10-Q 1 d89704e10-q.txt FORM 10-Q FOR QUARTER ENDED JUNE 30, 2001 1 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ----------- 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 ----------- 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 2 PART I. FINANCIAL INFORMATION Item 1. Financial Statements CANAAN ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS

See accompanying notes to financial statements. -2- 3 CANAAN ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to financial statements. -3- 4 CANAAN ENERGY CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See accompanying notes to financial statements. -4- 5 CANAAN ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to financial statements. -5- 6 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 -6- 7 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. -7- 8 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, -8- 9 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. -9- 10 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS SELECTED OPERATING DATA:

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 -10- 11 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 -11- 12 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. -12- 13 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, -13- 14 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. -14- 15 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. -15- 16 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. -16- 17 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:

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. -17- 18 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 -18-

CANAAN ENERGY CORP 10-Q