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 the quarterly period ended September 30, 2003.

[ ] 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 (State or other jurisdiction or organization of incorporation)		34-1594000 (I.R.S. Employer Identification No.)




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

Indicate by a check mark whether the registrant is an accelerated filer (as defined in Rule 12-b-2 of the Exchange Act).

Yes . No X .

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 September 30, 2003

Common Stock, $.01 par value		15,251,806

TABLE OF CONTENTS


PART I — FINANCIAL INFORMATION
	Item 2. Management’s 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 — OTHER INFORMATION
SIGNATURES
Index to Exhibits
Certification of CEO
Certification of CFO
906 Certification of CEO
906 Certification of CFO

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

FORM 10-Q

INDEX


			Page No.

PART I — FINANCIAL INFORMATION




Item 1. Financial Statements




	Consolidated Balance Sheets -




		September 30, 2003 (Unaudited) and December 31, 2002		3




	Consolidated Statements of Income (Unaudited) -




		For the Three and Nine Months Ended September 30, 2003 and 2002		5




	Consolidated Statements of Cash Flows (Unaudited) -




		For the Nine Months Ended September 30, 2003 and 2002		6




	Notes to Unaudited 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				20




Item 4. Controls and Procedures				21




PART II — OTHER INFORMATION				22




SIGNATURES				23




INDEX TO EXHIBITS				24

NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, 2003 and December 31, 2002


			September 30,		December 31,
ASSETS			2003		2002

			(Unaudited)
CURRENT ASSETS




	Cash and equivalents		$	16,970,728	$	14,711,205




	Accounts receivable			8,281,944		5,796,537




	Inventories			310,713		353,722




	Prepaid expenses			711,542		404,726

		Total current assets		26,274,927		21,266,190




PROPERTY AND EQUIPMENT, at cost




	Land			222,822		222,822




	Oil and gas properties (successful efforts)			158,612,028		143,952,276




	Gathering systems			17,664,379		17,137,184




	Vehicles			3,133,369		2,288,388




	Furniture and fixtures			1,092,736		991,438




	Buildings and improvements			2,170,862		1,877,667

				182,896,196		166,469,775




Less accumulated depreciation, depletion




	and amortization			43,816,334		37,213,430

				139,079,862		129,256,345




OTHER ASSETS, net				584,734		1,328,595













TOTAL ASSETS			$	165,939,523	$	151,851,130

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

NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, 2003 and December 31, 2002


				September 30,			December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY				2003			2002

				(Unaudited)
CURRENT LIABILITIES




	Accounts payable			$	4,330,519		$	3,369,632




	Accrued expenses				9,869,400			7,077,717

			Total current liabilities		14,199,919			10,447,349









LONG-TERM DEBT




	Affiliates				—			10,000,000




	Non-affiliates				57,000,000			57,000,000

					57,000,000			67,000,000









OTHER LONG-TERM LIABILITIES					1,184,123			208,456









DEFERRED INCOME TAXES					16,514,002			9,458,421









COMMITMENTS AND CONTINGENCIES









STOCKHOLDERS’ EQUITY




	Series A, 6% Noncumulative Convertible Preferred stock par value $.01 per share; 563,270 shares authorized; 0 and 72,336 shares issued and outstanding (aggregate liquidation value of $0 and $723,360)				—			723




	Series B, Cumulative Convertible Preferred stock, par value $.01 per share; 625,000 shares authorized; no shares issued or outstanding				—			—




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




	Common Stock, par value $.01 per share; 60,000,000 shares authorized; 15,251,806 and 15,208,634 shares issued and outstanding				152,518			152,086




Additional paid-in capital					47,264,681			47,889,111




Accumulated other comprehensive loss					(1,244,252	)		(1,430,225	)




Retained earnings					30,868,532			18,125,209

		Total stockholders’ equity			77,041,479			64,736,904






TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY				$	165,939,523		$	151,851,130

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, 2003 and 2002
(Unaudited)


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

			2003		2002		2003		2002

REVENUE




	Oil and gas production		$	14,445,510	$	9,194,196	$	42,186,892	$	26,245,966




	Drilling revenues			—		—		—		2,082,351




	Well operating, gathering, and other			1,766,291		1,648,632		5,018,799		5,039,990

				16,211,801		10,842,828		47,205,691		33,368,307




COSTS AND EXPENSES




	Oil and gas production expenses			2,565,363		2,231,911		7,799,116		6,175,590




	Drilling costs			—		—		—		1,752,456




	Well operating, gathering, and other			1,366,896		921,025		4,003,930		2,523,548




	Exploration expense			1,215,721		317,284		2,476,316		1,049,504




	General and administrative expenses			1,648,753		947,224		4,763,290		2,921,300




	Depreciation, depletion and amortization			2,352,710		2,257,730		6,789,965		6,463,464

				9,149,443		6,675,174		25,832,617		20,885,862


INCOME FROM OPERATIONS				7,062,358		4,167,654		21,373,074		12,482,445





INTEREST EXPENSE, NET




	Interest income			118,923		104,225		357,643		272,798




	Interest expense			661,009		795,167		2,071,894		2,378,038

				542,086		690,942		1,714,251		2,105,240


INCOME BEFORE PROVISION FOR INCOME TAXES				6,520,272		3,476,712		19,658,823		10,377,205





PROVISION FOR INCOME TAXES				2,294,000		1,175,123		6,915,500		3,506,332


NET INCOME			$	4,226,272	$	2,301,589	$	12,743,323	$	6,870,873


NET INCOME APPLICABLE TO COMMON STOCK (after dividends on Cumulative Preferred Stock of $58,167 for the nine months ended September 30, 2002)			$	4,226,272	$	2,301,589	$	12,743,323	$	6,812,706

NET INCOME PER SHARE




		Basic	$	0.28	$	0.15	$	0.84	$	0.45

		Diluted	$	0.27	$	0.15	$	0.82	$	0.45

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


					September 30,			September 30,
					2003			2002


CASH FLOWS FROM OPERATING ACTIVITIES




	Net income				$	12,743,323		$	6,870,873




		Adjustments to reconcile net income to net cash provided by operating activities:




			Depreciation, depletion and amortization			6,789,965			6,463,464




			Deferred income taxes			6,915,500			3,416,787




			Gain on sale of property and equipment			(4,781	)		—




			Change in:




				Accounts receivable		(2,485,407	)		(291,421	)




				Inventories and other current assets		(263,807	)		(455,585	)




				Other assets, net		604,627			279,888




				Accounts payable and accrued expenses		5,101,227			1,619




				Billings in excess of costs on uncompleted contracts		—			(2,062,094	)




				Other long-term liabilities		(46,937	)		(140,598	)

				Total adjustments		16,610,387			7,212,060

				Net cash provided by operating activities		29,353,710			14,082,933





CASH FLOWS FROM INVESTING ACTIVITIES




	Purchases of property and equipment					(16,844,409	)		(19,939,244	)




	Proceeds on sale of property and equipment					374,943			1,275

				Net cash used by investing activities		(16,469,466	)		(19,937,969	)





CASH FLOWS FROM FINANCING ACTIVITIES




	Repayment of long-term debt — affiliates					(10,000,000	)		—




	Net proceeds from issuance of common stock					154,189			—




	Redemption of Preferred A stock					(720,610	)		—




	Redemption of Preferred B stock					—			(2,326,640	)




	Redemption of Options					(58,300	)		—




	Dividends					—			(58,167	)

				Net cash used by financing activities		(10,624,721	)		(2,384,807	)


INCREASE (DECREASE) IN CASH AND EQUIVALENTS						2,259,523			(8,239,843	)





CASH AND EQUIVALENTS AT BEGINNING OF PERIOD						14,711,205			22,035,924


CASH AND EQUIVALENTS AT END OF PERIOD					$	16,970,728		$	13,796,081

Supplemental disclosures of cash flow information:




	Cash paid during the period for:




		Interest			$	2,242,140		$	2,548,886




		Income taxes				—			32,545

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

NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED 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, 2002.

			The balance sheet at December 31, 2002, 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, 2002.

			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 2002 Annual Report on Form 10-K filed with the SEC. Following is a discussion of the Company’s most critical accounting policies.

	B.		Oil and Gas Investments and Properties

			The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip developmental wells are capitalized.

			Costs to drill exploratory wells that do not find proved reserves, costs of developmental wells on properties the Company has no further interest in, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

	C.		Oil and Gas Reserves

			The Company’s proved developed and proved undeveloped reserves are all located within the Appalachian and Illinois Basins 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.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

			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, actual prices realized and actual costs incurred may vary 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, 2002.

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

			When a property is determined to contain proved reserves, the capitalized costs of such properties are transferred from unproved properties to proved properties and are amortized on a group (pool) basis with proved properties having similar characteristics, by the unit-of-production method based upon estimated proved developed reserves. To the extent that capitalized costs of each pool of proved properties exceed the estimated future net cash flow from such pool, the excess capitalized costs are written down to the present value of such amount. Estimated future net cash flows are determined based primarily upon the estimated future proved reserves related to the Company’s current proved properties.

			On sale or abandonment of an entire interest in an unproved property, the gain or loss is recognized taking into consideration the amount of any recorded impairment. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. The carrying cost of unproved properties is approximately $3,800,000 at September 30, 2003.

			Unproved oil and gas properties that are significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are expensed when surrendered or upon lease expiration.

			Property and equipment are stated at cost and are depleted or depreciated principally on methods and at rates designed to amortize their costs over their estimated useful lives (proved oil and gas properties using the unit-of-production method based upon estimated proved developed oil and gas reserves, gathering systems using the straight-line method over 10 to 25 years, vehicles, furniture and fixtures using various methods over 3 to 15 years and building and improvements using various methods over 7 — 31.5 years).

			The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 144 which requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment is recorded as impaired properties are identified.

	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 would not occur, deferred gains or losses are recognized in earnings immediately.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

	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 15,251,806 and 15,464,490 and 15,208,516 and 15,241,877 for the three months ended September 30, 2003 and 2002, respectively, and 15,251,798 and 15,454,692 and 15,208,423 and 15,241,867 for the nine months ended September 30, 2003 and 2002, respectively.

	H.		Reclassifications

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

Note 2. Stock Options

			At the Annual Meeting of Stockholders held June 12, 2003, the security holders adopted a proposal to amend the Company’s 1999 Employee Stock Option Plan to add 400,000 shares of common stock for issuance under such plan.

			The Company accounts for stock based compensation issued to its employees and directors in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, no compensation cost has been recognized for the stock option plans, as all options granted under the plans have an exercise price equal to the average of the closing price for each of the twenty trading days prior to the date of the grant. The fair value of options granted was determined using the Black-Scholes option pricing model, assuming no dividend yield, and weighted average risk-free interest rates of 2.5% and 4.6% for 2003 and 2002, respectively; volatility of 67% and 52% for 2003 and 2002, respectively; and expected life of 5 years.

			The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of FASB Statement No. 123, “Accounting for Stock-based Compensation” to stock-based employee compensation:


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

		2003		2002		2003			2002

Net Income as reported		$	4,226,272	$	2,301,589	$	12,743,323		$	6,870,873




Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects			—		—		(504,200	)		(103,300	)

Pro forma net income		$	4,226,272	$	2,301,589	$	12,239,123		$	6,767,573

Earnings per share




	Basic — as reported	$	0.28	$	0.15	$	0.84		$	0.45

	Diluted — as reported	$	0.27	$	0.15	$	0.82		$	0.45

	Basic — pro forma	$	0.27	$	0.15	$	0.80		$	0.44

	Diluted — pro forma	$	0.28	$	0.15	$	0.79		$	0.44

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 3. Preferred Stock

The Company paid a dividend of $58,167 on the Cumulative Convertible Series B Preferred stock during the nine months ended September 30, 2002. All shares of Series B Preferred stock were redeemed March 31, 2002. In June 2003, the Company redeemed all of its outstanding Series A Preferred stock for $720,610.

Note 4. 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 drilling partnerships sponsored by the Company. The Company ceased offering these partnerships in 2002. The Company believes that the terms of any remaining related party transactions involving the remaining partnerships are consistent with terms that could have been obtained from unaffiliated third parties.

			Accounts receivable from affiliates amounted to $97,095 and $72,385 at September 30, 2003, and December 31, 2002, respectively, consisting primarily of receivables from the partnerships managed by the Company and are for administrative fees charged to the partnerships and to reimburse the Company for amounts paid on behalf of the partnerships.

Note 5. Financial Instruments

			Derivative Financial Instruments: The Company uses financial 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 the sale of its natural gas and oil. As a result, the Company’s financial results can be significantly impacted by changes in commodity prices. “Costless collars” are financial derivatives that 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. As of September 30, 2003, the Company had entered into the following costless collar arrangements:


	Monthly		Price Per		Price Per
	Volume		MMBtu		MMBtu
Term	MMBtu		Floor		Ceiling

January 1, 2003 to December 31, 2003		100,000	$	3.25	$	4.35




January 1, 2003 to December 31, 2003		150,000		3.00		4.45




April 1, 2003 to December 31, 2003		153,000		3.60		4.68




April 1, 2003 to December 31, 2003		153,000		3.65		4.40




January 1, 2004 to December 31, 2004		153,000		3.35		4.61




January 1, 2004 to December 31, 2004		153,000		3.50		5.30




January 1, 2004 to December 31, 2004		305,000		4.25		7.06

Gains or losses on the hedges 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 defined price on a portion of its production. As a result of the costless collars, revenues were decreased by $820,340 and increased by $15,000 for the three months ended September 30, 2003 and 2002, respectively, and revenues were decreased by $5,383,000 and increased by $789,170 for the nine months ended September 30, 2003 and 2002, respectively. The mark-to-market liability associated with the costless collars at September 30, 2003, was $1,038,000.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

The following table reflects the natural gas volumes and the weighted average prices under financial hedges and fixed price contracts at September 30, 2003. One MMBtu is approximately equal to one Mcf.


	Financial Hedges (Collars)						Fixed Price Contracts

			Est. Realizable Price
											NYMEX
Quarter Ending	MMBtu		Floor		Cap		MMBtu		Est. Price		@ 9/30/03

December 31, 2003		1,670,000	$	3.39	$	4.48		873,000	$	5.30	$	4.78




March 31, 2004		1,815,000		3.84		6.01		1,111,000		5.43		5.19




June 30, 2004		1,820,000		3.84		6.01		619,000		5.32		4.75




September 30, 2004		1,840,000		3.84		6.01		403,000		5.45		4.72




December 31, 2004		1,840,000		3.84		6.01		280,000		5.39		4.86




March 31, 2005		0		0.00		0.00		87,717		5.23		5.00




June 30, 2005		0		0.00		0.00		60,208		5.05		4.49




September 30, 2005		0		0.00		0.00		45,291		4.88		4.46




December 31, 2005		0		0.00		0.00		28,483		4.67		4.67

Mcf: thousand cubic feet		MMBtu: million british thermal units

Interest Rate Swaps: During 2001, the Company entered into interest rate swap agreements that effectively converted 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. As a result of the swap agreements, interest expense was increased by approximately $203,400 and $132,100 for the three months ended September 30, 2003 and 2002 respectively, and $604,000 and $363,400 for the nine months ended September 30, 2003 and 2002 respectively.


	Notional		LIBOR			NCE Effective
Term	Amount		Rate Fixed			Fixed Rate

January 1, 2003 to December 31, 2004	$	20,000,000		3.2	%		4.9	%




January 1, 2003 to December 31, 2004	$	20,000,000		3.0	%		4.6	%

			The mark-to-market liability associated with the two interest rate swap contracts was approximately $907,000 at September 30, 2003. In February 2003 the Company extended the term of both swaps to December 31, 2004.

			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 (loss) 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 and terms of the Company’s hedges and the time periods covered by such hedges.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

The following table summarizes other comprehensive income of the Company for the three and nine months ended September 30, 2003 and 2002.


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

		2003		2002			2003		2002

Net Income		$	4,226,272	$	2,301,589		$	12,743,323	$	6,870,873




Change in mark-to-market asset (liability) net of deferred taxes:




	Natural gas hedge		2,368,199		(270,798	)		152,474		(990,478	)




	Interest rate swaps		119,584		(375,887	)		33,499		(627,915	)

Comprehensive Income		$	6,714,055	$	1,654,904		$	12,929,296	$	5,252,480

Note 6. Accounting Standards

			In June 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” which was effective the first quarter of fiscal year 2003. SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of long-lived assets and the associated asset retirement cost. The adoption of this standard has not had a material effect on the Company’s financial position, results of operations or cash flows.

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

			In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation” Transition and Disclosure (SFAS 148) that amends SFAS No. 123, “Accounting for Stock-Based Compensation”, to provide alternative methods of transition to Statement 123’s fair value method of accounting for stock-based employee compensation. SFAS 148 also amends the disclosure provisions of SFAS 123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure of the effects of an entity’s accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. The Statement does not amend SFAS 123 to require companies to account for employee stock options using the fair value method. The Statement is effective for fiscal years beginning after December 15, 2002. The adoption of SFAS 148 has not had a material effect on the Company’s results of operations.

			In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The Company does not expect the application of the provisions of SFAS No. 149 to have a material impact on its financial position, results of operations or cash flows.

			In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company does not expect the application of the provisions of SFAS No. 150 to have a material impact on its financial position, results of operations or cash flows.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)

Note 7. Commitments and Contingencies

			The Company leases certain equipment used in its field operations under non-cancellable operating leases. Rents under existing leases are approximately $33,400 per month and continue 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. All such general partner investors have subsequently been converted to limited partners in all outstanding partnerships.

			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 against the Company, if any, would not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Note 8. 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. Management’s 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 Annual Report on Form 10-K reports and other filings with the SEC.

General

North Coast Energy, Inc., (“NCE” or the “Company”), is a Delaware corporation. 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, and well operations, gas gathering and gas marketing services it provides for third parties.

In April 2003, the Company announced that it had retained an investment banking firm to assist it in examining and evaluating its strategic alternatives. Subsequently, in connection with its evaluation, the Company received several third party proposals for the acquisition of the Company. As announced on October 6, 2003, the prices reflected in these proposals are below the recent market trading prices of the Company’s stock and the level of recent trading activity in the Company’s stock has been substantially above historical levels at certain times recently.

There can be no assurance that a definitive transaction will be consummated.

The following table is a review of the results of operations of the Company for the three and nine months ended September 30, 2003 and 2002.


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

			2003		2002		2003		2002
PRODUCTION




		Oil production (MBbls)		29		27		84		76




		Gas production (MMcf)		2,733		2,425		7,943		6,935




		Total production (MMcfe)		2,909		2,585		8,447		7,393




	AVERAGE PRICES




		Oil (per Bbl)	$	26.44	$	25.80	$	27.27	$	21.90




		Gas (per Mcf)		5.00		3.51		5.02		3.54




		Average price per Mcfe		4.97		3.56		4.99		3.55




	AVERAGE COSTS (per Mcfe)




		Production expense	$	0.65	$	0.65	$	0.67	$	0.63




		Production taxes		0.24		0.22		0.25		0.21




		Depreciation, depletion and amortization		0.81		0.87		0.80		0.87




		General and administrative expenses		0.57		0.37		0.56		0.40




	GROSS OPERATING MARGIN (per Mcfe)		$	4.08	$	2.69	$	4.07	$	2.71


Definitions:


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




		natural gas equivalent





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





Average Price (per Mcf and Mcfe): Includes the effect of the Company’s natural gas hedging activities

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


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

		2003			2002			2003			2002

REVENUE




	Oil and gas production		89	%		85	%		89	%		79	%




	Drilling revenues		0	%		0	%		0	%		6	%




	Well operating, gathering and other		11	%		15	%		11	%		15	%





			100	%		100	%		100	%		100	%




COSTS AND EXPENSES




	Oil and gas production expenses		16	%		21	%		17	%		19	%




	Drilling costs		0	%		0	%		0	%		5	%




	Well operating, gathering and other		8	%		8	%		8	%		7	%




	Exploration expense		7	%		3	%		5	%		3	%




	General and administrative expenses		10	%		9	%		10	%		9	%




	Depreciation, depletion and amortization		15	%		21	%		14	%		19	%




	Interest (net)		3	%		6	%		4	%		6	%




	Income taxes		14	%		11	%		15	%		11	%

Total Expense			73	%		79	%		73	%		79	%

NET INCOME			27	%		21	%		27	%		21	%

The following discussion and analysis reviews the results of operations and the financial condition of the Company for the three and nine months ended September 30, 2003 and 2002. The review should be read in conjunction with the financial information presented elsewhere herein.

Comparison of Three Months Ended September 30, 2003 to September 30, 2002

Revenues

Oil and gas revenues increased $5,251,314 (57%) to $14,445,510 for the three months ended September 30th. Of this amount, $4,098,969 reflects higher prices received for natural gas and oil and $1,152,345 reflects higher production volumes. The Company’s production volumes for the three months ended September 30, 2003, were 2,909,031 Mcfe (Mcf equivalents) of natural gas compared to 2,585,038 Mcfe for the three months ended September 30, 2002. The Company recognizes a portion of the wellhead price it receives as gas gathering and other revenues to offset a portion of its cost 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 $4.97 and $3.56 per Mcfe for oil and natural gas sold for the three months ended September 30, 2003, and 2002, respectively.

Well operating, gathering and other revenue increased $117,659 (7%) to $1,766,291 for the three months ended September 30, 2003, compared to $1,648,632 for the three months ended September 30, 2002. This increase results from the higher price received for natural gas bought for resale, partially offset by the loss of administrative fee revenue resulting from the Company’s purchase of interests in 14 drilling programs in 2002.

Expenses

Oil and gas production expenses increased $333,452 (15%) to $2,565,363 for the three months ended September 30, 2003, from $2,231,911 for the three months ended September 30, 2002. This increase in production expense is due to higher production volumes and production taxes.

Well operating, gathering, and other expenses increased $445,871 (48%) for the three months ended September 30, 2003, to $1,366,896 from $921,025 at September 30, 2002, primarily as a result of increased spot prices on the open market for natural gas which has driven up the cost of the Company’s purchased gas for resale.

Exploration expense increased $898,437 (283%) for the three months ended September 30, 2003, to $1,215,721 from $317,284 for the corresponding three months ended September 30, 2002, which reflects an increase in the Company’s exploration activities (seismic and dry hole costs) and the addition of technical personnel. The Company recognized dry hole cost of approximately $574,000 for the three months ending September 30, 2003.

General and administrative expenses increased $701,529 (74%) to $1,648,753 for the three months ended September 30, 2003, from $947,224 for the three months ended September 30, 2002. This increase is largely the result of costs associated with the Company’s decision to explore its strategic alternatives to increase stockholder value.

The increase in depreciation, depletion and amortization (DD&A) of $94,980 (4%) to $2,352,710 for the three months ended September 30, 2003, from $2,257,730 for the three months ended September 30, 2002, is primarily the result of higher production volumes for the three months ended September 30, 2003, compared to the comparable period of 2002.

For the three months ended September 30, 2003, net interest expense decreased $148,856 to $542,086 compared to $690,942 for the three months ended September 30, 2002. The decrease reflects lower interest rates on the Company’s long-term debt, higher interest income earned on higher amounts invested in 2003 compared to 2002 and the repayment of $10,000,000 of long-term debt to Nuon International Renewables Projects, B.V.

Net Income

Net income for the three months ended September 30, 2003, increased $1,924,683 (84%) to $4,226,272 from $2,301,589 for the three months ended September 30, 2002, due to increased production volumes coupled with a $1.41 increase in the average price per Mcfe. The Company’s net income attributable to common stock was $4,226,272 ($.28/share basic and $.27/share diluted) for the three months ended September 30, 2003, compared to $2,301,589 ($.15/share basic and diluted) for the three months ended September 30, 2002.

Comparison of Nine Months Ended September 30, 2003 to September 30, 2002

Revenues

Oil and gas revenues increased $15,940,926 (61%) to $42,186,892 for the nine months ended September 30th. Of this amount, $12,220,312 reflects higher prices received for natural gas and oil and $3,740,614 reflects higher production volumes. The Company’s production volumes for the nine months ended September 30, 2003, were 8,446,860 Mcfe (Mcf equivalents) of natural gas compared to 7,393,174 Mcfe for the nine months ended September 30, 2002, an increase of 1,053,686 Mcfe or 14%. The Company recognizes a portion of the wellhead price it receives as gas gathering and other revenues to offset a portion of its cost 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 $4.99 and $3.55 per Mcfe for oil and natural gas sold for the nine months ended September 30, 2003, and 2002, respectively.

Drilling revenues decreased $2,082,351 (100%) to $0 for the nine months ended September 30, 2003, compared to $2,082,351 for the nine months ended September 30, 2002. This decrease reflects the Company’s decision to exit the drilling fund business to focus on its core business of exploration and production.

Well operating, gathering and other revenue decreased $21,191 to $5,018,799 for the nine months ended September 30, 2003, compared to $5,039,990 for the nine months ended September 30, 2002. The decrease resulted from the Company’s purchase of the interests in 14 of its drilling programs that were a source of administrative fee revenue to the Company. The overall decrease was partially offset by an increase in gas marketing revenue as a result of higher gas prices.

Expenses

Oil and gas production expenses increased $1,623,526 (26%) to $7,799,116 for the nine months ended September 30, 2003, from $6,175,590 for the nine months ended September 30, 2002. This increase is partly due to increased production taxes caused by higher oil and gas prices combined with increased production volumes. Also, the Company incurred unexpected clean-up costs due to late winter ice storms in March of 2003.

Drilling costs decreased $1,752,456 (100%) to $0 for the nine months ended September 30, 2003, compared to $1,752,456 at September 30, 2002, reflecting the Company’s transition to its core business of exploration and development.

Well operating, gathering, and other expenses increased $1,480,382 (59%) for the nine months ended September 30, 2003 to $4,003,930 from $2,523,548 at September 30, 2002. This increase is a result of increased spot prices on the open market for natural gas which has driven up the cost of the Company’s gas purchased for resale.

Exploration expense increased $1,426,812 (136%) for the nine months ended September 30, 2003, to $2,476,316 from $1,049,504 for the corresponding nine months ended September 30, 2002. This change reflects an increase in the Company’s exploration activities, specifically, dry hole expense, seismic costs and technical personnel.

General and administrative expenses increased $1,841,990 (63%) to $4,763,290 for the nine months ended September 30, 2003, from $2,921,300 for the nine months ended September 30, 2002. A significant portion of this increase is due to the retention of various professional services firms engaged to assist the Company in completing corporate projects and to evaluate the Company’s strategic options, as well as the addition of several key technical employees.

The increase in depreciation, depletion and amortization (DD&A) of $326,501 (5%) to $6,789,965 for the nine months ended September 30, 2003, from $6,463,464 for the nine months ended September 30, 2002, is primarily the result of higher production volumes for the nine months ended September 30, 2003, compared to the comparable period of 2002.

For the nine months ended September 30, 2003, net interest expense decreased $390,989 (19%) to $1,714,251 compared to $2,105,240 for the nine months ended September 30, 2002. The decrease reflects lower interest rates on the Company’s long-term debt and higher interest income resulting from amounts invested in 2003 compared to 2002.

Net Income

Net income for the nine months ended September 30, 2003, increased $5,872,450 (85%) to $12,743,323 from $6,870,873 for the nine months ended September 30, 2002, due to increased production volumes coupled with a $1.44 increase in the average price per Mcfe. The Company’s net income attributable to common stock was $12,743,323 ($.84/share basic and $.82/share diluted) for the nine months ended September 30, 2003, compared to $6,812,706 ($.45/share basic and diluted) for the nine months ended September 30, 2002. Dividends of $58,167 were declared and paid on the Company’s Series B Cumulative Preferred Stock for the three months ended March 31, 2002. All outstanding shares of the Company’s Series B Cumulative Preferred stock were redeemed on March 31, 2002.

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 exhibited substantial volatility in recent years as a result of forces such as OPEC production quotas, economic conditions, demand for and supply of natural gas in the United States and within the Company’s regional area of operation. Oil prices have increased as a result of political and labor unrest in Venezuela along with the conflict in Iraq. Natural gas prices have increased substantially for the three and nine months ended September 30, 2003, compared to natural gas prices for the corresponding periods in 2002. The increase in natural gas prices has been driven by a relatively cold winter causing greater demand for natural gas coupled with high volatility in the future markets. As a result of these market forces, the Company received an average price of $27.27 per barrel of oil for the nine months ended September 30, 2003, compared to $21.90 for the nine months ended September 30, 2002. The Company received an average price after recognition of a portion of the wellhead price as gas gathering revenues of $5.02 per MCF for its natural gas for the nine months ended September 30, 2003, compared to $3.54 for the nine months ended September 30, 2002. The Company cannot predict the duration of the current strength of oil and gas markets and prices, since the forces noted above as well as other variables are subject to change.

Liquidity and Capital Resources

The Company’s working capital was $12,075,008 at September 30, 2003, compared to $10,818,841 at December 31, 2002. The increase of $1,256,167 in working capital at September 30, 2003, reflects an increase in cash flow from operations offset by cash used for repayment of debt as well as capital expenditures during the period. The following table summarizes the Company’s financial position at September 30, 2003, and December 31, 2002:


		September 30, 2003				December 31, 2002

		Amount		%		Amount		%

			(Dollar amounts in Thousands)




Working capital		$	12,075		7	$	10,819		8




Property and equipment (net)			139,080		92		129,256		91




Other			585		1		1,329		1





	Total	$	151,740		100	$	141,404		100





Long-term debt		$	57,000		38	$	67,000		47




Deferred income taxes and other liabilities			17,698		12		9,667		7




Stockholders’ equity			77,042		50		64,737		46





	Total	$	151,740		100	$	141,404		100

The oil and gas exploration and development activities of NCE historically have been financed through 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, 2003 and 2002:


	September 30,			September 30,
	2003			2002

	(Dollar amounts in Thousands)
Net cash provided by operating activities	$	29,354		$	14,083




Net cash used by investing activities		(16,469	)		(19,938	)




Net cash used by financing activities		(10,625	)		(2,385	)

Increase (decrease) in cash and equivalents	$	2,260		$	(8,240	)

As the above table indicates, the Company’s cash provided by operating activities was $29,353,710 and $14,082,933 for the nine months ended September 30, 2003, and 2002, respectively. The increase in cash provided by operating activities was favorably impacted by an increase in net income, an increase in its year to date deferred tax provision and an increase in drilling liabilities partially offset by an increase in accounts receivable.

Net cash used for investing activities was $16,469,466 for the nine months ended September 30, 2003, compared to $19,937,969 for the nine months ended September 30, 2002. This decrease in cash used by investing activities reflects a decrease in the Company’s acquisitions in the 2003 period and the timing of its drilling expenditures.

Net cash used by financing activities was $10,624,721 for the nine months ended September 30, 2003, compared to $2,384,807 for the nine months ended September 30, 2002. The increase is primarily due to the repayment of $10,000,000 of long-term debt to affiliates and the redemption of the Company’s Series A Preferred Stock. The prior year’s activity is the result of the redemption of the Company’s Series B Preferred Stock.

At September 30, 2003, the Company had $23,000,000 available on its revolving line of credit and cash balances of $16,970,728. The Company believes that its cash balances, cash flow from operations and available borrowing capacity are adequate to fund its planned capital expenditures and operations.

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. The Company is exposed to commodity price risks related to its production of 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, 2002.

The Company is exposed to credit risk from its customer and other parties with which it does business. The Company has a credit approval policy that establishes 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 customer. The Company monitors the creditworthiness of its customers and, from time to time, will demand adequate assurances of performance if the creditworthiness of a particular 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 deemed by the Company to have acceptable creditworthiness.

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 September 30, 2003 (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 that occurred during the fiscal quarter ended September 30, 2003 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls.

NORTH COAST ENERGY, INC. AND SUBSIDIARIES

PART II
OTHER INFORMATION


Item 1.	Legal Proceedings




	Not applicable




Item 2.	Changes in Securities and Use of Proceeds




	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




		See Attached Index to Exhibits




	b.)	Report on Form 8-K filed August 6, 2003, regarding the Company’s second quarter earnings.




		Report on Form 8-K filed September 3, 2003, regarding the repayment of a loan from Nuon International Renewables Projects. B.V.




		No other 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.

Date: November 6, 2003		/s/ Gordon O. Yonel Gordon O. Yonel President, Chief Executive Officer and Director

		NORTH COAST ENERGY, INC.

Date: November 6, 2003		/s/ Dale E. Stitt Dale E. Stitt Chief Financial Officer and Principal Accounting Officer

Index to Exhibits


Exhibit
Number	Description of Documents	Page No.

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		25




31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002		26




32.1	Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350		27




32.2	Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350		28

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NORTH COAST ENERGY INC / DE/ 10-Q