<PAGE> 1
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1995
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.)
5311 NORTHFIELD ROAD, SUITE 320
CLEVELAND, OHIO 44146-1135
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (216) 663-1668
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
--- ---
APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:
Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 12, 13, or 15 (d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.
Yes No
--- ---
APPLICABLE ONLY TO CORPORATE ISSUERS:
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date. Indicate the number of shares
outstanding of each of the issuer's classes of Common Stock as the latest
practical date.
Class Outstanding at November 8, 1995
---------------------------- -------------------------------
Common Stock, $.01 par value 8,034,007
<PAGE> 2
<TABLE>
NORTH COAST ENERGY, INC.
<CAPTION>
Page No.
-------
<S> <C>
PART I - FINANCIAL INFORMATION
Consolidated Balance Sheets -
March 31, 1995 (Audited) and September 30, 1995 (Unaudited) 2
Unaudited Consolidated Statements of Operations -
For the Three and Six Months Ended September 30, 1994 and 1995 4
Unaudited Consolidated Statements of Cash Flows -
For the Six Months Ended September 30, 1994 and 1995 5
Unaudited Notes to Consolidated Financial Statements 7
Management's Discussion and Analysis of Financial Condition
and Results of Operations 11
PART II - OTHER INFORMATION 19
</TABLE>
<PAGE> 3
<TABLE>
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 1995 and September 30, 1995
(Unaudited)
<CAPTION>
March 31, September 30,
1995 1995
---- ----
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS
Cash and equivalents $ 2,366,660 $ 804,779
Accounts receivable:
Trade 1,592,321 1,246,832
Affiliates 59,243 1,620,281
Refundable income taxes - 61,000
Inventory 218,628 73,843
Deferred income taxes 59,000 61,000
Other 7,682 116,802
------------- -------------
Total current assets 4,303,534 3,984,537
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Land 122,699 122,699
Oil and gas properties (successful
efforts) 21,051,552 22,151,115
Pipelines 3,187,714 3,476,376
Vehicles 384,241 414,737
Furniture and fixtures 362,288 417,381
Building and improvements 145,539 145,539
------------- -------------
25,254,033 26,727,847
Less accumulated depreciation, depletion,
amortization and write-down (8,867,435) (9,747,511)
------------- -------------
16,386,598 16,980,336
OTHER ASSETS 445,534 422,087
------------- -------------
$ 21,135,666 $ 21,386,960
============= =============
The accompanying notes are an integral part of these Balance Sheets
</TABLE>
2
<PAGE> 4
<TABLE>
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 1995 and September 30, 1995
(Unaudited)
<CAPTION>
March 31, September 30,
1995 1995
---- ----
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ----------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt $ 432,100 $ 286,900
Accounts payable 3,644,368 2,083,347
Accrued expenses 423,981 274,594
Billings in excess of costs on
uncompleted contracts 284,880 1,619,512
------------ ------------
Total current liabilities 4,785,329 4,264,353
------------ ------------
LONG-TERM DEBT 6,197,450 8,092,681
DEFERRED INCOME TAXES 930,000 649,000
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Series A, 6% Non-Cumulative Convertible Preferred
stock, par value $.01 per share; 563,270 shares
authorized; 309,460 and 308,370 issued and out-
standing (aggregate liquidation value of
$3,094,600 and $3,083,700, respectively) 3,095 3,084
Series B, Cumulative Convertible Preferred stock,
par value $.01 per share; 625,000 shares author-
ized; 464,665 and 464,665 issued and outstanding
(aggregate liquidation value of $4,646,650
and $4,646,650, respectively) 4,647 4,647
Undesignated Serial Preferred stock, par
value $.01 per share; 811,730 shares
authorized; none issued and outstanding - -
Common stock, par value $.01 per share;
40,000,000 shares authorized; 8,030,352
and 8,032,857 issued and outstanding 80,304 80,329
Additional paid-in capital 12,083,024 12,083,007
Retained deficit (2,948,183) (3,790,141)
------------ ------------
Total stockholders' equity 9,222,887 8,380,926
------------ ------------
$ 21,135,666 $ 21,386,960
============ ============
The accompanying notes are an integral part of these Balance Sheets
</TABLE>
3
<PAGE> 5
<TABLE>
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For The Periods Ended September 30, 1994 and 1995
(Unaudited)
<CAPTION>
Three Months Ended Six Months Ended
--------------------- ----------------
1994 1995 1994 1995
---- ---- ---- ----
<S> <C> <C> <C> <C>
REVENUE:
Oil and gas production $ 666,865 $ 576,508 $ 1,395,602 $ 1,320,880
Drilling revenues 751,800 134,250 1,754,200 303,000
Well operating, transportation and other 367,486 408,809 933,001 868,419
Administrative and agency fees 209,531 238,782 360,259 431,523
------------ ------------ ------------ ------------
1,995,682 1,358,349 4,443,062 2,923,822
COSTS AND EXPENSES:
Oil and gas production expenses 143,753 209,795 267,415 411,539
Drilling costs 632,508 209,204 1,526,216 357,446
Oil and gas operations 208,011 171,116 553,550 403,435
General and administrative expenses 736,119 670,536 1,311,815 1,327,431
Depreciation, depletion, amortization,
and other 519,297 468,225 869,816 963,460
Abandonment of oil and gas properties - - 144,923 -
------------ ------------ ------------ ------------
2,239,688 1,728,876 4,673,735 3,463,311
------------ ------------ ------------ ------------
LOSS FROM OPERATIONS ( 244,006) ( 370,527) ( 230,673) ( 539,489)
------------ ------------ ------------ ------------
OTHER INCOME
Interest 13,751 16,188 23,207 36,961
Other - 3,004 - 7,658
Gain on sale of property
and equipment 6,545 - 3,516 8,943
------------ ------------ ------------ ------------
20,296 19,192 26,723 53,562
------------ ------------ ------------ ------------
OTHER EXPENSE
Interest 122,532 202,765 215,609 372,864
------------ ------------ ------------ ------------
LOSS BEFORE INCOME TAXE ( 346,242) ( 554,100) ( 419,559) ( 858,791)
PROVISION (CREDIT) FOR TAXES
ON INCOME
Current ( 145,800) - ( 146,000) ( 61,000)
Deferred ( 36,000) ( 211,000) ( 49,000) ( 281,000)
------------ ------------ ------------ ------------
( 181,800) ( 211,000) ( 195,000) ( 342,000)
------------ ------------ ------------ ------------
NET LOSS $( 164,442) $( 343,100) $ ( 224,559) $ ( 516,791)
============ ============ ============ ============
NET LOSS PER SHARE
(primary and fully diluted) $( .04) $( .06) $ ( .09) $ ( .10)
============ ============ ============ ============
The accompanying notes are an integral part of these Financial Statements
</TABLE>
4
<PAGE> 6
<TABLE>
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Six Months Ended September 30, 1994 and 1995
(Unaudited)
<CAPTION>
1994 1995
---- -----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ ( 224,559) ( 516,791)
Adjustments to reconcile net loss
to cash provided by operating activities-
Depreciation, depletion, amortization and other 869,816 963,460
Abandonment of oil and gas properties 144,923 -
Gain on sale of property and equipment ( 3,516) ( 8,943)
Deferred income taxes ( 49,000) ( 281,000)
Change in:
Accounts receivable 11,656 (1,276,549)
Other current assets ( 207,697) 33,665
Other assets ( 4,047) 14,964
Accounts payable ( 38,471) (1,558,151)
Current income taxes payable ( 95,000) -
Accrued expenses ( 32,064) ( 149,388)
Billings in excess of costs on uncompleted contracts 1,395,026 1,334,632
------------ ------------
Total adjustments 1,991,626 ( 927,310)
------------ ------------
Net cash provided (used) by operating activities 1,767,067 (1,444,101)
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment (1,487,115) (1,217,218)
Proceeds on sale of property and equipment 4,000 -
------------ ------------
Net cash used by investing activities (1,483,115) (1,217,218)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of accounts payable used to
finance property and equipment additions ( 335,552) ( 236,422)
Borrowings under revolving credit facility 2,095,000 1,000,000
Borrowings under note payable to stockholder - 1,000,000
Repayments of borrowings under revolving credit facility ( 165,772) ( 240,003)
Payments on long-term ( 45,358) ( 52,824)
Cash paid for deferred financing cost ( 5,512) ( 46,142)
Distributions and dividends ( 328,323) ( 325,171)
Proceeds from the exercise of Common Stock options 22,500 -
Proceeds from the issuance of Common Stock 1,871,500 -
------------ ------------
Net cash provided by financing activities 3,108,483 1,099,438
------------ ------------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS 3,392,435 (1,561,881)
The accompanying notes are an integral part of these Financial Statements
</TABLE>
5
<PAGE> 7
<TABLE>
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
For The Six Months Ended September 30, 1994 and 1995
(Unaudited)
<CAPTION>
1994 1995
---- ----
<S> <C> <C>
CASH AND EQUIVALENTS AT BEGINNING OF PERIOD $ 1,295,642 $ 2,366,660
--------- ---------
CASH AND EQUIVALENTS AT END OF PERIOD $ 4,688,077 $ 804,779
========= ==========
SUPPLEMENTAL DISCLOSURES OF CASH FLOWS INFORMATION:
Cash paid during the period for:
Interest $ 217,112 $ 343,116
Income taxes 187,502 71,135
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING
AND FINANCING ACTIVITIES:
Long-term debt incurred for the purchase
of property and equipment $ 43,895 $ 42,860
Accounts payable incurred for the
purchase of property and equipment 122,273 233,552
Increase in accounts receivable due to the sale of
property and equipment 8,144 -
The accompanying notes are an integral part of these Financial Statements
</TABLE>
6
<PAGE> 8
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1. Summary of Accounting Policies
A. General
The consolidated financial statements included herein, have been
prepared by North Coast Energy, Inc. without audit. In the
opinion of management, all adjustments (which include only normal
recurring adjustments) necessary to present fairly the financial
position have been made.
Information and footnote disclosures normally included in
financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted.
It is suggested that these financial statements be read
in conjunction with the financial statements and notes thereto
which are incorporated in the Company's Annual Report on Form 10-K
for the fiscal year ended March 31, 1995.
The results of the operations for the interim periods may not
necessarily be indicative of the results to be expected for the
full year.
B. Principles of Consolidation
The consolidated financial statements include the accounts of
North Coast Energy, Inc. and its wholly owned subsidiaries (the
Company), North Coast Operating Company (NCOC), and NCE
Securities, Inc. (NCE Securities). In addition, the Company's
investments in oil and gas drilling partnerships, which are
accounted for under the proportional consolidation method, are
reflected in the accompanying financial statements. The Company's
ownership of revenues in these drilling partnerships are as
follows:
Capital Drilling Fund 1986-1 Limited Partnership 13.2%
North Coast Energy/Capital 1987-1 Appalachian Drilling
Program Limited Partnership 33.7%
North Coast Energy/Capital 1987-2 Appalachian Drilling
Program Limited Partnership 26.1%
North Coast Energy/Capital 1988-1 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy/Capital 1988-2 Appalachian Drilling
Program Limited Partnership 25.0%
North Coast Energy 1989 Appalachian Drilling Program
Limited Partnership 30.0%
North Coast Energy 1990-1 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1990-2 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1990-3 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1991-1 Appalachian Drilling Program
Limited Partnership 26.5%
North Coast Energy 1991-2 Appalachian Drilling Program
Limited Partnership 25.0%
7
<PAGE> 9
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Note 1. Summary of Accounting Policies (Continued)
North Coast Energy 1991-3 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1992-1 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1992-2 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1992-3 Appalachian Drilling Program
Limited Partnership 39.5%
North Coast Energy 1993-1 Appalachian Drilling Program
Limited Partnership 30.3%
North Coast Energy 1993-2 Appalachian Drilling Program
Limited Partnership 31.0%
North Coast Energy 1993-3 Appalachian Drilling Program
Limited Partnership 30.0%
North Coast Energy 1994-1 Appalachian Drilling Program
Limited Partnership 30.0%
North Coast Energy 1994-2 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1994-3 Appalachian Drilling Program
Limited Partnership 25.0%
North Coast Energy 1995-1 Appalachian Drilling Program
Limited Partnership 20.0%
All significant intercompany accounts and transactions have
been eliminated.
Note 2. Long-Term Debt
Long-term debt consists of the following:
<TABLE>
<CAPTION>
March 31, 1995 September 30, 1995
-------------- ------------------
<S> <C> <C>
Revolving credit notes
payable - bank $ 6,050,003 $ 6,810,000
Other financing 335,000 1,335,000
Mortgage note payable to a bank, secured by land and
a building, requiring monthly payments of approximately
$1,019 (including interest at 8%) through July 1998.
Thereafter, the balance of the note will be amortized
over a 5 year period, at an interest rate to be renegotiated. 73,790 70,605
Various installment notes payable, in aggregate monthly
installments (including interest of $8,585 at March 31,
1995 and $9,475 at September 30, 1995). 170,757 163,976
---------- ----------
6,629,550 8,379,581
Less current portion 432,100 286,900
---------- ----------
$ 6,197,450 $ 8,092,681
========== ==========
</TABLE>
8
<PAGE> 10
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Note 2. Long-Term Debt (Continued)
On September 20, 1993, the Company entered into an agreement with
its lender to provide a reducing revolving line of credit of up to
$10,000,000. Subsequently, a draw was made on the new line of
credit to pay off certain of the Company's term loans. Available
borrowings under this agreement are computed based on a borrowing
base determined semi-annually by the lender, based upon the
Company's financial position, and level of oil and gas and
pipeline based reserves and are further based upon the amount of
outstanding letters of credit used to support certain bonding
requirements ($130,000 at September 30, 1995). The borrowing base
is reduced monthly by an amount determined by the lender at the
semi-annual borrowing base determination. At September 30, 1995,
the borrowing base was $8,270,000, with required monthly
reductions of $100,000. An amendment to the credit agreement
effective August 8, 1995 increased the borrowing base to
$8,500,000, with required monthly reductions of $100,000 beginning
on September 1, 1995.
Amounts outstanding under the reducing revolving line of credit,
which were $6,810,000 at September 30, 1995, bear interest at the
lending bank's prime rate plus 1-1/2%. The agreement requires the
Company to pay a commitment fee of 1/2% on the unused amount of
the available borrowings and closing costs of 1% on any increase
in borrowing availability. The agreement contains certain
restrictive covenants, including minimum working capital, minimum
shareholders' equity and a minimum debt coverage ratio, all as
defined. The Company was in compliance with or had received
waivers with respect to all covenants as of September 30, 1995.
In addition, there are restrictions on mergers, capital stock
dividends and stock repurchases, issuance of additional
securities, sale of assets, investments, rental agreements and the
incurrence of additional debt. The dividend restriction does not
permit dividends on any shares of the Company's capital stock
(other than dividends payable solely in shares of its capital
stock and the dividends on the Company's Preferred Stock).
The Company secured $335,000 in financing from NAGIT, a principal
stockholder of the Company, relating to the purchase of certain
producing wells, gas gathering lines and drilling locations. The
amounts outstanding under the terms of the Company's financing
arrangements with NAGIT are subordinated to the prior payment and
amounts outstanding under the Company's credit agreement, and bear
an interest rate at the prime rate designated by the Chemical
Bank, N.A., plus 1%. This agreement grants NAGIT a 3.125%
overriding royalty interest in the acquired properties. Repayment
of the loan is in cash based upon a percentage of the net monthly
revenues from the acquired properties.
Effective June 13, 1995, the Company entered into a Loan Agreement
with NAGIT with respect to a loan of $1,000,000. The unsecured
loan is due December 29, 1995 and may be repaid in cash plus
accrued interest (with approval of the Company's senior lender)
prior to December 29, 1995 or may be converted, after such date,
into shares of Common Stock at the rate of $1.00 per share. The
loan is subordinate to the Company's senior lender and bears
interest at the rate of 8% per annum. In connection with entering
into the Loan Agreement, the Company issued a warrant to purchase
200,000 shares of Common Stock at $1.20 per share and a warrant to
purchase 300,000 shares of Common Stock at $1.00 per share. The
warrants may be redeemed by the Company at its option upon 30 days
written notice.
9
<PAGE> 11
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Note 3. Billings in Excess of Costs on Uncompleted Contracts
Billings in excess of costs on uncompleted contracts consist of:
<TABLE>
<CAPTION>
March 31, September 30,
1995 1995
---- ----
<S> <C> <C>
Billings on uncompleted contracts $ 687,850 $ 1,888,450
Costs incurred on uncompleted contracts 402,970 268,938
----------- -----------
$ 284,880 $ 1,619,512
============ ============
</TABLE>
Note 4. Commitment and Contingencies
The Company and a commercial bank have issued standby letters of
credit which provide a guaranteed total amount of $130,000 in lieu
of coverage provided by insurance or road bond deposits against
damage.
At September 30, 1995, the Company has committed to fund certain
costs of the North Coast Energy Appalachian Drilling Programs
estimated to be approximately $428,956 for tangible well equipment
and pipeline construction. This commitment is expected to be
realized by December 1995.
10
<PAGE> 12
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
North Coast Energy, Inc., (the "Company") a Delaware corporation, is
an independent natural gas and oil company engaged in exploration, development
and production activities primarily in the Appalachian Basin region of Ohio and
Pennsylvania. The Company's strategy focuses primarily on the acquisition of
proved undeveloped natural gas and oil properties and on the turnkey drilling
and development of such properties by the Company in conjunction with drilling
partnerships which the Company sponsors and manages (the "Drilling Programs").
The Drilling Programs are funded through the sale of partnership interests to
non-industry investors and by contributions from the Company.
Several factors may affect the amount and timing of the Company's
revenues with respect to the activities of the Drilling Programs. The amount of
funds raised by each Drilling Program determines the number of wells for which
the Company receives drilling revenues and the date at which the wells reach a
certain point in the completion process determines the timing of revenue
recognition. The Company continually monitors the cost incurred in drilling,
completion and production operations and reviews its turnkey drilling contract
prices for each Drilling Program in order to reduce the risk of unprofitable
drilling operations. The turnkey drilling contract price between the Drilling
Programs and the Company may vary from Drilling Program to Drilling Program
depending on competition, type of well drilled and other cost factors and the
returns sought by investors in the Drilling Programs. In general, a smaller
percentage ownership interest by the Company in a Drilling Program (assuming no
change in the turnkey drilling contract price charged by the Company to the
Drilling Programs) would result in a larger amount of drilling revenue
recognized by the Company from such Drilling Program, as well as a larger
amount of oil field service and other fees. A smaller ownership interest by
the Company in a Drilling Program results in the Company receiving a smaller
share of the oil and gas production revenues from the related Drilling
Program's wells, as well as decreasing the Company's percentage interest in the
gas and oil reserves related to such wells. The Company's capital
availability, as well as revenue and profit considerations, may result in the
Company changing its percentage interest in future Drilling Programs.
The Company typically forms the Drilling Programs between August and
December in each year and conducts its drilling operations between October and
March. It generally requires six months between the drilling of a well and the
generation of production revenue from that well. Drilling revenues are
predominantly recognized during the second half of the Company's fiscal year.
The following table is a review of the results of operations of the
Company for the three and six months ended September 30, 1994 and 1995. All
items in the table are calculated as a percentage of total revenues.
<TABLE>
<CAPTION>
Three Months Six Months
Ended Ended
September 30, September 30,
------------- -------------
1994 1995 1994 1995
------------- -------------
<S> <C> <C> <C> <C>
Revenues:
- ---------
Oil and gas production 33% 42% 31% 44%
Drilling revenues 37 10 39 10
Well operating, transportation and other 19 30 21 29
Administrative and agency fees 10 17 8 15
Other 1 1 1 2
---- ---- ---- ----
Total Revenues 100% 100% 100% 100%
---- ---- ---- ----
</TABLE>
11
<PAGE> 13
<TABLE>
<S> <C> <C> <C> <C>
Expenses:
Oil and gas production expenses 7% 15% 6% 14%
Drilling costs 31 15 34 12
Oil and gas operations 10 12 12 13
General and administrative expenses 37 49 29 45
Depreciation, depletion, amortization and other 26 34 20 32
Abandonment of oil and gas properties 0 0 3 0
Provision for taxes on income (9) (15) (4) (11)
Other 6 15 5 12
----- ----- ----- -----
Total Expenses 108% 125% 105% 117%
----- ----- ----- -----
Net Loss ( 8%) ( 25%) ( 5%) ( 17%)
===== ===== ===== =====
</TABLE>
The following discussion and analysis reviews the results of
operations and the financial condition for the Company for the three and six
months ended September 30, 1995 and 1994. The review should be read in
conjunction with the financial information presented elsewhere herein.
COMPARISON OF SIX MONTHS ENDED SEPTEMBER 30, 1995 TO SIX MONTHS ENDED SEPTEMBER
30, 1994.
REVENUES
Oil and gas production revenues decreased $74,722 (5%) to $1,320,880
for the six months ended September 30, 1995 compared to $1,395,602 for the
prior corresponding period. Revenues were effected by lower oil and gas
production from wells in the Gulf Coast area with one well being temporarily
shut-in for reworking coupled with lower gas prices received by the Company.
The average gas prices the Company received decreased approximately 10% to
$2.07 per Mcf for the six months ended September 30, 1995 compared to $2.30
per Mcf for the six months ended September 30, 1994.
Drilling Revenues for the period decreased by $1,451,200 (83%) for the
six months ended September 30, 1995 compared to the six months ended September
30, 1994 due to the Company forming its first fiscal 1996 drilling program on
September 30, 1995, forty five days later than the first fiscal 1995 drilling
program. The Company recognized revenues for the six months ended September 30,
1995 on four wells compared to fourteen wells for the six months ended
September 30, 1994. Three of the four wells recognized in revenue for the six
months ended September 30, 1995 were shallow oil wells for which the Company
generally charges a lower turnkey drilling contract price compared to
the fourteen deeper gas wells which were recognized in revenue for the six
months ended September 30, 1994. The Company also has not completed three wells
from its fiscal 1995 drilling schedule which were delayed due to mechanical
problems and anticipates completing these wells in the Company's fiscal third
quarter.
Revenues generated from well operating, transportation, gas marketing
and compression increased approximately $113,000 (16%) while unaffiliated third
party gas sales declined approximately $178,000 for the six months ended
September 30, 1995 as compared to the six months ended September 30, 1994. For
the six months ended September 30, 1995, well operating, transportation
and other revenues decreased $64,582 (7%) compared to the six months
ended September 30, 1994 again primarily due to a decline in third party gas
sales.
Revenues from administrative and agency fees, which are based on a
percentage of the total investor capital raised in all of the Drilling
Programs, increased by $71,264 (20%) for the six months ended September
30, 1995 compared to the six months ended September 30, 1994 primarily due
to the formation of the first Drilling
12
<PAGE> 14
Program of fiscal 1996 coupled with the increase from ongoing administrative
fees accrued from the fiscal 1995 Drilling Programs.
EXPENSES
Oil and gas production expenses increased $144,124 (54%) for the six
months ended September 30, 1995 compared to the six months ended September 30,
1994. This increase was primarily due to costs associated with reworking a
well in the Gulf Coast area and costs associated with the production
enhancement program on the 163 wells the Company acquired in December 1994.
The Company expects to rework one other Gulf Coast well in the third quarter of
fiscal 1996 for a cost of approximately $28,000 in an effort to increase its
production to an acceptable level.
Drilling costs for the six months ended September 30, 1995 compared to
the six months ended September 30, 1994 decreased $1,168,770 (77%) due to the
decreased number of wells completed between the comparable periods. The
profit margin on drilling revenue was affected by overhead associated with its
drilling activities and by preparations for drilling approximately 19 wells
for the first fiscal 1996 Drilling Program formed September 30, 1995. It is
anticipated that the per well overhead cost will decline as additional wells
are drilled and completed.
Oil and gas operations expense decreased $150,115 (27%) for the six
months ended September 30, 1995 as compared to the six months ended September
30, 1994. This decrease was primarily due to the decrease in unaffiliated
third party gas purchases related to third party gas sales as discussed above.
Depreciation, depletion, amortization and other increased $93,644 (11%)
for the six months ended September 30, 1995 compared to the six months ended
September 30, 1994. This increase was primarily due to increases in
depreciation associated with the Company's increased investment in pipelines
and equipment during recent periods, amortization of costs associated with the
reducing revolving line of credit and depletion associated with the
capitalization of additional organizational costs related to the Drilling
Programs. The Company continues to capitalize certain organizational costs
associated with the Drilling Programs resulting in an increased depletable
basis of its investment.
Abandonment of oil and gas properties decreased $144,923 for the six
months ended September 30, 1995 as compared to the six months ended September
30, 1994. The Company did not abandon any oil and gas properties for the six
months ended September 30, 1995.
Interest expense increased to $372,864 for the six months ended
September 30, 1995 from $215,609 for the six months ended September 30, 1994.
This increase was associated with the Company's additional borrowings on its
reducing revolving credit facility, the placement of a private debt financing
with NAGIT (USA), a principal shareholder of the Company, and an increase in
the prime interest rate.
Operating loss for the six months ended September 30, 1995 increased
$308,816 compared to the six months ended September 30, 1994 due primarily to
the decrease in drilling revenues. The Company's net loss was $516,791 for the
six months ended September 30, 1995 compared to a net loss of $224,559 for the
six months ended September 30, 1994.
COMPARISON OF THREE MONTHS ENDED SEPTEMBER 30, 1995 TO
THREE MONTHS ENDED SEPTEMBER 30, 1994.
REVENUES
Oil and gas production revenues for the three months ended September
30, 1995 decreased $90,357 (14%) to $576,508 compared to $666,865 for the prior
corresponding period. As previously mentioned, the decrease in oil and gas
production revenues is due to the decrease in oil production in the Company's
Gulf Coast area where two wells were having production difficulties causing one
well to be reworked during the period. The decrease in oil and gas production
is also due to a decrease in gas production from Ohio wells primarily caused by
the shut-in of wells which have production limitations due to high line
pressure during the summer months.
13
<PAGE> 15
The Company recognized revenue on the drilling of one well for the
three months ended September 30, 1995 compared to six wells for the three
months ended September 30, 1994 resulting in a decrease in drilling revenue of
$617,550 (82%). The decrease in revenue was due to forming the Company's first
Drilling Program of fiscal 1996 on September 30, 1995, forty five days later
than its first Drilling Program of fiscal 1995. Also, the Company has been
delayed in completing three wells which were in progress at June 30, 1995 due
to mechanical reasons for the three months ended September 30, 1995 compared to
completion of all work-in-progress wells at June 30, 1994 for the three months
ended September 30, 1994.
Revenue from well operating, transportation and other increased
$41,323 (11%) due primarily to an increase in well operating revenue for the
three months ended September 30, 1995 compared to the three months ended
September 30, 1994.
Revenue from administrative and agency fees, which are based on a
percentage of the total investor capital raised in all of the Drilling
Programs, increased by 14% for the three months ended September 30, 1995
compared to the three months ended September 30, 1994 primarily due to the
formation of the first Drilling Program of fiscal 1996 coupled with the
increase from ongoing administrative fees accrued from the fiscal 1995 Drilling
Programs.
EXPENSES
Oil and gas production expense increased $66,042 (46%) for the three
months ended September 30, 1995 compared to the three months ended September
30, 1994. This increase was primarily due to costs associated with reworking a
well in the Gulf Coast area and costs associated with the production
enhancement program on the 163 wells the Company acquired in December 1994.
The Company expects to continue to upgrade the wells associated with this
acquisition through the next quarter as well as develop various associated
undeveloped leases on these properties in conjunction with the Drilling
Programs.
Drilling costs for the three months ended September 30, 1995 compared
to the three months ended September 30, 1994 decreased $423,304 (67%) due to
the decreased number of wells completed for the periods presented.
General and administrative expenses decreased $65,583 (9%) for the
three months ended September 30, 1995 compared to the three months ended
September 30, 1994. This decrease resulted from a reduction in professional
fees and office expenses. The Company has retained certain capitalized costs
incurred with the Registration Statement that Management believes will directly
benefit its future financing plans.
Depreciation, depletion, amortization and other decreased $51,072
(10%) for the three months ended September 30, 1995 compared to the three
months ended September 30, 1994. This decrease was a result of the decrease in
gas production mentioned above for the three months ended September 30, 1995
compared to the three months ended September 30, 1994.
Interest expense increased to $202,765 for the three months ended
September 30, 1995 from $122,532 for the three months ended September 30, 1994.
This increase was associated with increased borrowings under the Credit
Facility, a placement of debt financing from NAGIT(USA), a principal
stockholder of the Company, and an increase in the prime interest rate.
Outstanding borrowings under the Company's Credit Facility and with NAGIT (USA)
at September 30, 1995 were $8,145,000 compared to $5,395,002 at September 30,
1994.
INFLATION AND CHANGES IN PRICES
While the costs of operations have been and will continue to be
affected by inflation, oil and gas prices have fluctuated during recent years
and generally have not followed the same pattern as inflation. With today's
global economy, especially in the area of oil and natural gas, management
believes that other forces of the economy and world events, such as OPEC, the
weather, economic factors, and the effects of supply of natural gas in the
14
<PAGE> 16
United States and regionally have a more immediate effect on current pricing
than inflation. The Company received an average price of $ 16.99 and $15.92
per barrel in the six months ended September 30, 1995 and 1994, respectively,
and $2.07 and $2.30 per Mcf for natural gas in the six months ended September
30, 1995 and 1994, respectively. The general market for natural gas in the
Appalachian Basin has remained weak for a longer period than the Company
previously anticipated. The reasons for continued weak natural gas prices can
be attributed to supply and demand fluctuations caused by the weather sensitive
nature of the industry, increased competition from Canadian gas, effects of gas
storage and possibly Federal Energy Regulatory Commission ("FERC") Order 636.
The FERC Order may have contributed to the lower spot market prices by
mandating an unbundling of pipeline service and allowing open access to a
variety of geographical markets. Management cannot predict what long-term
effects FERC Order 636 will have on either spot market prices or longer term
gas contracts.
Currently, the Company sells natural gas under both fixed price
contracts and on the spot market. The spot market price the Company receives
for gas production is related to several variables including the weather and
the effects of gas storage.
The Company continues to construct new pipeline systems in the
Appalachian Basin and to contract with other pipeline systems in the region to
transport natural gas production from wells the Company operates.
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital was approximately negative $280,000 at
September 30, 1995 compared to approximately negative $482,000 at March 31,
1995. The increase of $202,000 in working capital from March 31, 1995 reflects
additional borrowings during the six months ended September 30, 1995. An
amendment to the Credit Facility increased the Company's borrowing base from
$6,450,000 at January 13, 1995 to $8,500,000 at August 8, 1995. As of
September 30, 1995, the Company had $6,810,000 outstanding under its Credit
Facility. North Coast's current ratio was .93 to 1.0 at September 30, 1995 and
.90 to 1.0 at March 31, 1995.
The following table summarizes the Company's financial position at
March 31, 1995 and September 30, 1995:
<TABLE>
<CAPTION>
March 31, 1995 September 30, 1995
-------------- ------------------
Amount % Amount %
------ --- ------ ---
(Dollar in Thousands)
<S> <C> <C> <C> <C>
Working capital $( 482) ( 3%) $( 280) ( 2%)
Property and equipment (net) 16,387 100 16,980 99
Other 445 3 422 3
---------- --------- ---------- --------
Total $ 16,350 100% $ 17,122 100%
========== ========= ========== ========
Long-term debt $ 6,197 38% $ 8,092 47%
Deferred income taxes 930 6 649 4
Stockholders' equity 9,223 56 8,381 49
---------- --------- ---------- --------
Total $ 16,350 100% $ 17,122 100%
========== ========= ========== ========
</TABLE>
15
<PAGE> 17
The following table summarizes the Company's Statements of Cash Flows for the
six months ended September 30, 1994 and 1995:
<TABLE>
<CAPTION>
Six Months Ended September 30,
------------------------------
1994 1995
---- ----
Amount % Amount %
------ - ------ -
(Dollar in Thousands)
<S> <C> <C> <C> <C>
Net cash provided (used) by operating $ 1,767 36% $ (1,444) (51%)
activities
Net cash used by investing activities (1,483) (30) (1,217) (43)
Net cash provided by financing activities 3,108 64 1,099 39
--------- -------- --------- -------
Increase (decrease) in cash and equivalents $ 3,392 70% $ (1,562) (55%)
========= ======== ========= =======
</TABLE>
Note: (1) All items in the previous table are calculated as a
percentage of total cash sources. Total cash sources include the
following items if positive: cash flow from operations before working
capital changes, changes in working capital, net cash provided by
investing activities and net cash provided by financing activities, plus
any decrease in cash and cash equivalents.
As the above table indicates, the Company's cash flow provided by
operating activities decreased approximately $3,211,000 for the six months
ended September 30, 1995 compared to the period ended September 30, 1994. This
decrease reflects the reduced number of wells recognized in drilling revenues
and the payment of drilling and completion costs associated primarily with the
Drilling Programs.
Net cash used by investing activities decreased to approximately
$1,217,000 (43% of cash sources) for the six months ended September 30, 1995
from approximately $1,483,000 (30% of cash sources) for the six months ended
September 30, 1994. This decrease is primarily due to the timing of the
Company's cash expenditures related to its obligation to fund the tangible
equipment for the Drilling Programs.
Net cash provided by financing activities decreased approximately
$2,000,000 for the six months ended September 30, 1995 compared to the prior
period. This decrease reflects the sale of stock for the six months ended
September 30, 1994 without a corresponding sale of stock during the current
period.
On September 20, 1993 the Company entered into an agreement with its
lender to provide a reducing revolving line of credit of up to $10,000,000 (the
"Credit Facility"). At September 30, 1995 the Company's borrowing base under
its Credit Facility was $8,270,000 based upon the Company's current financial
position and level of oil and natural gas and pipeline-based reserves, with
available borrowings reduced by $100,000 at the first of each month. Available
borrowings also are reduced based upon the amount of outstanding letters of
credit used to support certain bonding requirements ($130,000 as of September
30, 1995). The Credit Facility provides that availability is subject to
adjustment based upon the Company's semi-annual reserve study and is subject to
certain covenants. At September 30, 1995 the Company was in violation of
its debt coverage ratio loan covenant, this violation was waived by the lender.
Amounts borrowed under the Credit Facility bear interest at the lending bank's
prime rate plus 1 1/2% (10 1/4% at September 30, 1995). The Company's mortgage
note associated with its Youngstown field office bears interest at the rate of
8% and requires the Company to make monthly payments of approximately $1,019
through July 1998. Thereafter, the balance of the mortgage note will be
amortized over a five-year period at an interest rate to be renegotiated.
The amounts borrowed under the Company's Credit Facility are secured
by its receivables, inventory, equipment and a first mortgage on certain of its
interests in oil and gas wells and reserves. The mortgage note is secured by
certain land and a building.
In addition to bank financing, the Company secured $335,000 in
financing from NAGIT, a principal stockholder of the Company, relating to the
purchase of certain producing wells, gas gathering lines and drilling
locations. The amounts outstanding under the terms of the Company's financing
arrangements with NAGIT are
16
<PAGE> 18
subordinated to the prior payment and amounts outstanding under the Company's
Credit Facility, and bear an interest rate at the prime rate designated by the
Chemical Bank, N.A., plus 1% (9 3/4% at September 30, 1995). This agreement
grants NAGIT a 3.125% overriding royalty interest in the acquired properties.
Repayment of the loan is in cash based upon a percentage of the net monthly
revenues from the acquired properties.
Also, effective June 13, 1995, the Company entered into a Loan
Agreement with NAGIT with respect to a loan of $1,000,000. The unsecured loan
is due December 29, 1995 and may be repaid in cash plus accrued interest (with
approval of the Company's senior lender) prior to December 29, 1995 or may be
converted, after such date, into shares of Common Stock at the rate of $1.00
per share. The loan is subordinate to the Company's senior lender and bears
interest at the rate of 8% per annum. In connection with entering into the
Loan Agreement, the Company issued a warrant to purchase 200,000 shares of
Common Stock at $1.20 per share and a warrant to purchase 300,000 shares of
Common Stock at $1.00 per share. The warrants may be redeemed by the Company
for $.10 per share at its option upon 30 days written notice.
The Company anticipates that the demands on its capital resources may
increase further during fiscal 1996. This potential increase is anticipated to
result from additional drilling and completion obligations of the Company
relating to its sponsorship of drilling programs, further development of the
Company's drilling prospects, the possibility of future joint ventures or other
arrangements intended to assist in increasing the Company's reserve base and
production revenues and the dividend obligations associated with the Company's
Preferred Stock.
The Company believes that due to the amount of funds committed to
current and future projects, including those projects described above, the
uncertainties associated with the amount of funds raised from investors in the
Drilling Programs, and uncertainties associated with revenues from production,
it may be necessary for the Company to investigate additional sources of
capital or financing for its future long-term projects. In the event that
additional long-term financing is not obtained, the Company believes that it
would be required to change its growth oriented business plan in order to
conserve cash. In order to accomplish this objective, the Company believes
that it would be necessary to take various actions, including reducing the
amount of outside capital raised in investor financed Drilling Programs and the
level of its participation in such Programs. The Company believes that cost
cutting measures of this type would have a material adverse effect on its
results of operations and financial condition.
Management of the Company believes that the proceeds of the loan from
NAGIT, together with internally generated funds and available borrowings under
its Credit Facility will be sufficient to fund the Company's anticipated
capital expenditures as well as its working capital needs through the end of
the current fiscal year. Also the Company has decreased its ownership
percentage in the Drilling Programs while maintaining its turnkey drilling
contract price and has decreased the average depth of the wells for which the
Company contracts in order to decrease its drilling completion costs and
increase drilling revenue. Management expects to continue to review additional
financing options, including additional borrowings and sales of stock, in order
to meet the needs of the Company's growth oriented business plan.
17
<PAGE> 19
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
PART II
OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Not applicable
Item 2. CHANGES IN SECURITIES
Not applicable
Item 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
Item 5. OTHER INFORMATION
Not applicable
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
a). Exhibits
11.1 Computation of Earnings per Common Share.
b). No reports on Form 8-K have been filed during the
quarter for which this report was filed.
18
<PAGE> 20
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NORTH COAST ENERGY, INC.
November 13, 1995 /s/ Charles M. Lombardy, Jr.
---------------------------------------
Charles M. Lombardy, Jr.
Chief Executive Officer and Director
November 13, 1995 /s/ Tim Wagers
---------------------------------------
Tim Wagers
Principal Accounting and Financial Officer
<PAGE> 21
<TABLE>
Exhibit 11.1
Computation of Primary and Fully Diluted Earnings Per Common Share
<CAPTION>
EARNINGS
Three Months Ended Six Months Ended
9/30/94 9/30/95 9/30/94 9/30/95
------- ------- ------- -------
<S> <C> <C> <C> <C>
Net Loss $ (164,442) $ (343,100) $ (224,559) $ (516,791)
Series A Preferred Stock Dividends 0 0 ( 95,115) ( 92,838)
Series B Preferred Stock Dividends (116,167) (116,167) (233,208) (232,333)
---------- ---------- ---------- ----------
Pro Forma Loss Applicable to Common Stock $ (280,609) $ (459,267) $ (552,882) $ (841,962)
------------------------------------------------------------------------------------------------------
SHARES
Weighted Average Common Shares for the
period ended 6,432,009 8,032,509 6,398,233 8,031,649
Additional Shares Assuming Conversion of:
Employee Options Exercised 0 0 0 0
---------- ---------- ---------- ----------
Pro Forma Shares for Primary Earnings
Per Common Share 6,432,009 8,032,509 6,398,233 8,031,649
----------- ----------- ----------- -----------
Additional Shares Assuming Conversion of:
Preferred Stock 0 0 0 0
---------- ---------- ---------- ----------
Pro Forma Shares for Fully Diluted Earnings
Per Common Share 6,432,009 8,032,509 6,398,233 8,031,649
=========== =========== =========== ===========
------------------------------------------------------------------------------------------------------
Primary Earnings Per Common Share $( .04) $( .06) $( .09) $( .10)
Fully Diluted Earnings Per Share *$( .04) $( .06) $( .09) $( .10)
------------------------------------------------------------------------------------------------------
* Common Stock Equivalents Have an Anti-Dilutive Effect on Earnings Per Share
and are Excluded From This Exhibit.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000839950
<NAME> NORTH COAST ENERGY
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> MAR-31-1996
<PERIOD-START> APR-01-1995
<PERIOD-END> SEP-30-1995
<CASH> 804,779
<SECURITIES> 0
<RECEIVABLES> 2,928,113
<ALLOWANCES> 0
<INVENTORY> 73,843
<CURRENT-ASSETS> 3,984,537
<PP&E> 26,727,847
<DEPRECIATION> 9,747,511
<TOTAL-ASSETS> 21,386,960
<CURRENT-LIABILITIES> 4,264,353
<BONDS> 0
<COMMON> 80,329
0
7,731
<OTHER-SE> 12,083,007
<TOTAL-LIABILITY-AND-EQUITY> 21,386,960
<SALES> 2,923,822
<TOTAL-REVENUES> 2,923,822
<CGS> 3,463,311
<TOTAL-COSTS> 3,463,311
<OTHER-EXPENSES> (53,562)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 372,864
<INCOME-PRETAX> (858,791)
<INCOME-TAX> (342,000)
<INCOME-CONTINUING> (516,791)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (516,791)
<EPS-PRIMARY> (.10)
<EPS-DILUTED> (.10)
</TABLE>
