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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 SEPTEMBER 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
incorporation or organization) Identification No.)
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 November 13, 2001, Canaan Energy Corporation had outstanding
4,913,815 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
<Table>
<Caption>
SEPTEMBER 30, DECEMBER 31,
2001 2000
------------- -------------
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents $ 6,653,260 $ 6,481,550
Accounts receivable 4,873,967 7,569,328
Income tax receivable 3,036,161 --
Other assets 30,057 101,726
------------- -------------
Total current assets 14,593,445 14,152,604
------------- -------------
Property and equipment, at cost, based on the full cost method
of accounting for oil and natural gas properties 102,765,356 91,690,784
Less accumulated depreciation and amortization (25,292,993) (20,258,478)
------------- -------------
77,472,363 71,432,306
------------- -------------
Other assets 138,422 188,255
------------- -------------
Total assets $ 92,204,230 $ 85,773,165
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade $ 1,023,654 $ 1,324,812
Revenue and royalties due to others 1,822,724 2,433,547
Accrued expenses 72,368 99,536
Income taxes payable -- 1,105,907
------------- -------------
Total current liabilities 2,918,746 4,963,802
------------- -------------
Long-term debt 33,964,683 33,964,683
Deferred income taxes 14,156,764 10,514,000
Stockholders' equity:
Common stock, $0.01 par value; 50,000,000 shares
authorized, 4,931,815 and 4,913,815 issued and outstanding
in 2001, respectively, and 3,621,219 shares issued and
outstanding in 2000. 49,318 49,318
Additional paid-in capital 57,027,781 57,027,781
Treasury stock, at cost, 18,000 shares in 2001, and 15,500
shares in 2000 (163,647) (146,281)
Retained earnings (accumulated deficit) (15,749,415) (20,600,138)
------------- -------------
Total stockholders' equity 41,164,037 36,330,680
------------- -------------
Total liabilities and stockholders' equity $ 92,204,230 $ 85,773,165
============= =============
</Table>
See accompanying notes to financial statements.
2
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
2001 2000 2001 2000
------------ ------------ ------------ ------------
(UNAUDITED) (UNAUDITED)
REVENUES:
Oil and natural gas sales $ 4,492,919 $ 3,560,619 $ 23,261,618 $ 9,892,626
COSTS AND EXPENSES:
Lease operating 1,079,264 410,366 3,362,503 1,303,128
Production taxes 255,272 309,570 1,527,423 828,979
Depreciation, depletion and amortization 1,637,604 657,177 5,035,257 1,874,338
General and administrative expenses 1,555,322 507,019 3,700,987 1,387,496
Interest expense 594,019 188,524 2,127,769 519,514
------------ ------------ ------------ ------------
Total costs and expenses 5,121,481 2,072,656 15,753,939 5,913,455
------------ ------------ ------------ ------------
Other income, principally interest 82,038 26,971 316,044 81,488
------------ ------------ ------------ ------------
Earnings before income taxes (546,524) 1,514,934 7,823,723 4,060,659
Income tax expense (benefit) (197,000) 5,932 2,973,000 31,850
------------ ------------ ------------ ------------
NET EARNINGS (LOSS) $ (349,524) $ 1,509,002 $ 4,850,723 $ 4,028,809
============ ============ ============ ============
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
OUTSTANDING - BASIC $ (0.07) $ 0.42 $ 0.99 $ 1.11
============ ============ ============ ============
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
OUTSTANDING - DILUTED $ (0.07) $ 0.42 $ 0.98 $ 1.11
============ ============ ============ ============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
BASIC 4,916,183 3,621,219 4,916,271 3,621,219
============ ============ ============ ============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING -
DILUTED 4,916,183 3,621,219 4,958,228 3,621,219
============ ============ ============ ============
</Table>
See accompanying notes to financial statements.
3
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
<Table>
<Caption>
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30,
2001 2000 2001 2000
----------- ----------- ----------- -----------
(UNAUDITED) (UNAUDITED)
Net earnings (loss) $ (349,524) $ 1,509,002 $ 4,850,723 $ 4,028,809
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 -- -- 1,034,160 --
Change in fair value of derivative
instruments -- -- 544,739 --
----------- ----------- ----------- -----------
Comprehensive income (loss) $ (349,524) $ 1,509,002 $ 4,850,723 $ 4,028,809
=========== =========== =========== ===========
</Table>
See accompanying notes to financial statements.
4
CANAAN ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
NINE MONTHS ENDED SEPTEMBER 30,
2001 2000
----------- -----------
(UNAUDITED)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 4,850,723 $ 4,028,809
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation, depletion and amortization 5,035,257 1,874,338
Deferred income tax expense 3,642,764 1,500
Amortization of debt issuance costs 49,833 --
Forgiveness of subscription receivable -- 8,213
Increase in accounts receivable and other assets (269,873) (1,994,886)
Increase (Decrease) in accounts payable, accrued expenses and
other liabilities (2,045,056) 1,303,179
------------ -----------
Net cash provided by operating activities 11,263,648 5,221,153
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (11,074,572) (576,850)
Repayments on notes receivable -- 506,250
Net proceeds from affiliate contract services -- 72,425
------------ -----------
Net cash provided by (used in) investing activities (11,074,572) 1,825
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on long-term debt -- 625,000
Distributions to partners -- (4,513,057)
Purchase of treasury Stock (17,366) --
------------ -----------
Net cash used in financing activities (17,366) (3,888,057)
------------ -----------
Net increase in cash and cash equivalents 171,710 1,334,921
Cash and cash equivalents at beginning of period 6,481,550 1,495,035
------------ -----------
Cash and cash equivalents at end of period $ 6,653,260 $ 2,829,956
============ ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for income taxes $ 3,431,500 $ 13,350
============ ===========
Cash payments for interest $ 2,064,720 $ 347,236
============ ===========
</Table>
See accompanying notes to financial statements.
5
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 September 30, 2001, and for the three and nine months ended September 30,
2000 and 2001, reflect adjustments (which were normal and recurring) which, are
necessary for a fair statement of the financial position and results
6
of operations of the interim periods presented. Results for the three and nine
months ended September 30, 2001, are not necessarily indicative of results
expected for the full year.
2. 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 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 September 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 6.5% as of September 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 ranging 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 September 30, 2001.
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
September 30, 2001, the Company's Debt to EBITDA Ratio did not comply with that
required under the credit agreement. All other financial ratios calculated under
the credit agreement were within their required ranges. The Company has provided
projections to the bank group demonstrating its ability to meet this and all
other ratios through the next borrowing base review in May 2002, and accordingly
has received a waiver with respect to the Debt to EBITDA requirement as of
September 30, 2001.
3. OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for costs related to the
exploration and development of oil and gas properties. Under this method, all
such costs (productive and nonproductive) are capitalized and amortized on an
aggregate basis over the estimated lives of the properties using the
units-of-production method. These capitalized costs are subject to a ceiling
test, however, which limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved oil and gas reserves
discounted at 10% plus the lower of cost or market value of unproved properties.
The full cost ceiling is evaluated at the end of each quarter. If the costs to
be recovered exceed the ceiling, the excess is written-off as an expense unless
prices increase after the end of the quarter and prior to the
7
filing of the Company's financial statements. At September 30, 2001, our
unamortized costs of oil and gas properties, net of deferred income taxes,
exceeded this ceiling amount by approximately $20 million due to low gas prices
in effect on that date. The market price for gas at Henry Hub was $1.83 on
September 28, 2001, the last trading day prior to the end of the quarter. On
November 9, 2001, gas prices had increased to $2.92 and the ceiling increased
above the costs to be recovered. As a result, the Company was not required to
record a write-down of the value of its oil and gas properties.
4. 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 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.
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
8
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 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 nine months ended September 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). At September 30,
2001, the Company did not have any financial hedging arrangements.
5. EARNINGS PER SHARE
All of the 495,000 stock options (1,250 issued during the 3rd quarter) that have
been granted through September 30, 2001 are included in the determination of the
common shares outstanding on a diluted basis for September 30, 2001. There are
no other dilutive instruments outstanding. The dilutive effect of the stock
options for the nine months period ended September 30, 2001 was an addition of
41,957 shares. No options were considered for the three-month period ended
September 30, 2001 since the Company incurred a net loss. No stock options or
other dilutive instruments were outstanding in 2000.
6. 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 nine 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 $570,000 and $1,511,000 of additional income tax expense would
have been recognized for the three and nine month periods ended September 30,
2000, resulting in net earnings of approximately $939,002 and $2,517,809,
respectively.
7. 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, "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
9
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.
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 is required to adopt Statement 144 no later than the year beginning
after December 15, 2001, and plans to adopt its provisions for the quarter
ending March 31, 2002. Management does not expect the adoption of Statement 144
for long-lived assets held for use or for disposal to have a material impact on
the Company's financial statements because the Company utilizes the full-cost
method of accounting for oil and gas exploration and development activities and
the impairment assessment under Statement 144 is largely unchanged from
Statement 121.
10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
SELECTED OPERATING DATA:
<Table>
<Caption>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ------------------
2001 2000 2001 2000
------ ------ ------ ------
(UNAUDITED) (UNAUDITED)
Oil production (MMBbls) 44 31 133 96
Natural gas production (MMcf) 1,516 890 4,761 2,674
Gas equivalent production (MMcfe) 1,781 1,074 5,562 3,249
Average oil price (per Bbl) before 24.76 29.45 26.71 29.00
hedging contract settlements
Adjustment for hedging contract settlements -- (8.01) -- (5.98)
------ ------ ------ ------
Average oil price (per Bbl) 24.76 21.44 26.71 23.02
Average gas price (per Mcf) before hedging contract
settlements 2.24 4.22 4.49 3.28
Adjustment for hedging contract settlements -- (.96) (.35) (.41)
------ ------ ------ ------
Average gas price (per Mcf) 2.24 3.26 4.14 2.87
Average gas equivalent price (per Mcfe) before hedging
contract settlements 2.52 4.34 4.48 3.56
Adjustment for hedging contract settlements -- (1.02) (.30) (.51)
------ ------ ------ ------
Average gas equivalent price (per Mcfe) 2.52 3.32 4.18 3.05
OPERATING COSTS (PER MCFE):
Lease operating expense .61 .38 .60 .40
Production taxes .14 .29 .27 .26
General and administrative expense .87 .47 .67 .43
Depreciation, depletion and amortization - oil & gas
properties .90 .61 .89 .57
</Table>
The following discussion is intended to assist in obtaining an understanding of
Canaan's financial position as of September 30, 2001, and its results of
operations for the three-month and nine-month periods ended September 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
11
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. 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
nine-month periods ended September 30, 2000 do not include the operations of
Indian or CSI.
THREE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH THE THREE MONTHS ENDED
SEPTEMBER 30, 2000
For the three months ended September 30, 2001, we recorded a net loss of
$349,524 or $.07 per share on total revenues of $4,492,919. These results
compare with net earnings for the three months ended September 30, 2000 of
$1,509,002 or $.42 per share on total revenues of $3,560,619. The net loss was
primarily due to lower gas prices received during the third quarter of 2001 and
increased general and administrative expenses, as more fully described below. As
discussed above, results of operations have been reported as if the Company
owned the Partnerships and the General Partners for the entire quarter ended
September 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 $570,000 of additional income
tax expense would have been recognized for the three month period ended
September 30, 2000, resulting in net earnings of approximately $939,000 or $.26
per share.
Revenues. Revenues from oil and natural gas sales increased by 26%, or $932,300
to $4,492,919 for the three months ended September 30, 2001, as compared to
$3,560,619 for the same period of 2000. This increase was the result of higher
natural gas production, primarily attributable to the acquisition of Indian,
offset by a decrease in average gas prices received during 2001. Natural gas
production increased 626,052 Mcf or 70% to 1,516,259 Mcf during the three months
ended September 30, 2001 as compared to 890,207 Mcf for the third quarter of
2000. Oil production increased 44% or 13,488 Bbls from 30,684 Bbls during the
three months ended September 30, 2000 to 44,172 Bbls for the three months ended
12
September 30, 2001. The average price realized for natural gas decreased by 31%,
or $1.02 per Mcf, to $2.24 per Mcf during the three months ended September 30,
20001 as compared to $3.26 per Mcf for the same period of 2000. Hedging losses
on third quarter 2000 production decreased our average price for natural gas by
$.96 per Mcf. The average price realized for oil increased by 15%, or $3.31 per
Bbl to $24.76 during the three months ended September 30, 2001, as compared to
$21.44 per Bbl for the same period of 2000. Hedging contract settlements
decreased our average price for oil by $8.01 per Bbl during the three months
ended September 30, 2000. Oil hedging contract arrangements expired in December
2000.
Lease operating expense. Lease operating expense increased by 163% or $668,898
to $1,079,264 for the three months ended September 30, 2001, as compared to
$410,366 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 61% during the three months ended September 30, 2001 to $.61
per Mcfe from $.38 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 overall operating costs on all wells during
2001.
Production taxes. Production taxes decreased 18%, or $54,298 to $255,272 for the
three months ended September 30, 2001, as compared to $309,570 for the same
period of 2000. The decrease is due to the acquisition of Indian Oil Company.
The Indian properties were located in states that have lower production tax
rates than Canaan or the Partnerships. As a percentage of revenues, the
production taxes were 5.7% and 6.7% for the three-month periods ended September
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 149%, or $980,427 to $1,637,604 for the three months ended September
30, 2001, as compared to $657,177 for the same period of 2000. Depreciation and
amortization expense from oil and natural gas properties increased 145%, or
$946,453 to $1,600,716 during the three months ended September 30, 2001 compared
to $654,263 for the comparable period of 2000, due to the acquisition of the
Indian properties, and the associated increased production during the three
months ended September 30, 2001. Amortization expense per equivalent Mcf was
$.90 for the three months ended September 30, 2001 versus $.61 for the same
period of 2000. This increase in amortization per equivalent Mcf was due
primarily to the purchase of Indian in October 2000.
General and administrative expense. General and administrative expenses
increased $1,048,303 or 207% to $1,555,322 during the three months ended
September 30, 2001 as compared to $507,019 for the same period of 2000. The
principal components of the increase were salaries and related expenses, which
increased $534,205 due to a significant expansion of our professional staff in
anticipation of future growth in drilling and acquisition activities.
Additionally, we incurred nonrecurring professional fees related to tax research
and compliance as well as other services associated with the transition to a
publicly held company totaling approximately $338,000. General and
administrative expenses per equivalent Mcf were $.87 for the three months ended
September 30, 2001, compared to $.47 for the same period of 2000, a 85%
increase. We believe our general and administrative expense will decline on a
nominal basis in the upcoming quarters and on a per equivalent Mcf basis as we
increase production in future periods.
Interest expense. Interest expense increased $405,495 or 215% to $594,019 during
the three months ended September 30, 2001 from $188,524 during the same period
of 2000. In October 2000 we assumed $23,639,994 in additional bank debt from the
Indian acquisition. The 6.8% average interest rate associated with our bank debt
decreased during the three months ended September 30, 2001 as compared to the
9.3% average interest rate for the same period of 2000.
13
Income taxes. The income tax benefit was $197,000 for the three months ended
September 30, 2001 as compared to an income tax expense of $5,932 for the same
period of 2000. Partnership income and expenses were recorded for the entire
three months ended September 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
September 30, 2001 and 2000, respectively. On a pro forma basis, assuming the
income 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 three month period of 2000 would have approximated
the rate for 2001.
NINE MONTHS ENDED SEPTEMBER 30, 2001 COMPARED WITH THE NINE MONTHS ENDED
SEPTEMBER 30, 2000
For the nine months ended September 30, 2001, we had net earnings of $4,850,723
or $.99 per share on total revenues of $23,261,618. These results compare with
net earnings for the nine months ended September 30, 2000 of $4,028,809 or $1.11
per share on total revenues of $9,892,626. This 20% increase in net earnings was
primarily due to higher average oil and natural prices received during the first
nine months 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 $2,941,150 for
the first nine months of 2001 compared to the comparable period of 2000. Results
of operations have been reported as if we owned the Partnerships and the General
Partners for the entire nine months ended September 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 $1,511,000 of additional income tax expense would have been
recognized for the nine month period ended September 30, 2000, resulting in net
earnings of approximately $2,518,000 or $.70 per share.
Revenues. Revenues from oil and natural gas sales increased by 135%, or
$13,368,992 to $23,261,618 for the nine months ended September 30, 2001, as
compared to $9,892,626 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 78% to 4,761,382 Mcf during the nine months
ended September, 2001 as compared to 2,673,892 Mcf for the first nine months of
2000. Oil production increased 39% from 95,785 Bbls during the nine months ended
September 30, 2000 to 133,438 Bbls for the nine months ended September 30, 2001.
The average price realized for natural gas increased by 44%, or $1.27 per Mcf,
to $4.14 per Mcf during the nine months ended September 30, 2001, as compared to
$2.88 per Mcf for the same period of 2000. Hedging losses for the nine months
ended September 30, 2001 and 2000 decreased our average price for natural gas by
$.35 and $.41 per Mcf, respectively. The average price realized for oil
increased 16%, or $3.69 per Bbl to $26.71 during the nine months ended September
30, 2001, as compared to $23.02 per Bbl for the same period of 2000. Hedging
contract settlements decreased our average price for oil by $5.98 per Bbl during
the nine months ended September 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 158% or $2,059,375
to $3,362,503 for the nine months ended September 30, 2001, as compared to
$1,303,128 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 nine months ended September 30, 2001 to $.60
per Mcfe from $.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 overall operating costs on all wells during
2001.
14
Production taxes. Production taxes increased 84%, or $698,444 to $1,527,423 for
the nine months ended September 30, 2001, as compared to $828,979 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, production taxes were 6.1% and 7.2% for the nine-month periods ended
September 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 169%, or $3,160,919 to $5,035,257 for the nine months ended September
30, 2001, as compared to $1,874,338 for the same period of 2000. Depreciation
and amortization expense from oil and natural gas properties increased 164%, or
$3,065,671 to $4,931,265 during the nine months ended September 30, 2001
compared to $1,865,594 for the comparable period of 2000, due to the acquisition
of the Indian properties, and the associated increased production during the
nine months ended September 30, 2001. Amortization expense per equivalent Mcf
was $.89 for the nine months ended September 30, 2001 versus $.57 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 $95,248 as a result of assets added
during the year, including those added through the acquisition of Indian.
General and administrative expense. General and administrative expenses
increased $2,313,491 or 167% to $3,700,987 during the nine months ended
September 30, 2001 as compared to $1,387,496 for the same period of 2000. The
principal components of the increase were salaries and related expenses, which
increased $1,439,042 due to a significant expansion of our professional staff in
anticipation of future growth in drilling and acquisition activities.
Additionally, we incurred nonrecurring professional fees related to tax research
and compliance as well as other services associated with the transition to a
publicly held company totaling approximately $388,000. General and
administrative expenses per equivalent Mcf were $.67 for the nine months ended
September 30, 2001, compared to $.43 for the same period of 2000, a 56%
increase. We believe our general and administrative expense on a nominal basis
in the upcoming quarters will decline on a equivalent Mcf basis as we increase
production in future periods.
Interest expense. Interest expense increased $1,608,255 or 310% to $2,127,769
during the nine months ended September 30, 2001 from $519,514 during the same
period of 2000. In October 2000 we assumed $23,639,994 in additional bank debt
from the Indian acquisition. The 8.16% average interest rate associated with our
bank debt during the nine months ended September 30, 2001 was lower than the
9.0% average interest rate for the same period of 2000, slightly mitigating the
increase in interest expense.
Income taxes. Income tax expense increased $2,941,150 to $2,973,000 for the nine
months ended September 30, 2001 as compared to $31,850 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 nine months
ended September 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 September 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.
15
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
As of September 30, 2001 and December 31, 2000, we had cash balances of
$6,653,260, and $6,481,550 respectively. Working capital increased from
$9,188,802 at December 31, 2000 and $11,674,699 at September 30, 2001.
For the nine months ended September 30, 2001, net cash provided by operating
activities was $11,263,648 as compared to cash provided of $5,221,153 for the
nine months ended September 30, 2000. This increase was primarily the result of
improved pre-tax earnings. Earnings before interest, taxes, depreciation, and
amortization (EBITDA) increased $8,532,238 or 132% from $6,454,511 for the nine
months ended September 31, 2000 to $14,986,749 for the nine months ended
September 30, 2001. 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
measures as presented may not be comparable to other similarly titled measures
of other companies.
Net cash used in investing activities for the nine months ended September 30,
2001 was $11,074,572 as compared to $1,825 provided by investing activities
during the nine months ended September 30, 2000, resulting in a $11,076,397
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 $17,366 for the nine months ended
September 30, 2001 as compared with $3,888,057 during the same period of 2000.
Cash used in financing activities for the nine months ended September 30, 2000
consisted of distributions to former limited partners of the Partnerships
totaling $4,513,057 offset by draws on our bank credit facility of $625,000.
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 $12,100,000 for development drilling and $2,700,000 for
other drilling . Actual expenditures may vary depending on the results of our
drilling program. We expended $11,074,572 during the nine months ended September
30, 2001. During the remainder of 2001 we will also aggressively seek 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 September 30, 2001. 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. During the quarter ended September 30, 2001, the
Company incurred general and administrative expenses of a nonrecurring nature in
the amount of approximately $388,000. These expenses, coupled with declining oil
and gas prices caused the Company's Debt to EBITDA ratio to rise above the
required 3.00 to 1. All other financial ratios calculated under the credit
agreement were within their required ranges. EBITDA, as defined in the credit
agreement, is calculated by annualizing the current quarter, and as a result,
these factors are magnified in the resulting ratio. The Company has provided
projections to the bank group demonstrating its ability to meet this and all
other ratios through the next borrowing base review in May 2002, and accordingly
has received a waiver with respect to the Debt to EBITDA requirement as of
September 30, 2001. Our long term debt to equity ratio decreased to .83 as of
September 30, 2001 from .93 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
16
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.
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.
17
At September 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
September 30, 2001. All of the debt outstanding at September 30, 2001 bears
interest at floating rates which averaged 6.5% as of September 30, 2001. A 10%
increase in short-term interest rates on the floating-rate debt outstanding at
September 30, 2001 would equal approximately 65 basis points. Such an increase
in interest rates would increase Canaan's annual interest expense by
approximately $220,000 assuming amounts borrowed at September 30, 2001 were
outstanding for a twelve month period.
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.
18
PART II -- OTHER INFORMATION
ITEMS 1-5
Not applicable.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
None.
(b) Reports on Form 8-K
None.
19
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)
/s/ LEO E. WOODARD
------------------------------------
Leo E. Woodard
Chairman and Chief Executive Officer
/s/ MICHAEL S. MEWBOURN
------------------------------------
Michael S. Mewbourn
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 13, 2001
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