FORM 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

X		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
		THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended September 30, 2002

		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 0-18691

NORTH COAST ENERGY, INC.

(Exact name of Registrant as specified in its charter)


Delaware		34-1594000
(State of incorporation)		(I.R.S. Employer Identification No.)

1993 Case Parkway
Twinsburg, Ohio		44087-2343
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (330) 425-2330

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 .

APPLICABLE ONLY TO CORPORATE ISSUERS:

Indicate the number of shares outstanding of each of the issuer’s classes of Common Stock, as of the latest practicable date.


Class		Outstanding at October 31, 2002

Common Stock, $.01 par value		15,208,634

TABLE OF CONTENTS


PART 1 — FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		Unaudited Notes to Consolidated Financial Statements
	Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
PART II
	Item 1. Legal Proceedings
	Item 2. Changes in Securities
	Item 3. Defaults Upon Senior Securities
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 5. Other Information
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
CHIEF EXECUTIVE OFFICER CERTIFICATION
CHIEF FINANCIAL OFFICER CERTIFICATION

NORTH COAST ENERGY, INC. AND SUBSIDIARIES


		Page No.


PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements

	Consolidated Balance Sheets -
	September 30, 2002 (Unaudited) and December 31, 2001	3

	Unaudited Consolidated Statements of Income -
	For the Three and Nine Months Ended September 30, 2002 and 2001	5

	Unaudited Consolidated Statements of Cash Flows -
	For the Nine Months Ended September 30, 2002 and 2001	6

	Unaudited Notes to Consolidated Financial Statements	7


Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14


Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22


Item 4.	Controls and Procedures	23

PART II — OTHER INFORMATION		24

CHIEF EXECUTIVE OFFICER CERTIFICATION		26

CHIEF FINANCIAL OFFICER CERTIFICATION		27

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

September 30, 2002 and December 31, 2001


			September 30,		December 31,
ASSETS			2002		2001

			(Unaudited)
CURRENT ASSETS
	Cash and equivalents		$	13,796,081	$	22,035,924
	Accounts receivable			5,490,593		6,006,622
	Inventories			531,111		290,481
	Prepaid drilling and other expenses			689,366		474,411

		Total current assets		20,507,151		28,807,438

PROPERTY AND EQUIPMENT, at cost
	Land			222,822		222,822
	Oil & gas properties (successful efforts)			140,670,745		121,195,745
	Gathering systems			16,448,437		16,411,433
	Vehicles			2,553,352		2,249,507
	Furniture & fixtures			829,608		748,974
	Buildings & improvements			1,872,213		1,862,382

				162,597,177		142,690,863
Less accumulated depreciation, depletion and amortization				35,119,792		29,442,909

				127,477,385		113,247,954
OTHER ASSETS, net				1,587,552		2,734,966

TOTAL ASSETS			$	149,572,088	$	144,790,358

The accompanying notes are an integral part of these consolidated financial statements.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, 2002 and December 31, 2001


			September 30,			December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY			2002			2001

			(Unaudited)
CURRENT LIABILITIES
	Accounts payable		$	3,336,942		$	3,395,272
	Accrued expenses			8,615,113			6,906,337
	Billings in excess of costs on uncompleted contracts			0			2,062,094

	Total current liabilities			11,952,055			12,363,703

LONG-TERM DEBT, net of current portion
	Affiliates			10,000,000			10,000,000
	Non-affiliates			57,000,000			57,000,000

				67,000,000			67,000,000

ACCRUED PLUGGING LIABILITY				226,796			367,394

DEFERRED INCOME TAXES				8,146,326			5,680,027

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS’ EQUITY
	Series A, 6% Noncumulative Convertible Preferred stock par value $.01 per share; 563,270 shares authorized; 72,591 and 73,096 shares issued and outstanding (aggregate liquidation value of $725,910)			726			731

	Series B, Cumulative Convertible Preferred stock, par value $.01 per share; 625,000 shares authorized; 0 and and 232,864 shares outstanding			0			2,329

Undesignated Serial Preferred stock, par value $.01 per share; 811,730 shares authorized; no shares issued or outstanding				0			0

Common Stock, par value $.01 per share; 60,000,000 shares authorized; 15,208,516 and 15,208,031 shares issued and outstanding				152,085			152,080

Additional paid-in capital				47,889,110			50,213,422
Accumulated other comprehensive (loss) income				(1,038,763	)		579,630
Retained earnings				15,243,753			8,431,042

		Total stockholders’ equity		62,246,911			59,379,234
TOTAL LIABILITIES & STOCKHOLDERS’ EQUITY			$	149,572,088		$	144,790,358

The accompanying notes are an integral part of these consolidated financial statements.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Three and Nine Months Ended September 30, 2002 and 2001
(Unaudited)


		Three Months Ended September 30,						Nine Months Ended September 30,

		2002			2001			2002			2001

REVENUE
	Oil and gas production	$	9,194,196		$	7,936,738		$	26,245,966		$	23,618,617
	Drilling revenues		0			0			2,082,351			6,214,520
	Well operating, gathering, and other		1,648,632			2,407,922			5,039,990			8,776,458

			10,842,828			10,344,660			33,368,307			38,609,595
COSTS AND EXPENSES
	Oil and gas production expenses		2,231,911			2,212,148			6,175,590			7,117,462
	Drilling costs		0			164,088			1,752,456			4,793,974
	Well operating, gathering, and other		1,238,309			1,389,814			3,573,052			4,862,025
	General and administrative expenses		947,224			906,733			2,921,300			3,017,995
	Depreciation, depletion and amortization		2,257,730			2,182,905			6,463,464			5,508,951

			6,675,174			6,855,688			20,885,862			25,300,407

INCOME FROM OPERATIONS			4,167,654			3,488,972			12,482,445			13,309,188
INTEREST INCOME (EXPENSE)
	Interest income		104,225			138,300			272,798			637,557
	Interest expense		(795,167	)		(938,866	)		(2,378,038	)		(3,831,421	)

			(690,942	)		(800,566	)		(2,105,240	)		(3,193,864	)

INCOME BEFORE PROVISION FOR INCOME TAXES			3,476,712			2,688,406			10,377,205			10,115,324
PROVISION FOR INCOME TAXES			1,175,123			799,702			3,506,332			3,262,702

NET INCOME		$	2,301,589		$	1,888,704		$	6,870,873		$	6,852,622

NET INCOME APPLICABLE TO COMMON STOCK (after dividends on Cumulative Preferred Stock of $0 and $58,216 for the three months ended September 30, 2002 and 2001 and $58,167 and $174,648 for the nine months ended September 30, 2002 and 2001, respectively		$	2,301,589		$	1,830,488		$	6,812,706		$	6,677,974

NET INCOME PER SHARE (basic and diluted)		$	0.15		$	0.12		$	0.45		$	0.44

The accompanying notes are an integral part of these consolidated financial statements.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three and Nine Months Ended September 30, 2002 and 2003
(Unaudited)


					September 30,			September 30,
					2002			2001

CASH FLOWS FROM OPERATING ACTIVITIES
	Net income				$	6,870,873		$	6,852,622
		Adjustments to reconcile net income to net cash provided by operating activities:
			Depreciation, depletion and amortization			6,463,464			5,508,951
			Deferred income taxes			3,416,787			3,262,656
			Stock Issuance			—			14,648
			Change in:
				Accounts receivable		(291,421	)		2,241,003
				Inventories and other current assets		(455,585	)		3,295,274
				Other assets, net		279,888			668,704
				Accounts payable and accrued expenses		(138,979	)		(77,150	)
				Billings in excess of costs on uncompleted contracts		(2,062,094	)		(6,214,520	)

				Total adjustments		7,212,060			8,699,566

				Net cash provided by operating activities		14,082,933			15,552,188
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property and equipment					(18,482,411	)		(9,901,617	)
	Proceeds on sale of property and equipment					1,275			—
	Acquisition of property and equipment					(1,456,833	)		—

				Net cash used by investing activities		(19,937,969	)		(9,901,617	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Redemption of preferred B stock					(2,326,640	)		—
	Repayment of long term debt					—			(3,763,188	)
	Dividends					(58,167	)		(174,648	)

				Net cash used by financing activities		(2,384,807	)		(3,937,836	)
(DECREASE) INCREASE IN CASH AND EQUIVALENTS						(8,239,843	)		1,712,735
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD						22,035,924			18,189,760

CASH AND EQUIVALENTS AT END OF PERIOD					$	13,796,081		$	19,902,495

Supplemental disclosures of cash flow information:
	Cash paid during the period for:
		Interest			$	2,548,886		$	4,652,064
		Income taxes				32,545			—

The accompanying notes are an integral part of these consolidated financial statements.

Note 1. Summary of Accounting Policies

	A.		General

			The accompanying unaudited consolidated financial statements included herein, have been prepared by North Coast Energy, Inc. in accordance with accounting principles generally accepted in the United States of America for interim financial information and with instructions to Form 10-Q and Article 10 of U.S. Securities and Exchange Commission (“SEC”) Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for fair presentation have been included. These financial statements should be read in conjunction with the financial statements and notes thereto which are in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001.

			The balance sheet at December 31, 2001, presented in this report, has been derived from the audited financial statements at that date but does not include all of the information and footnotes included in the Company’s annual report on Form 10-K for the year ended December 31, 2001.

			The results of the operations for the interim periods may not necessarily be indicative of the results to be expected for the full year. In addition, the preparation of these financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that effect the reported amounts of assets and liabilities at the date of the consolidated financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

			The accompanying financial statements should be read in connection with the “Notes to Consolidated Financial Statements” included in “Item 8. Financial Statements and Supplemental Data” in the Company’s 2001 Annual Report on Form 10-K filed with the SEC. Following is a discussion of the Company’s most critical accounting policies.

	B.		Successful Efforts Method of Accounting

			The Company utilizes the “successful efforts” method of accounting for oil and gas producing activities. Under the successful efforts method, property acquisition and development costs and certain productive exploration cost are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining unproved properties, are expensed as incurred.

			The major difference between the successful efforts method of accounting and the alternative full cost method is that under the full cost method of accounting such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion or impairment expense.

Note 1. Summary of Accounting Policies (cont’d)

	C.		Oil and Gas Reserves

			The Company’s proved developed and proved undeveloped reserves are all located within the Appalachian Basin in the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may very significantly from assumptions used. Proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the accuracy of assumptions used and the judgment of the persons preparing the estimate.

			The Company’s proved reserve information is based on estimates it prepared. Estimates prepared by others may be higher or lower than the Company’s estimates. The Company’s estimates of proved reserves have been reviewed by independent petroleum engineers at each fiscal year end, most recently, December 31, 2001.

	D.		Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets

			Capitalized costs related to proved properties are depleted using the units-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in large or extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

			Unproved oil and gas properties are stated at cost and consist of undrilled leases. These costs are assessed periodically to determine when their value has been impaired, and if impairment is indicated, the costs are charged to expense.

			Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over an average 15 years.

			Other property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 years for buildings. When assets other than oil and gas

Note 1. Summary of Accounting Policies (cont’d)

			properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.

			Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is based on management’s outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest.

	E.		Derivatives and Hedging

			The hedging relationship between the hedging instruments and hedged item must be highly effective. The Company measures effectiveness at least on a monthly basis. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

	F.		Revenue Recognition

			Gas production revenue is recognized as production takes place. Oil production is recognized as oil is removed from the well site. Oil and gas marketing revenues are recognized when title passes. Oilfield service revenues are recognized when services have been provided.

	G.		Per Share Amounts

			The average number of shares used in computing basic and diluted net income per share was 15,208,516 and 15,241,877 and 15,208,031 and 15,244,894 for the three months ended September 30, 2002 and 2001, respectively, and 15,208,423 and 15,241,867 and 15,207,672 and 15,248,769 for the nine months ended September 30, 2002 and 2001, respectively.

	H.		Reclassifications

			Certain reclassifications were made to prior period financial statement presentations to conform with current period presentations.

Note 2. Preferred Dividends

The Company paid a dividend of $58,167 and $174,648 on the Cumulative Convertible Series B Preferred Stock during the nine months ended September 30, 2002 and 2001, respectively. All dividends in arrears attributable to Series B Preferred Stock were paid in December 2001. All shares of Series B Preferred Stock were redeemed on March 31, 2002.

Note 3. Related Party Transactions

			Prior to January 2002, a large portion of the Company’s revenues, other than oil and gas production revenue, was generated from, or was a result of, the organization and management of oil and gas partnerships sponsored by the Company. The Company has since ceased to offer oil and gas partnership investments. The Company believes that the terms of any remaining related party transactions are consistent with terms that could have been obtained from unaffiliated third parties.

			Accounts receivable from affiliates amounted to $1,005,890 and $985,559 at September 30, 2002 and December 31, 2001, respectively, consisting primarily of cash paid on behalf of the partnerships that are managed by the Company and for administrative fees charged to the partnerships. During the nine months ended September 30, 2002 and 2001, the Company acquired limited partnership interests in oil and gas partnerships that it had sponsored at a cost of approximately $295,000 and $1,590,000, respectively.

			In August 2002 the Company offered to purchase any and all partnership interests in 17 limited partnerships in which the company serves as Managing General Partner for approximately $1.8 million. At October 31, 2002, the majority of outstanding interests in 14 of the partnerships had voted in favor of selling all of the assets of the partnerships to the Company. These 14 partnerships will be terminated and the Company will acquire the remaining outstanding interests excluding the interests of those investors that elect to become working interest owners. At this time it is not possible to determine how many partners will elect to become working interest owners. Consequently, it is not possible to estimate the cost of the interests to be acquired or the oil and gas reserves associated with such interests. Termination of the partnerships and the acquisition of partnership interests, excluding the interests of those investors that elect to become working interest owners, is expected to take place in the fourth quarter of 2002.

Note 4. Financial Instruments

			Derivative Financial Instruments: The Company uses derivatives solely for hedging purposes. The following is a summary of the Company’s risk management strategies and the effect of these strategies on the Company’s consolidated financial statements.

			Cash Flow Hedging Strategy: The Company is exposed to commodity price risks related to natural gas. The Company’s financial results can be significantly impacted by changes in commodity prices. “Costless collars” consist of a sold call option and a purchased put option such that the combined revenue and cost of these individual transactions is equal to or near zero. During 2001 and 2002, the Company entered into the following costless collar arrangements:

Note 4. Financial Instruments (cont’d)


	Monthly
	Volume		Price/Mcf		Price/Mcf
Term	Mcf		Floor		Ceiling

January 1, 2002 to December 31, 2002		130,000		3.34		4.52
May 1, 2002 to December 31, 2002		139,000		3.29		4.62
August 1, 2002 to March 31, 2003		46,000		3.33		4.12
November 1, 2002 to March 31, 2003		98,000		3.08		3.48
January 1, 2003 to December 31, 2003		98,000		3.33		4.45
January 1, 2003 to December 31, 2003		130,000		3.45		5.11
April 1, 2003 to December 31, 2003		135,000		4.07		5.29
April 1, 2003 to December 31, 2003		149,000		3.74		4.51
January 1, 2004 to December 31, 2004		132,000		3.85		5.30

			Gains or losses on the hedge relative to the market are recognized monthly as additions to or subtractions from oil and gas sales. To lessen its exposure to commodity price risk, the Company expects to continue to sell natural gas under fixed price contracts, on the spot market and to use financial hedging instruments to realize a fixed price on a portion of its production.

			The following table reflects the natural gas volumes and the weighted average prices under financial hedges and fixed price contracts at September 30, 2002:


									Fixed Price
	Financial Hedges (Collars)								Contracts

					Estimated
					Realizable Price (Mcf)						Estimated
	NYMEX										Realizable
Quarter Ending	MMcf		Price (DTH)		Floor		Cap		MMcf		Price (Mcf)

December 31, 2002		1,158		4.05		3.43		4.48		1,086		3.57
March 31, 2003		1,114		4.27		3.48		4.56		949		3.60
June 30, 2003		1,531		3.91		3.63		4.81		364		3.72
September 30, 2003		1,540		3.94		3.63		4.81		222		3.67
December 31, 2003		1,540		4.12		3.69		4.87		153		3.19
March 31, 2004		396		4.18		4.08		5.53		92		3.00
June 30, 2004		396		3.73		4.01		5.46		81		2.81
September 30, 2004		400		3.71		4.01		5.46		79		2.77
December 31, 2004		400		3.90		4.06		5.51		84		2.89

Note 4. Financial Instruments (cont’d)

Interest Rate Swaps: During 2001 and the first nine months of 2002, the Company entered into interest rate swap agreements that effectively convert a portion of its variable-rate-long-term-debt to fixed rate debt for periods of up to two years, thus reducing the impact of interest rate changes on future income. At September 30, 2002, the following contracts were outstanding:


			LIBOR Rate			All-In
Term	Notional Amount		Fixed			Rate Fixed

January 1, 2002 to December 31, 2002	$	20,000,000		2.7	%		4.6	%
January 1, 2002 to December 31, 2003	$	20,000,000		3.5	%		5.4	%
January 1, 2003 to December 31, 2003	$	20,000,000		4.2	%		6.0	%

			On April 1, 2001, the Company adopted Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended). SFAS 133 establishes accounting and reporting standards for hedging activities and derivative instruments.

			The Company qualifies for special hedge accounting treatment under SFAS 133, whereby the fair value of the hedge is recorded in the balance sheet as either an asset or liability and changes in fair value are recognized in other comprehensive income until settled, when the resulting gains and losses are recorded in earnings. The effect on earnings and other comprehensive income as a result of SFAS 133 will vary from period to period and will be dependent upon prevailing natural gas prices and interest rates, the volatility of forward prices for such commodities, the amount the Company hedges and the time periods covered by such hedges.

			The following table summarizes other comprehensive income of the Company for the three and nine months ended September 30, 2002 and 2001.


		Three Months Ended					Nine Months Ended
		September 30,					September 30,

		2002			2001		2002			2001

Net Income		$	2,301,589		$	1,888,704	$	6,870,873		$	6,852,622
Change in mark-to-market hedge asset (liability) net of deferred taxes:
	Natural gas hedging		(270,798	)		421,113		(990,478	)		126,113
	Interest rate swaps		(375,887	)		0		(627,915	)		0

Comprehensive Income		$	1,654,904		$	2,309,817	$	5,252,480		$	6,978,735

Note 5. Accounting Standards

			In April 2002, the FASB issued SFAS 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS 145 rescinds SFAS 4, “Reporting Gains and Losses from Extinguishment of Debt,” SFAS 44, “Accounting for Intangible Assets of Motor Carriers” and SFAS 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements” and amends SFAS 13, “Accounting for Leases”. Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in 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,” now will be used to classify those gains and losses. SFAS 145 is effective quarter ending September 30, 2002, for the Company’s financial position, results of operations and cash flows.

			In June 2002, the FASB issued SFAS 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 will be effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

Note 6. Commitments and Contingencies

			The Company leases certain equipment used in its field operations under non-cancellable operating leases. Rents under existing leases are approximately $10,000 per month and continues in decreasing amounts until 2005.

			The Company has unlimited liability to third parties with respect to the operations of the partnerships it has sponsored and may be liable to limited partners for losses attributable to breach of fiduciary obligations. In certain partnerships, certain investors have participated as co-general partners in such partnerships. To make such investments more acceptable to potential investors (from a standpoint of risks to such investors), NCE has agreed to indemnify these investor-general partners from any partnership liability, which they may incur in excess of their capital contributions.

			From time to time and in the ordinary course of business, the Company may be subject to various claims, charges, and litigation. In the opinion of management, final judgments from such pending claims, charges, and litigation, if any, against the Company would not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Note 7. Industry Segment Information

The Company operates in one reportable industry segment as an independent energy company engaged in exploring for, developing and producing natural gas and oil reserves, acquiring and enhancing existing reserves and gathering and marketing natural gas and oil. The company’s operations are entirely within the United States.

Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations

			Forward Looking Information

			The information in this document includes forward-looking statements that are made pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of the Company are subject to a number of risks and uncertainties, which may cause the Company’s actual results in future periods to differ from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, the Company’s access to capital, the market demand for and prices of oil and natural gas, the Company’s oil and gas production and costs of operation, the results of the Company’s future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulation changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in the Company’s 10-K and 10-Q reports and other filings with the SEC.

General

North Coast Energy, Inc., a Delaware corporation (“NCE” or the “Company”), is an affiliate of nv NUON (“NUON”), a limited liability company organized under the laws of The Netherlands. NCE and its subsidiaries are engaged in the acquisition and enhancement of developed producing natural gas and oil properties and the exploration, development and production of undeveloped natural gas and oil properties. NCE derives its revenues from its own oil and gas production, well operating and gas gathering and marketing services it provides for third parties.

The following tables review the results of operations of the Company for the three and nine months ended September 30, 2002 and 2001.


		Three Months Ended				Nine Months Ended
		September 30,				September 30,

		2002		2001		2002		2001

PRODUCTION
	Oil production (MBbls)		27		27		76		68
	Gas production (MMcf)		2,425		2,267		6,935		6,216
	Total production (MMcfe)		2,585		2,426		7,393		6,624
AVERAGE PRICES
	Oil (per Bbl)	$	25.80	$	21.70	$	21.90	$	23.21
	Gas (per Mcf)		3.51		3.25		3.54		3.55
	Average price per Mcfe		3.56		3.27		3.55		3.57
AVERAGE COSTS (per Mcfe)
	Production expense	$	0.65	$	0.67	$	0.63	$	0.75
	Production taxes		0.22		0.25		0.21		0.29
	Depreciation, depletion & amortization		0.87		0.90		0.87		0.83
	General and administrative expense		0.37		0.37		0.40		0.46
GROSS OPERATING MARGIN (per Mcfe)		$	2.69	$	2.35	$	2.71	$	2.53


MBbls: thousand barrels	MMcf:	million cubic feet	MMcfe:	million cubic feet of natural gas equivalent
Bbl: barrel	Mcf:	thousand cubic feet	Mcfe:	thousand cubic feet of natural gas equivalent

Gross Operating Margin (per Mcfe): Average Price less Production Expense (including production taxes)

All items in the following table are calculated as a percentage of total revenues.


		Three Months Ended						Nine Months Ended
		September 30,						September 30,

		2002			2001			2002			2001

Revenues:
	Oil and gas production		85	%		77	%		79	%		61	%
	Drilling		0	%		0	%		6	%		16	%
	Well operating, gathering, and other		15	%		23	%		15	%		23	%

Total Revenues			100	%		100	%		100	%		100	%
Expenses:
	Oil and gas production		21	%		21	%		19	%		18	%
	Drilling costs		0	%		2	%		5	%		13	%
	Well operating, gathering, and other		11	%		13	%		11	%		13	%
	General and administrative		9	%		9	%		9	%		8	%
	Depreciation, depletion, and amortization		21	%		21	%		19	%		14	%
	Interest (net)		6	%		8	%		6	%		8	%
	Income taxes		11	%		8	%		10	%		8	%

Total Expenses			79	%		82	%		79	%		82	%
Net Income			21	%		18	%		21	%		18	%

The following discussion and analysis reviews the results of operations and the financial condition for the Company for three and nine months ended September 30, 2002 and 2001. The review should be read in conjunction with the financial information presented elsewhere herein.

Comparison of Three Months Ended September 30, 2002 to September 30, 2001

Revenues

Oil and gas revenues increased $1,257,458 (16%) to $9,194,196 for the three months ended September 30, 2002, from $7,936,738 for the three months ended September 30, 2001. The increase in oil and gas revenues reflects higher volumes of gas production. The Company’s production volumes for the three months ended September 30, 2002, were 2,585,044 Mcfe (Mcf equivalents) of natural gas and oil compared to 2,425,822 Mcfe for the three months ended September 30, 2001. The Company recognizes a portion of the wellhead price it receives as gas gathering and other revenues to offset a portion of its costs related to its gathering systems and compression facilities. Excluding the portion attributable to gas gathering and compression revenues, the Company received an average price of $3.56 and $3.27 per Mcfe for oil and natural gas sold for the three months ended September 30, 2002 and 2001, respectively.

Well operating, gathering and other revenue decreased $759,290 (32%) to $1,648,632 for the three months ended September 30, 2002, compared to $2,407,922 for the three months ended September 30, 2001. This decrease results from lower natural gas gathering revenue and lower gas marketing revenues due to a significant reduction in gas purchased and sold to third parties because of reduced demand in 2002.

Expenses

Oil and gas production expenses increased $19,763 (1%) to $2,231,911 for the three months ended September 30, 2002, from $2,212,148, for the three months ended September 30, 2001, reflecting increased production volumes.

Drilling costs decreased $164,088 (100%) to $0 for the three months ended September 30, 2002, compared to $164,088 at September 30, 2001, due to no wells being drilled for drilling partnerships in the quarter ending September 30, 2002.

Well operating, gathering, and other expenses decreased $151,505 (11%) for the three months ended September 30, 2002, to $1,238,309 from $1,389,814 for the three months ended September 30, 2001, primarily as a result of decreased costs and amounts of gas purchased and sold to third parties.

General and administrative expenses increased $40,491 (4%) to $947,224 for the three months ended September 30, 2002, from $906,733 for the three months ended September 30, 2001, primarily due to compensation and benefit related expenses.

The increase in depreciation, depletion and amortization (DD&A) of $74,825 (3%) to $2,257,730 for the three months ended September 30, 2002, from $2,182,905 for the three months ended September 30, 2001, is the result of increased production volumes in the quarter ending September 30, 2002. DD&A per unit of production decreased 3% to $0.87 per Mcfe in the quarter ending September 30, 2002.

For the three months ended September 30, 2002, net interest expense decreased $109,624 to $690,942 compared to $800,566 for the three months ended September 30, 2001. The decrease reflects lower interest rates on the Company’s long-

term debt partially offset by lower interest income resulting from lower rates earned on amounts invested in 2002 compared to 2001.

Net income for the three months ended September 30, 2002, increased $412,885 (22%) to $2,301,589 from $1,888,704 for the three months ended September 30, 2001 due to increased production volumes along with a $0.28 increase in average price per Mcfe. The Company’s net income attributable to common stock was $2,301,589 ($0.15/share) for the three months ended September 30, 2002, compared to $1,830,488 ($0.12/share) for the three months ended September 30, 2001.

Comparison of Nine Months Ended September 30, 2002 to September 30, 2001

Revenues

Oil and gas revenues increased $2,627,349 (11%) to $26,245,966 for the nine months ended September 30, 2002, from $23,618,617 for the nine months ended September 30, 2001. The increase in oil and gas revenues reflects increased volumes of gas and oil production offset by slightly lower prices received for natural gas and oil. The Company’s production volumes for the nine months ended September 30, 2002, were 7,393,174 Mcfe (Mcf equivalents) of natural gas and oil compared to 6,624,295 Mcfe for the nine months ended September 30, 2001. The Company recognizes a portion of the wellhead price it receives as gas gathering and other revenues to offset a portion of its costs related to its gathering systems and compression facilities. Excluding the portion attributable to gas gathering and compression revenues, the Company received an average price of $3.55 and $3.57 per Mcfe for oil and natural gas sold for the nine months ended September 30, 2002 and 2001, respectively.

Drilling revenues decreased $4,132,169 (66%) to $2,082,351 for the nine months ended September 30, 2002, compared to $6,214,520 for the nine months ended September 30, 2001. This decrease results from significantly less drilling program funds being raised reflecting the Company’s exodus from the drilling program business to focus on its core business of exploration and production.

Well operating, gathering and other revenue decreased $3,736,468 (43%) to $5,039,990 for the nine months ended September 30, 2002, compared to $8,776,458 for the nine months ended September 30, 2001. This decrease results from lower natural gas gathering revenue and lower gas marketing revenues due to a significant reduction in gas purchased and sold to third parties because of reduced demand in 2002.

Expenses

Oil and gas production expenses decreased $941,872 (13%) to $6,175,590 for the nine months ended September 30, 2002, from $7,117,462 for the nine months ended September 30, 2001, reflecting ongoing efficiencies in field operations and lower production taxes resulting from lower average gas prices.

Drilling costs decreased $3,041,518 (63%) to $1,752,456 for the nine months ended September 30, 2002, compared to $4,793,974 at September 30, 2001, reflecting a significantly reduced number of wells drilled and completed for drilling programs.

Well operating, gathering, and other expenses decreased $1,288,973 (27%) for the nine months ended September 30, 2002, to $3,573,052 from $4,862,025 at September 30, 2001, primarily as a result of decreased costs and amounts of gas purchased and sold to third parties.

General and administrative (“G&A”) expenses decreased $96,695 (3%) to $2,921,300 for the nine months ended September 30, 2002, from $3,017,995 for the nine months ended September 30, 2001. The decrease in G&A expense primarily reflects the elimination of costs incurred in the quarter ended March 31, 2001 associated with business process reengineering activities and the implementation of a new computer system.

The increase in depreciation, depletion and amortization (“DD&A”) of $954,513 (17%) to $6,463,464 for the nine months ended September 30, 2002, from $5,508,951 for the nine months ended September 30, 2001, is the result of higher volumes of oil and gas produced during the nine months ended September 30, 2002. DD&A per unit of production increased 5% to $0.87 per Mcfe for the nine months ended September 30, 2002.

For the nine months ended September 30, 2002, net interest expense decreased $1,088,624 to $2,105,240 compared to $3,193,864 for the nine months ended September 30, 2001. The decrease reflects lower interest rates on the Company’s long-term debt partially offset by lower interest income resulting from lower rates earned on amounts invested in 2002 compared to 2001.

Net income for the nine months ended September 30, 2002 increased $18,251 (0.3%) to $6,870,873 from $6,852,622 for the nine months ended September 30, 2001, primarily as a result of increased production volumes reflected in oil and gas revenues. This increase is offset by the decrease in drilling revenues. This reflects the Company’s shift from the drilling program business to its core business of exploration and development. The Company’s net income attributable to common stock was $6,812,706 ($0.45/share) for the nine months ended September 30, 2002, compared to $6,677,974 ($0.44/share) for the nine months ended September 30, 2001.

Inflation and Changes in Prices

Inflation affects the Company’s operating expenses as well as interest rates, both of which may have an effect on the Company’s profitability. Oil and gas prices have not followed inflation and have fluctuated during recent years as a result of other forces such as the Organization of Petroleum Exporting Countries (“OPEC”), economic factors and demand for and supply of natural gas in the United States and within the Company’s regional area of operation. Natural gas prices have decreased slightly during the nine months ended September 30, 2002, compared to the natural gas prices for the nine months ended September 30, 2001. This decrease in price is attributed to higher storage supplies entering the winter of 2002/2003 and decreased natural gas demand for industrial use. As a result of these market forces, the Company received an average price of $21.90 per barrel of oil for the nine months ended September 30, 2002 compared to $23.21 for the nine months ended September 30, 2001. The Company received an average price after recognition of a portion of the wellhead price in gas gathering and other revenues of $3.54 per Mcf for its natural gas for the nine months ended September 30, 2002, compared to $3.55 for the nine months ended September 30, 2001. The Company cannot predict the future direction of oil and gas markets and prices, as the forces noted above as well as other variables are subject to change.

Liquidity and Capital Resources

The Company’s working capital was $8,555,096 at September 30, 2002, compared to $16,443,735 at December 31, 2001. The decrease of $7,888,639 in working capital at September 30, 2002, is due mainly to the use of cash in the Company’s drilling activity, the acquisition of certain oil and gas properties and the redemption of the Company’s Series B Preferred Stock.

			The following table summarizes the Company’s financial position at September 30, 2002, and December 31, 2001 (amounts in thousands):


		September 30,				December 31,
		2002				2001

		Amount		%		Amount		%

Working Capital		$	8,555		6	$	16,444		12
Property and equipment (net)			127,477		93		113,248		86
Other			1,588		1		2,735		2

	Total	$	137,620		100	$	132,427		100

Long-term debt		$	67,000		49	$	67,000		51
Deferred income taxes and other liabilities			8,373		6		6,048		4
Stockholders’ equity			62,247		45		59,379		45

	Total	$	137,620		100	$	132,427		100

			The oil and gas exploration and development activities of NCE historically have been financed through the sponsored drilling programs, internally generated funds, and from bank and equity financing.

			The following table summarizes the Company’s Statements of Cash Flows for the nine months ended September 30, 2002 and 2001 (amounts in thousands):


	2002			2001

Net cash provided by operating activities	$	14,083		$	15,552
Net cash used by investing activities		(19,938	)		(9,902	)
Net cash used by financing activities		(2,385	)		(3,937	)

(Decrease) Increase in cash and equivalents	$	(8,240	)	$	1,713

			As the above table indicates, the Company’s cash provided by operating activities was $14,082,933 and $15,552,188 for the nine months ended September 30, 2002, and 2001, respectively. This decrease reflects a significant reduction in accounts receivable from the nine months ended September 30, 2001.

			Net cash used for investing activities was $19,937,969 for the nine months ended September 30, 2002, compared to $9,901,617 for the nine months ended September 30, 2001 reflecting the Company’s increased drilling for its own account and the acquisition of producing oil and gas properties.

			Net cash used in financing activities was $2,384,807 for the nine months ended September 30, 2002, and $3,937,836 for the nine months ended September 30, 2001. The amount used in 2002 was primarily for the redemption of the Company’s Series B Preferred Stock while the amount used in 2001 was primarily used for repayment of long-term debt.

At September 30, 2002, the Company had $8,000,000 available on its revolving line of credit and cash balances totaling $13,796,081. In October 2002, the Company was informed by its lead bank that its borrowing base will be increased to $80,000,000, which will increase the amount available under its line of credit to $23,000,000. The Company believes that its cash, cash flow from operations and available borrowing capacity are adequate to fund its planned capital expenditures and operations, including any operating risks discussed below under the heading “Quantitative and Qualitative disclosures About Market Risk”.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

			The Company is exposed to commodity price, interest rate and credit risks. The Company’s primary interest rate risk exposure results from floating rate debt including debt under the Company’s revolving Credit Facility and the Subordinated Promissory Note between the Company and NUON. The Company is exposed to commodity price risks related to natural gas and oil. The Company has entered into contracts to reduce its exposure to these risks, as discussed in the Company’s financial statements filed herein. In addition, quantitative and qualitative disclosures about market risk were included in the Company’s Form 10-K (Item 7A) and the financial statements included therein for the fiscal year ended December 31, 2001.

			The Company is exposed to credit risk from its customers and counterparties transactions. The Company has credit approval policies that establish credit limits for its customers. These limits are closely monitored, as are collections of accounts receivable. The Company generally does not require collateral from its customers and counterparties. Historically, losses from bad debt have been within management’s expectations.

			The Company’s ability to collect for sales of natural gas and oil to its customers is dependent on the payment ability of the Company’s customer base. The Company monitors the creditworthiness of its customers and, from time to time, will demand adequate assurances of performance if the creditworthiness of the customer is in question. If such assurances are not given to the Company, an alternative purchaser may be sought. In recent months, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for the Company’s natural gas production. This reduction in potential customers has reduced market liquidity and, in some cases, made it difficult for the Company to identify creditworthy customers. The Company will continue to monitor its customer base and to pursue alternative customers.

			The Company sells approximately $1,000,000 per month of natural gas to a major customer. Performance by this customer is guaranteed by an affiliate of the customer. The credit rating of the customer’s affiliate was recently downgraded by various credit rating agencies due to liquidity and other financial concerns. In the event of a default in payment by the customer, the Company may not be able to collect amounts due from the customer or customer’s affiliate and would need to identify an alternative purchaser for a significant amount of natural gas. The Company presently believes that the customer will honor all payment obligations to the Company.

Item 4. Controls and Procedures

			Evaluation of disclosure controls and procedures. The Company’s Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-14) as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”) have concluded that as of the Evaluation Date, the Company’s disclosure controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms.

			Changes in internal controls. There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls subsequent to the Evaluation Date.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

PART II

OTHER INFORMATION

Item 1. Legal Proceedings

Not applicable

Item 2. Changes in Securities

Not applicable

Item 3. Defaults Upon Senior Securities

Not applicable

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable

Item 5. Other Information

Not applicable

Item 6. Exhibits and Reports on Form 8-K

	a.)		Exhibits

			None

	b)		Reports on Form 8-K:

			No reports on Form 8-K have been filed during the quarter for which this report was filed.

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.


		NORTH COAST ENERGY, INC.

November 6, 2002		/s/ Ömer Yonel Ömer Yonel President, Chief Executive Officer and Director

		NORTH COAST ENERGY, INC.

November 6, 2002		/s/ Dale E. Stitt Dale E. Stitt

		Chief Financial Officer and Principal Accounting Officer

CERTIFICATIONS

I, Ömer Yonel, certify that:

1. I have reviewed this quarterly report on Form 10-Q of North Coast Energy, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

			a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

			b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

			c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

			a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

			b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


Date: November 6, 2002				Signed: /s/ Ömer Yonel Title: President, Chief Executive Officer and Director

I, Dale E. Stitt, certify that:

1. I have reviewed this quarterly report on Form 10-Q of North Coast Energy, Inc.;

			a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

			b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

			c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

			a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

			b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


Date: November 6, 2002				Signed: /s/ Dale E. Stitt Title: Chief Financial Officer and Principal Accounting Officer

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NORTH COAST ENERGY INC / DE/ 10-Q