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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR QUARTERLY PERIOD ENDED JUNE 30, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER: 000-31819
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CANAAN ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)
OKLAHOMA 73-1300132
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
211 NORTH ROBINSON, SUITE 1000N, OKLAHOMA CITY, OKLAHOMA 73102
(Address of principal executive offices, including zip code)
(405) 604-9200
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock as of the latest practicable date:
At August 10, 2001, Canaan Energy Corporation had outstanding 4,916,315
shares of Common Stock, par value $.01
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
CANAAN ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
JUNE 30, DECEMBER 31,
2001 2000
------------ ------------
ASSETS (UNAUDITED)
Current assets:
Cash and cash equivalents $ 10,194,371 $ 6,481,550
Accounts receivable 7,639,802 7,569,328
Income tax receivable 260,300 --
Other assets 92,057 101,726
------------ ------------
Total current assets 18,186,530 14,152,604
------------ ------------
Property and equipment, at cost, based
on the full cost method of accounting
for oil and natural gas properties 97,859,211 91,690,784
Less accumulated depreciation
and amortization (23,656,130) (20,258,478)
------------ ------------
74,203,081 71,432,306
------------ ------------
Other assets 155,033 188,255
------------ ------------
Total assets $ 92,544,644 $ 85,773,165
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade $ 3,095,772 $ 1,324,812
Revenue and royalties due to others 2,190,087 2,433,547
Accrued expenses 14,175 99,536
Income taxes payable -- 1,105,907
------------ ------------
Total current liabilities 5,300,034 4,963,802
------------ ------------
Long-term debt 33,964,683 33,964,683
Deferred income taxes 11,749,000 10,514,000
Stockholders' equity:
Common stock, $0.01 par value; 50,000,000
shares authorized, 4,931,815 and
4,916,315 issued and outstanding
respectively, in 2001 and 2000 49,318 49,318
Additional paid-in capital 57,027,781 57,027,781
Treasury stock, at cost, 15,500 shares
in 2001 and 2000 (146,281) (146,281)
Retained earnings (accumulated deficit) (15,399,891) (20,600,138)
------------ ------------
Total stockholders' equity 41,530,927 36,330,680
------------ ------------
Total liabilities and stockholders' equity $ 92,544,644 $ 85,773,165
============ ============
See accompanying notes to financial statements.
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CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------ ------------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(UNAUDITED) (UNAUDITED)
REVENUES:
Oil and natural gas sales $ 7,347,687 $ 3,211,291 $18,768,699 $ 6,332,007
COSTS AND EXPENSES:
Lease operating 1,185,250 462,851 2,283,239 892,762
Production taxes 444,146 257,526 1,272,151 519,409
Depreciation, depletion and amortization 1,672,419 593,596 3,397,653 1,217,161
General and administrative expenses 1,066,254 323,835 2,145,665 880,477
Interest expense 703,781 174,460 1,533,750 330,990
----------- ----------- ----------- -----------
Total costs and expenses 5,071,850 1,812,268 10,632,458 3,840,799
----------- ----------- ----------- -----------
Other income, principally interest 107,578 25,238 234,006 54,517
----------- ----------- ----------- -----------
Earnings before income taxes 2,383,415 1,424,261 8,370,247 2,545,725
Income taxes 914,000 16,918 3,170,000 25,918
----------- ----------- ----------- -----------
NET EARNINGS $ 1,469,415 $ 1,407,343 $ 5,200,247 $ 2,519,807
=========== =========== =========== ===========
EARNINGS PER AVERAGE COMMON SHARE
OUTSTANDING - BASIC $ 0.30 $ 0.39 $ 1.06 $ 0.70
=========== =========== =========== ===========
EARNINGS PER AVERAGE COMMON SHARE
OUTSTANDING - DILUTED $ 0.30 $ 0.39 $ 1.05 $ 0.70
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
BASIC 4,916,315 3,621,219 4,916,315 3,621,219
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
DILUTED 4,977,251 3,621,219 4,959,652 3,621,219
=========== =========== =========== ===========
See accompanying notes to financial statements.
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CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30,
------------------------------ -------------------------------
2001 2000 2001 2000
----------- ----------- ----------- -----------
(UNAUDITED) (UNAUDITED)
Net earnings $ 1,438,345 $ 1,407,343 $ 5,169,177 $ 2,519,807
Other comprehensive income, net of tax:
Cumulative effect of change in
accounting principle -- -- (1,578,899) --
Derivative losses reclassified
into oil and natural gas sales 272,434 -- 1,034,160 --
Change in fair value of
derivative instruments 19,566 -- 544,739 --
----------- ----------- ----------- -----------
Comprehensive income $ 1,730,345 $ 1,407,343 $ 5,169,177 $ 2,519,807
=========== =========== =========== ===========
See accompanying notes to financial statements.
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CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
SIX MONTHS ENDED JUNE 30,
---------------------------------
2001 2000
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(UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 5,200,247 $ 2,519,807
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation, depletion and amortization 3,397,653 1,217,161
Deferred income tax expense (benefit) 1,235,000 (10,000)
Amortization of debt issuance costs 33,222 --
Forgiveness of subscription receivable -- 5,476
Increase in accounts receivable and
other assets (60,805) (1,062,561)
Increase in accounts payable, accrued expenses and
other liabilities 75,932 245,731
------------ ------------
Net cash provided by operating activities 9,881,249 2,915,614
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (6,168,428) (267,180)
Repayments on notes receivable -- 337,500
Net proceeds from affiliate contract services -- 42,415
Costs related to business combinations -- 286,403
------------ ------------
Net cash provided by (used in) investing activities (6,168,428) 399,138
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on long-term debt -- 500,000
Distributions to partners -- (3,843,657)
------------ ------------
Net cash used in financing activities -- (3,343,657)
------------ ------------
Net increase (decrease) in cash and cash equivalents 3,712,821 (28,905)
Cash and cash equivalents at beginning of period 6,481,550 1,495,035
------------ ------------
Cash and cash equivalents at end of period $ 10,194,371 $ 1,466,130
============ ============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for income taxes $ 3,431,500 $ 2,918
============ ============
Cash payments for interest $ 1,500,528 $ 330,990
============ ============
See accompanying notes to financial statements.
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CANAAN ENERGY CORPORATION
Notes to Financial Statements
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 accompanying consolidated financial statements and notes thereto have been
prepared pursuant to the rules and regulations of the Securities and Exchange
Commission. Accordingly, certain disclosures normally included in financial
statements prepared in accordance with accounting principles generally accepted
in the United States of America have been omitted. The accompanying consolidated
financial statements and notes thereto should be read in conjunction with the
consolidated financial statements and notes thereto included in Canaan's 2000
Annual Report on Form 10-K.
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.
In the opinion of management, the accompanying unaudited financial statements as
of June 30, 2001, and for the three and six months ended June 30, 2000 and 2001,
reflect adjustments (which were normal and recurring) which, in the opinion of
management, are necessary for a fair statement of the financial position and
results of operations of the interim periods presented. Results for the three
and six months ended June 30, 2001, are not necessarily indicative of results
expected for the full year.
2. LONG-TERM DEBT
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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 provided for a borrowing base of $43,500,000 based on the Company's
oil and gas reserves, with the borrowing base reducing monthly at the rate of
$535,000 beginning on December 1, 2000. The credit facility has a maturity date
of October 2003, and provides for semiannual redetermination of the borrowing
base. In June 2001, the borrowing base was increased to $45,000,000 with no
scheduled monthly reductions. The terms of the facility give the Company the
option of either borrowing at the LIBOR rate plus a margin of 1.5% to 2.25% 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. The interest rate was 7.5% as of June 30, 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 gas properties. 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 Company's borrowings under this facility represent all of
its borrowings as of June 30, 2001.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
On January 1, 2001, the Company adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Certain Hedging Activities and SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities, an Amendment of SFAS No. 133." SFAS
No. 133 and SFAS No. 138 require that all derivative instruments be recorded on
the balance sheet at their respective fair values. In accordance with the
transition provisions of SFAS No. 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 qualify for hedge accounting treatment are
"cash-flow" hedges. The Company designates its cash flow hedge derivatives on
the date the derivative contract is entered into. The Company formally documents
all relationships between hedging instruments and hedged items, as well as its
risk-management objective and strategy for undertaking various hedge
transactions. This process includes linking all derivatives that are designated
as cash-flow hedges to specific forecasted transactions. The Company also
assesses, both at the hedge's inception and on an ongoing basis, whether the
derivatives that are used in hedging transactions are 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 exposes 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 are usually
placed with counterparties that the Company believes are minimal credit risks.
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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.
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 natural 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 have 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 has been
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 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 natural gas. For the six months ended June 30,
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).
4. EARNINGS PER SHARE
All 493,750 stock options that have been granted through June 30, 2001 are
included in the determination of the common shares outstanding on a diluted
basis for June 30, 2001. There are no other dilutive instruments outstanding.
The dilutive effect of the stock options for the three and six months periods
ended June 30, 2001 were an addition of 60,936 and 43,337 shares, respectively.
No stock options or other dilutive instruments were outstanding in the 2000
period.
5. INCOME TAX EXPENSE
As discussed in Note 1, the acquisition of the Partnerships was accounted for as
a reorganization of interests under common control in a manner similar to a
pooling of interests. Accordingly, the results of operations of the partnerships
have been included with Canaan's results for the first six months of both 2001
and 2000. However, any income tax liability associated with the operations of
the Partnerships did not arise until the actual consummation of the transactions
on October 23, 2000. Had the transactions been completed on January 1, 2000,
approximately $524,000 and $941,000 of additional income tax expense would have
been recognized for the three and six month periods ended June 30, 2000,
resulting in net earnings of approximately $883,000 and $1,579,000,
respectively.
6. RECENT ISSUED ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board issued new
pronouncements: Statement 141, Business Combinations, Statement 142, Goodwill
and Other Intangible Assets, and Statement 143,
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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. Statements 141 and 142 will not apply to the Company unless
it enters into a future business combination. The Company is currently assessing
the impact of Statement 143 on its financial condition and results of
operations.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
SELECTED OPERATING DATA:
<Table>
<Caption>
---------------------------------------------------
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
2001 2000 2001 2000
--------- --------- --------- ---------
(UNAUDITED) (UNAUDITED)
Oil production (MMBls) 46 29 89 75
Natural gas production (MMcf 1,560 897 3,245 1,784
Gas equivalent production (MMcfe) 1,836 1,069 3,781 2,236
Average oil price (per Bbl) before
hedging contract settlements $ 28.14 $ 26.16 $ 27.67 $ 24.04
Adjustment for hedging contract
settlements -- (5.70) -- (4.33)
--------- --------- --------- ---------
Average oil price (per Bbl) $ 28.14 $ 20.46 $ 27.67 $ 19.71
Average gas price (per Mcf) before
hedging contract settlements $ 4.14 $ 3.28 $ 5.53 $ 2.82
Adjustment for hedging contract
settlements (0.27) (0.37) (0.52) (0.16)
--------- --------- --------- ---------
Average gas price (per Mcf) $ 3.87 $ 2.91 $ 5.01 $ 2.66
Average gas equivalent price (per Mcfe)
before hedging contract settlements $ 4.23 $ 3.45 $ 5.40 $ 3.06
Adjustment for hedging contract
settlements (0.23) (0.47) (0.44) (0.25)
--------- --------- --------- ---------
Average gas equivalent price (per Mcfe) $ 4.00 $ 2.98 $ 4.96 $ 2.81
OPERATING COSTS (per Mcfe):
Lease operating expense $ 0.65 $ 0.43 $ 0.60 $ 0.40
Production taxes 0.24 0.24 0.34 0.23
General and administrative expense 0.58 0.30 0.57 0.39
Depreciation, depletion and
amortization -- oil & gas properties 0.89 0.56 0.88 0.54
</Table>
The following discussion is intended to assist in an understanding of Canaan's
financial position as of June 30, 2001 and December 31, 2000, and its results of
operations for the three-month and six-month periods ended June 30, 2001. It is
presumed that readers have read or have access to Canaan's 2000 Annual Report on
Form 10-K.
GENERAL
Canaan is an Oklahoma corporation formerly known as Coral Reserves Group, Ltd.,
organized in March of 1987 for the purpose of originating, evaluating,
engineering, negotiating, closing and managing producing oil and 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 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 shares to the amount
allocated to it under the terms of the combination transaction. We have 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 to
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
since their acquisition in October 2000. Therefore, the three-month and
six-month period ended June 30, 2000 do not include the operations of Indian or
CSI.
THREE MONTHS ENDED JUNE 30, 2001 COMPARED WITH THE THREE MONTHS ENDED JUNE 30,
2000
For the three months ended June 30, 2001, we recorded net earnings of $1,469,415
or $0.30 per share on total revenues of $7,347,687. These results compare with
net earnings for the three months ended June 30, 2000 of $1,407,343 or $0.39 per
share on total revenues of $3,211,291. The 4% increase in net earnings was
primarily due to higher oil and natural gas prices received during the second
quarter of 2001, as well as increased natural gas production attributable to the
acquisition of Indian, as more fully described below. The effects of higher
average prices and production were offset by higher operating and general and
administrative costs. Additionally, income tax expense increased $897,000 for
the second quarter of 2001 compared to the comparable period of 2000. As
previously discussed, results of operations have been reported as if we owned
the Partnerships and the General Partners for the entire quarter ended June 30,
2000. However, any income tax liability associated with the operations of
Partnerships and the General Partners did not arise until the actual
consummation of the transactions in October 2000. Had the
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transactions been completed on January 1, 2000, approximately $524,000 of
additional income tax expense would have been recognized for the three month
period ended June 30, 2000, resulting in net earnings of approximately $883,000
or $0.24 per share.
Revenues. Revenues from oil and natural gas sales increased by 129%, or
$4,136,396 to $7,347,687 for the three months ended June 30, 2001, as compared
to $3,211,291 for the same period of 2000. 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 2001.
Natural gas production increased 74% to 1,560,310 Mcf during the three months
ended June 30, 2001 as compared to 896,831 Mcf for the second quarter of 2000.
Oil production increased 60% from 28,711 Bbls during the three months ended June
30, 2000 to 46,019 Bbls for the three months ended June 30, 2001. The average
price realized for natural gas increased by 33%, or $0.96 per Mcf, to $3.87 per
Mcf during the three months ended June 30, 2001, as compared to $2.91 per Mcf
for the same period of 2000. Hedging losses on second quarter produced volumes
decreased our average price for natural gas by $0.31 and $0.37 per Mcf during
the three months ended June 30, 2001, and 2000, respectively. The average price
realized for oil increased by 38%, or $7.68 per Bbl to $28.14 during the three
months ended June 30, 2001, as compared to $20.46 per Bbl for the same period of
2000. Hedging contract settlements decreased our average price for oil by $5.70
per Bbl during the three months ended June 30, 2000. Oil hedging contract
arrangements expired in December 2000, while existing natural gas hedging
contract arrangements, covering approximately 18% of our daily natural gas
production, expired in May 2001.
Lease operating expense. Lease operating expense increased by 156% or $722,399
to $1,185,250 for the three months ended June 30, 2001, as compared to $462,851
for the same period of 2000. The majority of this increase is attributable to
the acquisition of the Indian properties. The remaining increase was due
primarily to repairs and workovers. On an Mcfe basis, lease operating expense
increased 51% during the three months ended June 30, 2001 to $0.65 per Mcfe from
$0.43 per Mcfe during the same period in 2000. This increase is primarily
attributable to higher operating costs per Mcfe on the acquired Indian
properties, as well as higher costs associated with workovers in 2001.
Production taxes. Production taxes increased 72%, or $186,620 to $444,146 for
the three months ended June 30, 2001, as compared to $257,526 for the same
period of 2000. This increase was primarily the result of increased oil and
natural gas revenues in 2001, as discussed previously. As a percentage of
revenues, the production taxes were 6.0% and 8.0% for the three-month periods
ended June 30, 2001 and 2000, respectively. 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 187%, or $1,078,823 to $1,672,419 for the three months ended June 30,
2001, as compared to $593,596 for the same period of 2000. Depreciation and
amortization expense from oil and natural gas properties increased 178%, or
$1,050,271 to $1,638,867 during the three months ended June 30, 2001 compared to
$588,596 for the comparable period of 2000, due to the acquisition of the Indian
properties, and the associated increased production during the three months
ended June 30, 2001. Amortization expense per equivalent Mcf was $0.89 for the
three months ended June 30, 2001 versus $0.56 for the same period of 2000. This
increase in amortization per equivalent Mcf was due primarily to the purchase of
Indian in October 2000. Depreciation resulting from non-oil and natural gas
properties increased $33,551 as a result of assets added during the year,
including those added through the acquisition of Indian.
General and administrative expense. General and administrative expense increased
$742,419 or 229% to $1,066,254 during the three months ended June 30, 2001 as
compared to $323,835 for the same period of 2000. The principal components of
the increase were salaries and related expenses, which increased $553,308 due to
a significant expansion of our professional staff in anticipation of future
growth in drilling and acquisition activities. General and administrative
expenses per equivalent Mcf were $0.58 for the three months ended June 30, 2001,
compared to $0.30 for the same
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period of 2000, a 93% increase. We believe our general and administrative
expense per equivalent Mcf will decline as we increase production in future
periods.
Interest expense. Interest expense increased $529,321 or 303% to $703,781 during
the three months ended June 30, 2001 from $174,460 during the same period of
2000. In October 2000 we assumed $23,639,994 in additional bank debt from the
Indian acquisition. The 8.84% average interest rate associated with our bank
debt decreased during the three months ended June 30, 2001 as compared to the
9.3% average interest rate for the same period of 2000.
Income taxes. Income tax expense increased $897,082 to $914,000 for the three
months ended June 30, 2001 as compared to $16,918 for the same period of 2000.
As discussed earlier, this increase is primarily attributable to the fact that
Partnership income and expenses were recorded for the entire three months ended
June 30, 2000, but we had no tax liability for Partnership related operations
until the consummation of the acquisition in October 2000. Our effective tax
rate was 38% and 1% for the three months ended June 30, 2001 and 2000,
respectively. On a pro forma basis, assuming the income tax from the
Partnerships was fully taxed at corporate rates and the deferred income tax
assets and liabilities had been recognized prior to 2000, our effective tax rate
for the first three months of 2000 would have approximated the rate for 2001.
SIX MONTHS ENDED JUNE 30, 2001 COMPARED WITH THE SIX MONTHS ENDED JUNE 30, 2000
For the six months ended June 30, 2001, we recorded net earnings of $5,200,247
or $1.06 per share on total revenues of $18,768,699. These results compare with
net earnings for the six months ended June 30, 2000 of $2,519,807 or $0.70 per
share on total revenues of $6,332,007. This 106% increase in net earnings was
primarily due to higher oil and natural gas prices received during the first
half of 2001, as well as increased natural gas production attributable to the
acquisition of Indian, as more fully described below. The effects of higher
average prices and production were offset by higher operating and general and
administrative costs. Additionally, income tax expense increased $3,144,082 for
the first six months of 2001 compared to the comparable period of 2000. As
previously discussed, results of operations have been reported as if we owned
the Partnerships and the General Partners for the entire six months ended June
30, 2000. However, any income tax liability associated with the operations of
Partnerships and the General Partners did not arise until the actual
consummation of the transactions in October 2000. Had the transactions been
completed on January 1, 2000, approximately $941,000 of additional income tax
expense would have been recognized for the six month period ended June 30, 2000,
resulting in net earnings of approximately $1,579,000 or $0.44 per share.
Revenues. Revenues from oil and natural gas sales increased by 196%, or
$12,436,692 to $18,768,699 for the six months ended June 30, 2001, as compared
to $6,332,007 for the same period of 2000. 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 2001.
Natural gas production increased 82% to 3,245,123 Mcf during the six months
ended June 30, 2001 as compared to 1,783,685 Mcf for the first three months of
2000. Oil production increased 18% from 75,443 Bbls during the six months ended
June 30, 2000 to 89,266 Bbls for the six months ended June 30, 2001. The average
price realized for natural gas increased by 88%, or $2.35 per Mcf, to $5.01 per
Mcf during the six months ended June 30, 2001, as compared to $2.66 per Mcf for
the same period of 2000. Hedging losses for the six months ended June 30, 2001
and 2000 decreased our average price for natural gas by $0.53 and $0.16 per Mcf,
respectively. The average price realized for oil increased 40%, or $7.96 per Bbl
to $27.67 during the six months ended June 30, 2001, as compared to $19.71 per
Bbl for the same period of 2000. Hedging contract settlements decreased our
average price for oil by $4.33 per Bbl during the six months ended June 30,
2000. Oil hedging contract arrangements expired in December 2000, while existing
natural gas hedging contract arrangements, covering approximately 18% of our
daily natural gas production, expired in May 2001.
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Lease operating expense. Lease operating expense increased by 156% or $1,390,477
to $2,283,239 for the six months ended June 30, 2001, as compared to $892,762
for the same period of 2000. The majority of this increase is attributable to
the acquisition of the Indian properties. The remaining increase was due
primarily to repairs and workovers. On an Mcfe basis, lease operating expense
increased 50% during the six months ended June 30, 2001 to $0.60 per Mcfe from
$0.40 per Mcfe during the same period in 2000. This increase is primarily
attributable to higher operating costs per Mcfe on the acquired Indian
properties, as well as to higher costs associated with workovers in 2001.
Production taxes. Production taxes increased 145%, or $752,742 to $1,272,151 for
the six months ended June 30, 2001, as compared to $519,409 for the same period
of 2000. This increase was primarily the result of increased oil and natural gas
revenues in 2000, as discussed previously. As a percentage of revenues,
production taxes were 6.8% and 8.2% for the six-month periods ended June 30,
2001 and 2000, respectively. 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 179%, or $2,180,492 to $3,397,653 for the six months ended June 30,
2001, as compared to $1,217,161 for the same period of 2000. Depreciation and
amortization expense from oil and natural gas properties increased 176%, or
$2,123,388 to $3,330,549 during the six months ended June 30, 2001 compared to
$1,207,161 for the comparable period of 2000, due to the acquisition of the
Indian properties, and the associated increased production during the six months
ended June 30, 2001. Amortization expense per equivalent Mcf was $0.88 for the
six months ended June 30, 2001 versus $0.54 for the same period of 2000. This
increase in amortization per equivalent Mcf was due primarily to the purchase of
Indian in October 2000. Depreciation resulting from non-oil and natural gas
properties increased $67,104 as a result of assets added during the year,
including those added through the acquisition of Indian.
General and administrative expense. General and administrative expense increased
$1,265,188 or 144% to $2,145,665 during the six months ended June 30, 2001 as
compared to $880,477 for the same period of 2000. The principal components of
the increase were salaries and related expenses, which increased $626,045 due to
a significant expansion of our professional staff in anticipation of future
growth in drilling and acquisition activities. General and administrative
expenses per equivalent Mcf were $0.57 for the six months ended June 30, 2001,
compared to $0.39 for the same period of 2000, a 46% increase. We believe our
general and administrative expense per equivalent Mcf will decline as we
increase production in future periods.
Interest expense. Interest expense increased $1,202,760 or 363% to $1,533,750
during the six months ended June 30, 2001 from $330,990 during the same period
of 2000. In October 2000 we assumed $23,639,994 in additional bank debt from the
Indian acquisition. The 9.15% average interest rate associated with our bank
debt increased during the six months ended June 30, 2001 as compared to the 9.0%
average interest rate for the same period of 2000, further contributing to the
increase in interest expense.
Income taxes. Income tax expense increased $3,144,082 to $3,170,000 for the six
months ended June 30, 2001 as compared to $25,918 for the same period of 2000.
As discussed earlier, this increase is primarily attributable to the fact that
Partnership income and expenses were recorded for the entire six months ended
June 30, 2000, but we had no tax liability for Partnership related operations
until the consummation of the acquisition in October 2000. Our effective tax
rate was 38% and 1% for the six months ended June 30, 2001 and 2000,
respectively. On a pro forma basis, assuming the income tax from the
Partnerships was fully taxed at corporate rates and the deferred income tax
assets and liabilities had been recognized prior to 2000, our effective tax rate
for the first three months of 2000 would have approximated the rate for 2001.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
As of June 30, 2001 and December 31, 2000, we had cash balances of $10,194,371,
and $6,481,550,
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respectively. Working capital increased from $9,188,802 at December 31, 2000 to
$12,886,496 at June 30, 2001, due principally to higher oil and natural gas
prices.
For the six months ended June 30, 2001, net cash provided by operating
activities was $9,881,249 as compared to cash provided of $2,915,614 for the six
months ended June 30, 2000. This increase was primarily the result of improved
pre-tax earnings. EBITDA increased $9,207,774 or 225% from $4,093,876 for the
six months ended June 31, 2000 to $13,301,650 for the six months ended June 30,
2001.
Net cash used in investing activities for the six months ended June 30, 2001 was
$6,168,428 as compared to $399,138 provided by investing activities during the
six months ended June 30, 2000, resulting in a $6,567,566 increase in cash used.
This change was primarily the result of increased capital expenditures related
to our 2001 drilling program, which were funded entirely by cash flow from
operations.
Net cash used in financing activities was zero for the six months ended June 30,
2001 as compared with $3,343,657 during the same period of 2000. Cash used in
financing activities for the six months ended June 30, 2000 consisted of
distributions to former limited partners of the Partnerships totaling $3,843,657
offset by draws on our bank credit facility of $500,000.
Capital expenditures. Our capital expenditures to date have focused primarily on
the development of oil and natural gas properties in the Mid Continent Area, as
well as acquisitions of proved developed producing oil and natural gas
properties located in the same area. Our projected capital expenditures for 2001
are estimated to be $9,400,000 for development drilling and $2,100,000 for other
drilling. Actual expenditures may vary depending on the results of our drilling
program. We expended $6,168,428 during the six months ended June 30, 2001.
During 2001 we will also 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. In October 2000 we entered into a new secured
revolving credit facility with a group of banks which provides for a borrowing
base of $43,500,000 based on our oil and gas reserves, with the borrowing base
reducing monthly at the rate of $535,000 beginning on December 1, 2000. The
credit facility has a maturity date of October 2003, and provides for semiannual
redetermination of the borrowing base. In June 2001, the borrowing base was
increased to $45,000,000 with no scheduled monthly reductions. The terms of the
facility give us the option of either borrowing at the LIBOR rate plus a margin
of 1.5% to 2.25% 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. Our available credit under this facility was
approximately $11 million at June 30, 2001. Our long term debt to equity ratio
improved to .82:1 as of June 30, 2001 from .93:1 as of December 31, 2000. We
intend to meet our 2001 capital requirements primarily from existing cash
balances, cash flow from operations, and funding under our bank credit facility.
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 our business plan would
be delayed and, accordingly, our growth strategy could be adversely affected.
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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 ("Canaan" or "Companies"), 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. See our Annual Report on Form 10-K for the year
ended December 31, 2000 for a more complete discussion of these risks. 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.
ITEM 3. 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 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.
Commodity Price Risk. Canaan's major market risk exposure will be in the pricing
applicable to its oil and 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 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 gas production through financial
price swaps whereby the Company receives a fixed price for production and pays a
variable market price to the contract counterparty. These financial price
hedging activities are intended to reduce exposure to oil and gas price
fluctuations. Realized gains or losses from the settlement of these financial
hedging instruments are recognized in oil and gas sales when the associated
production occurs. The gains and losses realized as a result of these hedging
activities are substantially offset in the cash market when the hedged commodity
is delivered.
At June 30, 2001, Canaan did not have any financial hedging arrangements.
Interest Rate Risk. Canaan had long-term debt outstanding of $34.0 million as of
June 30, 2001. All of the debt outstanding at June 30, 2001 bears interest at
floating rates which averaged 7.5% as of June 30, 2001. A 10% increase in
short-term interest rates on the floating-rate debt outstanding at June 30, 2001
would equal approximately 75 basis points. Such an increase in interest rates
would have increased Canaan's interest expense by approximately $255,000
assuming amounts borrowed at June 30, 2001 were outstanding for a twelve month
period.
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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.
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PART II -- OTHER INFORMATION
ITEMS 1 - 3
Not applicable.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Annual Meeting of Shareholders of the Company held on May 22, 2001, the
shareholders elected certain directors to serve until the 2004 Annual Meeting of
Shareholders.
Votes cast were as follows:
For Against Abstained
--------- ------- ---------
Election as a Director of the Company of:
Michael Cross 3,352,863 0 7,894
Thomas Henson 3,353,112 0 7,645
Michael Mewbourn 3,355,082 0 5,675
Additionally, on May 22, 2001 at the Annual Meeting of Shareholders of the
Company, the Board of Directors, by power of the Company's corporate bylaws,
expanded the size of the Board from seven to eight members. The Board
simultaneously approved the appointment of Anthony Lasuzzo to fill the newly
created vacancy.
The directors elected at the meeting will serve a 3 year term until the 2004
annual meeting of shareholders. Directors who continue in office after the
meeting and the year of the expiration of their terms are as follows: 2002-John
Penton, Mischa Gorkuscha; 2003-Leo E. Woodard, Randy Harp, Anthony Lasuzzo.
ITEM 5
Not Applicable
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CANAAN ENERGY CORPORATION
(Registrant)
Leo E. Woodard
Chairman and Chief Executive Officer
Michael S. Mewbourn
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 14, 2001
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