Back to GetFilings.com
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 June 30, 2003.
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 [ ].
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 June 30, 2003
----- ----------------------------
Common Stock, $.01 par value 15,251,806
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
Page No.
--------
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - 3
June 30, 2003 (Unaudited) and December 31, 2002
Unaudited Consolidated Statements of Income - 5
For the Three and Six Months Ended June 30, 2003 and
2002
Unaudited Consolidated Statements of Cash Flows - 6
For the Six Months Ended June 30, 2003 and 2002
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 20
Risk
Item 4. Controls and Procedures 21
PART II - OTHER INFORMATION 22
2
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, 2003 and December 31, 2002
June 30, December 31,
ASSETS 2003 2002
- --------------------------------------------- ------------ ------------
(Unaudited)
CURRENT ASSETS
Cash and equivalents $ 23,315,214 $ 14,711,205
Accounts receivable 9,399,996 5,796,537
Inventories 438,137 353,722
Prepaid expenses 867,283 404,726
------------ ------------
Total current assets 34,020,630 21,266,190
PROPERTY AND EQUIPMENT, at cost
Land 222,822 222,822
Oil and gas properties (successful efforts) 150,071,567 143,952,276
Gathering systems 17,553,746 17,137,184
Vehicles 2,790,078 2,288,388
Furniture and fixtures 1,074,258 991,438
Buildings and improvements 2,170,862 1,877,667
------------ ------------
173,883,333 166,469,775
Less accumulated depreciation, depletion
and amortization 41,531,659 37,213,430
------------ ------------
132,351,674 129,256,345
OTHER ASSETS, net 856,299 1,328,595
------------ ------------
TOTAL ASSETS $167,228,603 $151,851,130
============ ============
The accompanying notes are an integral part of these consolidated
financial statements.
3
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
June 30, 2003 and December 31, 2002
June 30, December 31,
LIABILITIES AND STOCKHOLDERS' EQUITY 2003 2002
------------- -------------
(Unaudited)
CURRENT LIABILITIES
Accounts payable $ 4,318,491 $ 3,369,632
Accrued expenses 11,121,817 7,077,717
------------- -------------
Total current liabilities 15,440,308 10,447,349
LONG-TERM DEBT
Affiliates 10,000,000 10,000,000
Non-affiliates 57,000,000 57,000,000
------------- -------------
67,000,000 67,000,000
OTHER LONG-TERM LIABILITIES 1,640,246 208,456
DEFERRED INCOME TAXES 12,820,625 9,458,421
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Series A, 6% Noncumulative Convertible Preferred -- 723
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)
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; 60,000,000 152,518 152,086
shares authorized; 15,251,806 and 15,208,634 shares issued
and outstanding
Additional paid-in capital 47,264,681 47,889,111
Accumulated other comprehensive loss (3,732,035) (1,430,225)
Retained earnings 26,642,260 18,125,209
------------- -------------
Total stockholders' equity 70,327,424 64,736,904
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 167,228,603 $ 151,851,130
============= =============
The accompanying notes are an integral part of these consolidated
financial statements.
4
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2003 and 2002
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2003 2002 2003 2002
----------- ----------- ----------- -----------
REVENUE
Oil and gas production $14,692,999 $ 8,663,655 $27,741,382 $17,051,770
Drilling revenues 0 0 0 2,082,351
Well operating, gathering, and other 1,918,376 1,713,078 3,252,508 3,391,358
----------- ----------- ----------- -----------
16,611,375 10,376,733 30,993,890 22,525,479
COSTS AND EXPENSES
Oil and gas production expenses 2,653,592 2,025,199 5,233,753 3,943,679
Drilling costs 0 0 0 1,752,456
Well operating, gathering, and other 1,630,948 801,628 2,637,034 1,602,523
Exploration expense 738,262 504,890 1,260,595 732,220
General and administrative expenses 1,825,985 1,064,343 3,114,537 1,974,076
Depreciation, depletion and amortization 2,227,741 2,099,758 4,437,255 4,205,734
----------- ----------- ----------- -----------
9,076,528 6,495,818 16,683,174 14,210,688
----------- ----------- ----------- -----------
INCOME FROM OPERATIONS 7,534,847 3,880,915 14,310,716 8,314,791
INTEREST EXPENSE, NET
Interest income 128,106 86,453 238,720 168,573
Interest expense 697,842 795,074 1,410,885 1,582,871
----------- ----------- ----------- -----------
569,736 708,621 1,172,165 1,414,298
----------- ----------- ----------- -----------
INCOME BEFORE PROVISION
FOR INCOME TAXES 6,965,111 3,172,294 13,138,551 6,900,493
PROVISION FOR INCOME TAXES 2,453,000 1,063,000 4,621,500 2,331,209
----------- ----------- ----------- -----------
NET INCOME $ 4,512,111 $ 2,109,294 $ 8,517,051 $ 4,569,284
=========== =========== =========== ===========
NET INCOME APPLICABLE TO
COMMON STOCK (after dividends on
Cumulative Preferred Stock of $58,167 for the
six months ended June 30, 2002) $ 4,512,111 $ 2,109,294 $ 8,517,051 $ 4,511,117
=========== =========== =========== ===========
NET INCOME PER SHARE:
Basic $ 0.30 $ 0.14 $ 0.56 $ 0.30
=========== =========== =========== ===========
Diluted $ 0.29 $ 0.14 $ 0.55 $ 0.30
=========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
5
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2003 and 2002
(Unaudited)
June 30, June 30,
2003 2002
------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 8,517,051 $ 4,569,284
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 4,437,255 4,205,734
Deferred income taxes 4,621,500 2,273,799
Gain on sale of property and equipment (581) --
Change in:
Accounts receivable (3,603,459) (1,033,950)
Inventories and other current assets (546,972) (455,269)
Other assets, net 381,980 450,655
Accounts payable and accrued expenses 2,880,346 (1,317,953)
Billings in excess of costs on uncompleted contracts -- (2,062,094)
Other long-term liabilities (16,704) (46,253)
------------ ------------
Total adjustments 8,153,365 2,014,669
------------ ------------
Net cash provided by operating activities 16,670,416 6,583,953
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment (7,760,167) (11,894,621)
Proceeds on sale of property and equipment 318,481 1,275
Acquisition of property and equipment -- (1,456,833)
------------ ------------
Net cash used by investing activities (7,441,686) (13,350,179)
CASH FLOWS FROM FINANCING ACTIVITIES
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 -- (58,166)
------------ ------------
Net cash used by financing activities (624,721) (2,384,806)
------------ ------------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS 8,604,009 (9,151,032)
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD 14,711,205 22,035,924
------------ ------------
CASH AND EQUIVALENTS AT END OF PERIOD $ 23,315,214 $ 12,884,892
============ ============
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest $ 1,278,527 $ 1,640,304
Income taxes -- 32,012
The accompanying notes are an integral part of these consolidated
financial statements.
6
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.
7
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 estimate future proved
reserves related to the Company's current proved properties.
On sale or abandonment of an entire interest in an unproved property, 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 $3,600,000 at June 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 depreciated or depleted
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.
8
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 15,457,043 and 15,208,516 and
15,242,401 for the three months ended June 30, 2003 and 2002,
respectively, and 15,251,795 and 15,399,794 and 15,208,340 and 15,241,991
for the six months ended June 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 Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2003 2002 2003 2002
-------------- -------------- -------------- --------------
Net income as reported $ 4,512,111 $ 2,109,294 $ 8,517,051 $ 4,569,284
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax effects (217,700) -- (504,200) (103,300)
-------------- -------------- -------------- --------------
Pro forma net income $ 4,294,411 $ 2,109,294 $ 8,012,851 $ 4,465,984
Earnings per share:
Basic - as reported $ 0.30 $ 0.14 $ 0.56 $ 0.30
============== ============== ============== ==============
Diluted - as reported $ 0.29 $ 0.14 $ 0.55 $ 0.30
============== ============== ============== ==============
Basic - pro forma $ 0.28 $ 0.14 $ 0.53 $ 0.29
============== ============== ============== ==============
Diluted - pro forma $ 0.28 $ 0.14 $ 0.52 $ 0.29
============== ============== ============== ==============
9
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 six months ended June 30, 2002. All
shares of Series B Preferred Stock were redeemed March 31, 2002. In June
2003, the Company redeemed it's 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 $141,957 and $72,385 at
June 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.
A Director of the Company, Garry Regan, serves as the President of Nornew,
Inc. ("Nornew"), an entity that controls South Jamestown Gathering System,
LLC ("South Jamestown"). Prior to Mr. Regan's joining Nornew in July 2001,
South Jamestown had entered into a gas purchase agreement with the Company
for the sale of production from certain wells located in Erie and Warren
Counties in Pennsylvania. In March 2002, South Jamestown cancelled the
agreement, and, at the time, was in arrears for the payment of natural
gas. The largest amount due from South Jamestown in 2002 was $285,322.
After making several payments, South Jamestown executed a cognovit
promissory note in September 2002 for the balance then due of $209,285
bearing interest at the rate of 6% per annum. The balance of this
indebtedness was extinguished in April, 2003.
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 natural gas and oil. 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 June 30, 2003, the
Company has 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
10
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 fixed price on a portion of
its production. As a result of the costless collars revenues were
decreased by $1,534,000 and increased by $0 for the three months ended
June 30, 2003 and 2002, respectively, and revenues were decreased by
$4,563,000 and increased by $774,000 for the six months ended June 30,
2003 and 2002, respectively. The mark-to-market liability associated with
the collars at June 30, 2003 is $4,738,000.
The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed price contracts at June
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 @ 6/30/03
- -------------------- ----- ----- --- ----- ---------- ---------
September 30, 2003 1,670,000 $3.39 $4.48 458,000 $4.37 $5.39
December 31, 2003 1,670,000 3.39 4.48 384,000 4.85 5.65
March 31, 2004 1,815,000 3.84 6.01 391,000 5.00 5.81
June 30, 2004 1,820,000 3.84 6.01 224,000 4.87 4.93
September 30, 2004 1,840,000 3.84 6.01 114,000 5.52 4.88
December 31, 2004 1,840,000 3.84 6.01 88,000 5.86 5.11
Interest Rate Swaps: During 2001, 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.
As a result of the swap agreements, interest expense was increased by
approximately $186,000 and $401,000 for the three months and six months
ended June 30, 2003. The effect on interest expense was immaterial in the
three and six months ended June 30, 2002.
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 $1,094,000 at June 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 the Company hedges and the time periods covered by such hedges.
11
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 six months ended June 30, 2003 and 2002.
Three Months Ended June 30, Six Months Ended June 30,
----------------------------- -----------------------------
2003 2002 2003 2002
----------- ----------- ----------- -----------
Net income $ 4,512,111 $ 2,109,294 $ 8,517,051 $ 4,569,284
Change in mark-to-market liability
net of deferred taxes:
Natural gas hedge (738,647) (4,222) (2,215,727) (719,680)
Interest rate swaps (24,541) (252,028) (86,083) (252,028)
----------- ----------- ----------- -----------
Comprehensive income $ 3,748,923 $ 1,853,044 $ 6,215,241 $ 3,597,576
=========== =========== =========== ===========
NOTE 6. ACCOUNTING STANDARDS
In June 2001, FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations" which is 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 will be 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.
12
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 $10,000 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 a limited partner status 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, if any, against the Company 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.
13
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.
14
GENERAL
North Coast Energy, Inc., a Delaware corporation ("NCE" or the "Company"),
is an affiliate of n.v. 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 operations, gas gathering and gas marketing services it
provides for third parties.
The following table is a review of the results of operations of the
Company for the three and six months ended June 30, 2003 and 2002.
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2003 2002 2003 2002
--------- --------- --------- ---------
PRODUCTION
Oil production (MBbls) 31 22 55 50
Gas production (MMcf) 2,629 2,280 5,210 4,510
Total production (Mmcfe) 2,816 2,413 5,538 4,808
AVERAGE PRICES
Oil (per Bbl) $ 26.20 $ 22.47 $ 27.72 $ 19.81
Gas (per Mcf) 5.28 3.58 5.03 3.56
Average price per Mcfe 5.22 3.59 5.01 3.55
AVERAGE COSTS (per Mcfe)
Production expense $ 0.68 $ 0.61 $ 0.68 $ 0.61
Production taxes 0.26 0.23 0.26 0.21
Depreciation, depletion and amortization 0.79 0.87 0.80 0.88
General and administrative expense 0.65 0.44 0.56 0.41
GROSS OPERATING MARGIN (per Mcfe) 4.28 2.75 4.07 2.73
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)
Average Price (per Mcf and Mcfe): Includes the Effect of the Company's Natural
Gas Hedging Activities
15
All items in the table are calculated as a percentage of total revenues.
Three Months Ended Six Months Ended
June 30, June 30,
2003 2002 2003 2002
---- ---- ---- ----
REVENUE
Oil and gas production 88% 83% 90% 76%
Drilling revenue 0% 0% 0% 9%
Well operating, gathering and other 12% 17% 10% 15%
--- --- --- ---
Total Revenues 100% 100% 100% 100%
COST AND EXPENSES
Oil and gas production expenses 16% 20% 17% 18%
Drilling costs 0% 0% 0% 8%
Well operating, gathering and other 10% 8% 9% 7%
Exploration expense 4% 5% 4% 3%
General and administrative expense 11% 10% 10% 9%
Depreciation, depletion and amortization 14% 20% 14% 19%
Interest (net) 3% 7% 4% 6%
Income taxes 15% 10% 15% 10%
--- --- --- ---
Total Expense 73% 80% 73% 80%
--- --- --- ---
NET INCOME 27% 20% 27% 20%
=== === === ===
The following discussion and analysis reviews the results of operations
and the financial condition of the Company for the three and six months
ended June 30, 2003 and 2002. The review should be read in conjunction
with the financial information presented elsewhere herein.
16
COMPARISON OF THREE MONTHS ENDED JUNE 30, 2003 TO JUNE 30, 2002
REVENUES
Oil and gas revenues increased $6,029,344 (70%) to $14,692,999 for the
three months ended June 30, 2003, from $8,663,655 for the three months ended
June 30, 2002. The increase in oil and gas revenues primarily reflects higher
prices received for natural gas and oil and higher production volumes. The
Company's production volumes for the three months ended June 30, 2003, were
2,815,977 Mcfe (Mcf equivalents) of natural gas compared to 2,412,522 Mcfe for
the three months ended June 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 $5.22 and $3.59 per Mcfe for oil and
natural gas sold for the three months ended June 30, 2003 and 2002,
respectively.
Well operating, gathering and other revenue increased $205,298 (12%) to
$1,918,376 for the three months ended June 30, 2003, compared to $1,713,078 for
the three months ended June 30, 2002. This increase results from the higher
price of natural gas sold for resale, partially offset by the loss of
administrative fee revenue from the Company's purchase of 14 drilling programs
in 2002.
EXPENSES
Oil and gas production expenses increased $628,393 (31%) to $2,653,592 for
the three months ended June 30, 2003, from $2,025,199 for the three months ended
June 30, 2002. This increase is due to an increase in production expense due to
higher production volumes as well as an increase in production taxes the result
an increase in both oil and gas revenues as well as an increase in production
volumes.
Well operating, gathering, and other increased $829,320 (103%) for the
three months ended June 30, 2003 to $1,630,948 from $801,628 at June 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 $233,372 (46%) for the three months ended
June 30, 2003 to $738,262 from $504,890 for the corresponding three months ended
June 30, 2002, which reflects an increase in the Company's exploration
activities (lease acquisition and seismic costs) and personnel.
General and administrative expenses increased $761,642 (72%) to $1,825,985
for the three months ended June 30, 2003, from $1,064,343 for the three months
ended June 30, 2002. This increase is the result of the Company's decision to
retain an investment banking firm to assist the Company in exploring strategic
alternatives to increase shareholder value.
The increase in depreciation, depletion and amortization (DD&A) of
$127,983 (6%) to $2,227,741 for the three months ended June 30, 2003, from
$2,099,758 for the three months ended June 30, 2002, is primarily the result of
higher production volumes for the three months ended June 30, 2003, compared to
the comparable period of 2002.
For the three months ended June 30, 2003, net interest expense decreased
$138,885 to $569,736 compared to $708,621 for the three months ended June 30,
2002. The decrease reflects lower interest rates on the Company's long-term debt
and higher interest income earned on higher amounts invested in 2003 compared to
2002.
NET INCOME
Net income for the three months ended June 30, 2003, increased $2,402,817
(114%) to $4,512,111 from $2,109,294 for the three months ended June 30, 2002,
due to increased production volumes coupled with a $1.63 increase in the average
price per Mcfe. The Company's net income attributable to common stock was
$4,512,111 ($.30/share basic and $.29/share diluted) for the three months ended
June 30, 2003, compared to $2,109,294 ($.14/share basic and diluted) for the
three months ended June 30, 2002.
17
COMPARISON OF SIX MONTHS ENDED JUNE 30, 2003 TO JUNE 30, 2002
REVENUES
Oil and gas revenues increased $10,689,612 (63%) to $27,741,382 for the
six months ended June 30, 2003, from $17,051,770 for the six months ended June
30, 2002. The increase in oil and gas revenues primarily reflects higher prices
received for natural gas and oil and higher production volumes. The Company's
production volumes for the six months ended June 30, 2003, were 5,537,829 Mcfe
(Mcf equivalents) of natural gas compared to 4,808,136 Mcfe for the six months
ended June 30, 2002 an increase of 729,693 Mcfe or 15%. 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, Company received an average price of $5.01 and $3.55 per Mcfe for oil
and natural gas sold for the six months ended June 30, 2003 and 2002,
respectively.
Drilling revenues decreased $2,082,351 (100%) to $0 for the six months
ended June 30, 2003, compared to $2,082,351 for the six months ended June 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. In the six
months ended June 30, 2002, 12.4 wells were drilled for third parties.
Well operating, gathering and other revenue decreased $138,850 (4%) to
$3,252,508 for the six months ended June 30, 2003, compared to $3,391,358 for
the six months ended June 30, 2002. A decrease in well operating, gathering and
other revenue resulted from the Company's purchase of the outstanding interest
in 14 of its drilling programs that were the source of administrative fee
revenue to the Company. The overall decrease in well operating, gathering and
other revenue was offset by an increase in gas marketing revenue as a result of
higher gas prices. These two factors combined to yield this modest decrease for
the six months ended June 30, 2003 compared to the six months ended June 30,
2002.
EXPENSES
Oil and gas production expenses increased $1,290,074 (33%) to $5,233,753
for the six months ended June 30, 2003, from $3,943,679 for the six months ended
June 30, 2002. This increase is partly due to increased production taxes of
approximately $460,000 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 six months ended
June 30, 2003, compared to $1,752,455 at June 30, 2002, reflecting the Company's
shift to its core business of exploration and development.
Well operating, gathering, and other increased $1,034,511 (65%) for the
six months ended June 30, 2003 to $2,637,034 from $1,602,523 at June 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 purchased gas for
resale.
Exploration expense increased $528,375 (72%) for the six months ended June
30, 2003 to $1,260,595 from $732,220 for the corresponding six months ended June
30, 2002. This change reflects an increase in the Company's exploration
activities (lease acquisition and seismic costs) and personnel.
General and administrative expenses increased $1,140,461 (58%) to
$3,114,537 for the six months ended June 30, 2003, from $1,974,076 for the six
months ended June 30, 2002. A significant portion of this increase is due to the
retention of professional services firms to evaluate the Company's strategic
options, as well as the addition of several key employees including, but not
limited to, a Vice President for Exploration and Production and a Geophysicist.
The increase in depreciation, depletion and amortization (DD&A) of
$231,521 (6%) to $4,437,255 for the six months ended June 30, 2003, from
$4,205,734 for the six months ended June 30, 2002, is primarily the result of
higher production volumes for the six months ended June 30, 2003, compared to
the comparable period of 2002.
18
For the six months ended June 30, 2003, net interest expense decreased
$242,133 to $1,172,165 compared to $1,414,298 for the six months ended June 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 six months ended June 30, 2003, increased $3,947,767
(86%) to $8,517,051 from $4,569,284 for the six months ended June 30, 2002, due
to increased production volumes coupled with a $1.46 increase in the average
price per Mcfe. The Company's net income attributable to common stock was
$8,517,051 ($.56/share) for the six months ended June 30, 2003, compared to
$4,511,117 ($.30/share) for the six months ended June 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 not followed inflation and have fluctuated during recent years
as a result of other forces such as OPEC, economic factors, 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 for the three and six months ended June 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 $27.72 per barrel
of oil for the six months ended June 30, 2003, compared to $19.81 for the six
months ended June 30, 2002. The Company received an average price after
recognition of a portion of the wellhead price as gas gathering revenues of
$5.03 per MCF for its natural gas for the six months ended June 30, 2003,
compared to $3.56 for the six months ended June 30, 2002. The Company cannot
predict the duration of the current strength of oil and gas markets and prices,
since those forces noted above as well as other variables may change.
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital was $18,580,322 at June 30, 2003, compared
to $10,818,841 at December 31, 2002. The increase of $7,761,491 in working
capital at June 30, 2003, reflects the cash flow from operations and financing
offset by cash used for capital expenditures during the period. The following
table summarizes the Company's financial position at June 30, 2003, and December
31, 2002:
June 30, 2003 December 31, 2002
------------------- -------------------
Amount % Amount %
-------- --- -------- ---
(Dollar amounts in Thousands)
Working capital $ 18,580 12 $ 10,819 8
Property and equipment (net) 132,352 87 129,256 91
Other 856 1 1,329 1
-------- --- -------- ---
Total $151,788 100 $141,404 100
======== === ======== ===
Long-term debt $ 67,000 44 $ 67,000 47
Deferred income taxes and other liabilities 14,461 10 9,667 7
Stockholder's equity 70,327 46 64,737 46
-------- --- -------- ---
Total $151,788 100 $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.
19
The following table summarizes the Company's Statements of Cash Flows for
the six months ended June 30, 2003 and 2002:
June 30, June 30,
2003 2002
-------- --------
(Dollar amounts in Thousands)
Net cash provided by operating activities $ 16,671 $ 6,584
Net cash used by investing activities (7,442) (13,350)
Net cash used by financing activities (625) (2,385)
-------- --------
Increase (decrease) in cash and equivalents $ 8,604 $ (9,151)
======== ========
As the above table indicates, the Company's cash provided by operating
activities was $16,670,416 and $6,583,953 for the six months ended June 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 a increase in drilling liabilities
partially offset by an increase in accounts receivable.
Net cash used for investing activities was $7,441,686 for the six months
ended June 30, 2003, compared to $13,350,179 for the six months ended June 30,
2002. This decrease in cash used by investing activities is a result of a less
aggressive current year drilling program and unfavorable late spring weather
which delayed drilling activities.
Net cash used by financing activities was $624,721 for the six months
ended June 30, 2003, due to the redemption of the Company's Series A Preferred
Stock. For the six months ended June 30, 2002, net cash used by financing
activities was $2,384,806 primarily for the redemption of the Company's Series B
Cumulative Preferred Shares.
At June 30, 2003, the Company has $23,000,000 available on its revolving
line of credit and cash balances of $23,315,214. The Company believes that its
cash, 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 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, 2002.
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.
20
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.
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.
21
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
On or about April 25, 2003, a Proxy Statement was mailed to all holders
of record as of April 15, 2003, of the Company's common stock and Series
A Preferred Stock along with a Notice of Annual Meeting of Stockholders
to be held on June 12, 2003. At the meeting, the stockholders were asked
to consider and act upon the election of two directors whose terms of
office expire in 2006. The Proxy Statement filed with the Securities and
Exchange Commission on April 21, 2003, is incorporated by reference
herein.
At the Annual Meeting of Stockholders held on June 12, 2003, director
Ron L. Langenkamp was reelected, and nominee Joe K. Ward was elected, to
three-year terms by votes of 15,137,879 and 15,138,046, respectively, in
favor and 14,433 and 14,266 respectively, opposed. Directors Gordon O.
Yonel, Pieter Jobsis, Cok van der Horst, Joop Drechsel and Garry Regan
continue in office.
At the Annual Meeting of Stockholders, 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 by votes of
15,062,113 in favor and 76,698 opposed.
Item 5. Other Information
Not applicable
Item 6. Exhibits and Reports on Form 8-K
a.) Exhibits
See Exhibit Index
b) Report on Form 8-K dated April 21, 2003, concerning the press
release dated April 21, 2003, related to the Company's engagement
of R. W. Baird & Co.
Report on Form 8-K dated May 8, 2003, concerning the press release
dated May 8, 2003, related to the Company's earnings for the first
quarter of fiscal 2003.
No other reports on Form 8-K have been filed during the quarter
for which this report was filed.
22
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: August 5, 2003 /s/ Gordon O. Yonel
--------------------------------------
Gordon O. Yonel
President, Chief Executive Officer
and Director
NORTH COAST ENERGY, INC.
Date: August 5, 2003 /s/ Dale E. Stitt
--------------------------------------
Dale E. Stitt
Chief Financial Officer and
Principal Accounting Officer
23
Exhibit Index
Exhibit Sequential
Number Description of Documents Page
------ ------------------------ ----
10.40 North Coast Energy, Inc. 1999 Employee Stock Option
Plan (Amended and Restated)
31.1 Certification of Principal Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, 18 U.S.C.
Section 1350
31.2 Certification of the Principal Financial Officer Pursuant
to the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350
32.1 Certification of Principal Executive Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, 18
U.S.C. Section 1350
32.2 Certification of Principal Financial Officer Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, 18
U.S.C. Section 1350
24