudited interim results of operations for
the years ended December 31, 2001 and 2000:
Second Third Fourth
First Quarter Quarter Quarter Quarter Full Year
------------- ---------- ---------- ------------ -----------
2001
Revenues.............................. $11,421,012 $7,347,687 $4,492,919 $ 5,119,697 $28,381,315
Net earnings (loss)................... $ 3,730,832 $1,469,415 $ (349,524) $(13,740,189) $(8,889,466)
=========== ========== ========== ============ ===========
Net earnings (loss) per share -- basic
and diluted......................... $ 0.76 $ 0.30 $ (0.07) $ (2.91) $ (1.83)
=========== ========== ========== ============ ===========
2000
Revenues.............................. $ 3,120,716 $3,729,593 $3,042,317 $ 8,098,951 $17,991,577
Net earnings (loss)................... $ 1,112,464 $1,925,645 $ 990,700 $ (2,009,300) $ 2,019,509
=========== ========== ========== ============ ===========
Net earnings (loss) per share -- basic
and diluted......................... $ 0.31 $ 0.53 $ 0.27 $ (0.44) $ 0.52
=========== ========== ========== ============ ===========
During the fourth quarter of 2000, Canaan recognized $1,350,686 of merger
costs and approximately $3,387,000 of deferred income tax expense. Both items
resulted from the combination transactions that occurred on October 23, 2000.
During the fourth quarter of 2001, Canaan recognized $21,748,000
($13,484,000, net of tax) of reductions in carrying value of oil and natural
gas properties.
F-34
INDEX TO EXHIBITS
Exhibit
Number Description
- ------ -----------
2.1 --Plan of Combination, dated as of February 11, 2000, by and between the Registrant, Coral
Reserves, Inc., Coral Reserves Energy Corp., Indian Oil Company, Canaan Securities, Inc. and
the Partnerships
2.1(a) --Amendment No. 1 to Plan of Combination dated May 5, 2000.
2.1(b) --Amendment No. 2 to Plan of Combination dated July 20, 2001
2.2 --Agreement and Plan of Merger dated February 15, 1999, Between Registrant, Indian Oil
Company, Coral Reserves, nc. and Coral Reserves Energy Corp. and First Amendment dated
February 15, 1999.
3.1(a) --Amended and Restated Certificate of Incorporation of Registrant.
3.1(b) --Amended and Restated Bylaws of the Registrant.
3.1(c) --Certificate of Designation of Series A Junior Participating Preferred Stock of the Registrant and
filed herewith
4.1 --Rights Agreement dated as of March 13, 2002 (UMB Bank, N.A. as rights agent) (incorporated by
reference to Exhibit 99.2 of Form 8-K dated March 18, 2002).
10.1** --Stock Option Plan of the Registrant.
10.2 --Form of Indemnification Agreement by and between the Registrant and non-employee directors.
10.3** --Form of Change of Control Agreement (revised and supercedes the previously filed form) by and
between the Registrant and executive officers (Messrs. Woodard, Penton, Mewbourn and Henson)
and filed herewith.
10.4 --Shareholders' Agreement between Registrant and shareholders of Registrant and certain former
shareholders of Indian Oil Company.
10.5 --Restated and Consolidated Credit Agreement dated October 23, 2000 by and between the
Registrant and a lending group lead by Bank One, Oklahoma, N.A. (Incorporated by reference to
Exhibit 10.1 to the Registrant's Form 8-K filed with the SEC on November 6, 2000)
10.5(a) --First Amendment to Restated and Consolidated Credit Agreement dated October 9, 2001 by and
between the Registrant and a lending group lead by Bank One, Oklahoma, N.A. as filed herewith.
10.5(b) --Second Amendment to Restated and Consolidated Credit Agreement dated November 21, 2001 by
and between the Registrant and a lending group lead by Bank One, Oklahoma, N.A. (incorporated
by reference to Exhibit 10.1 in the Registrant's Form 8-K filed with the SEC on January 15, 2002)
10.6 --Stock Purchase Agreement among Coral Reserves Group, Ltd., Coral Reserves, Inc., Coral
Reserves Energy Corp. and Michael Mewbourn dated November 30, 1998 (Exhibit 10.10 in
Form S-4)
10.7** --Employment Agreement dated November 1, 2000 between Anthony "Skeeter" Lasuzzo and
Canaan Energy Corporation (incorporated by reference to Exhibit 10.7 in the Registrant's Form
10-K filed with the SEC for the year ending December 31, 2000).
10.7(a) --Letter agreement effective March 12, 2002 between Anthony "Skeeter" Lasuzzo and Canaan
Energy Corporation confirming termination of employment and resignation as a Board member of
Mr. Lasuzzo and filed herewith.
10.8 --Office Lease at Leadership Square, Oklahoma City, OK, Between LSQ Investors, L.L.C.
(Landlord) and Canaan Energy Corporation (Tenant) dated December 4, 2000 (incorporated by
reference to Exhibit 10.8 in Registrant's Form 10-K filed with the SEC for the year ending
December 31, 2000)
Exhibit
Number Description
- ------ -----------
10.8(a) --First Amendment to Office Lease at Leadership Square, Oklahoma City, OK, between LSQ
Investors, L.L.C. (Landlord) and Canaan Energy Corporation (Tenant) dated July 18, 2001 and
filed herewith.
10.8(b) --Second Amendment to Office Lease at Leadership Square, Oklahoma City, OK, between LSQ
Investors, L.L.C. (Landlord) and Canaan Energy Corporation (Tenant) dated October 8, 2001 and
filed herewith.
- --------
** Management contract or compensatory plan or arrangement required to be filed
as an exhibit to this report.