<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 December 31, 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 February 12, 1996
- ---------------------------- --------------------------------
Common Stock, $.01 par value 8,037,848
<PAGE> 2
NORTH COAST ENERGY, INC.
Page No.
PART I - FINANCIAL INFORMATION --------
Consolidated Balance Sheets -
March 31, 1995 (Audited) and December 31, 1995 (Unaudited) 2
Unaudited Consolidated Statements of Operations -
For the Three and Nine Months Ended December 31, 1994 and 1995 4
Unaudited Consolidated Statements of Cash Flows -
For the Nine Months Ended December 31, 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
<PAGE> 3
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 1995 and December 31, 1995
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1995 1995
<S> <C> <C>
ASSETS
------
CURRENT ASSETS
Cash and equivalents $ 2,366,660 $ 2,726,501
Accounts receivable:
Trade 1,592,321 1,543,056
Affiliates 59,243 87,782
Refundable income taxes - 61,000
Inventory 218,628 115,721
Deferred income taxes 59,000 61,000
Other 7,682 58,622
---------------- --------------
Total current assets 4,303,534 4,653,682
---------------- --------------
PROPERTY AND EQUIPMENT, at cost
Land 122,699 122,699
Oil and gas properties (successful efforts) 21,051,552 22,773,700
Pipelines 3,187,714 3,569,084
Vehicles 384,241 427,920
Furniture and fixtures 362,288 430,850
Building and improvements 145,539 145,539
---------------- --------------
25,254,033 27,469,792
---------------- --------------
Less accumulated depreciation, depletion, amortization and
write-down (8,867,435) (10,226,350)
---------------- --------------
16,386,598 17,243,442
OTHER ASSETS 445,534 350,034
---------------- --------------
$ 21,135,666 $ 22,247,158
================ ==============
</TABLE>
The accompanying notes are in integral part of these Balance Sheets
2
<PAGE> 4
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 1995 and December 31, 1995
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1995 1995
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
<S> <C> <C>
CURRENT LIABILITIES
Current portion of long-term debt $ 432,100 $ 279,200
Accounts payable 3,644,368 2,346,691
Accrued expenses 423,981 239,759
Billings in excess of costs on uncompleted contracts 284,880 2,635,174
---------------- ----------------
Total current liabilities 4,785,329 5,500,824
---------------- ----------------
LONG-TERM DEBT 6,197,450 8,165,238
DEFERRED INCOME TAXES 930,000 552,000
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
307,870 issued and outstanding (aggregate liquidation value of
$3,094,600 and $3,078,700, respectively) 3,095 3,079
Series B, Cumulative Convertible Preferred stock, par value $.01
per share; 625,000 shares authorized; 464,665 issued and
outstanding (aggregate liquidation value of $4,646,650) 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 8,034,007 issued and outstanding 80,304 80,340
Additional paid-in capital 12,083,024 12,083,004
Retained deficit
(2,948,183) (4,141,974)
---------------- ----------------
Total stockholders' equity 9,222,887 8,029,096
---------------- ----------------
$ 21,135,666 $ 22,247,158
================= ================
</TABLE>
The accompanying notes are in integral part of these Balance Sheets
3
<PAGE> 5
CONSOLIDATED STATEMENTS OF OPERATIONS
For The Periods Ended December 31, 1994 and 1995
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
1994 1995 1994 1995
<S> <C> <C> <C> <C>
REVENUE:
Oil and gas production $ 653,526 $ 622,504 $ 2,049,128 $ 1,943,384
Drilling revenues 2,801,350 1,729,840 4,555,550 2,032,840
Well operating, transportation and other 720,230 306,769 1,653,231 1,175,188
Administrative and agency fees 260,011 275,900 620,270 707,423
----------- ----------- ----------- -----------
4,435,117 2,935,013 8,878,179 5,858,835
COSTS AND EXPENSES:
Oil and gas production expenses 143,639 144,900 411,054 556,439
Drilling costs 2,408,445 1,253,668 3,934,661 1,611,114
Oil and gas operations 470,400 199,549 1,023,950 602,984
General and administrative expenses 714,302 738,214 2,026,116 2,065,645
Depreciation, depletion, amortization, and 405,168 609,149 1,274,984 1,572,609
other
Abandonment of oil and gas properties (628) 66,392 144,295 66,392
----------- ----------- ----------- -----------
4,141,326 3,011,872 8,815,060 6,475,183
----------- ----------- ----------- -----------
INCOME (LOSS) FROM OPERATIONS 293,791 (76,859) 63,119 (616,348)
----------- ----------- ----------- -----------
OTHER INCOME
Interest 37,766 13,987 60,973 50,948
Other - 99 - 7,757
(Loss) gain on sale of property and equipment (2,530) 10,027 986 18,970
----------- ----------- ----------- -----------
35,236 24,113 61,959 77,675
----------- ----------- ----------- -----------
OTHER EXPENSE
Interest 157,556 203,556 373,165 576,420
----------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES 171,471 (256,302) (248,087) (1,115,093)
PROVISION (CREDIT) FOR TAXES ON INCOME
Current 89,000 - (57,000) (61,000)
Deferred (55,000) (113,000) (104,000) (394,000)
----------- ----------- ----------- -----------
34,000 (113,000) (161,000) (455,000)
----------- ----------- ----------- -----------
NET INCOME (LOSS) $ 137,471 $ (143,302) $ (87,087) $ (660,093)
========== ============ =========== ===========
NET LOSS PER SHARE (primary and
fully diluted) $ (.01) $ (.04) $ (.09) $ (.15)
========== ============ =========== ===========
</TABLE>
The accompanying notes are an integral part of these Financial Statements
4
<PAGE> 6
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended December 31, 1994 and 1995
(Unaudited)
<TABLE>
<CAPTION>
December 31, December 31,
1994 1995
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (87,087) $ (660,093)
Adjustments to reconcile net loss to cash provided by
operating activities-
Depreciation, depletion, amortization and other 1,274,984 1,572,609
Abandonment of oil and gas properties 144,295 66,392
Gain on sale of property and equipment (986) (18,970)
Deferred income taxes (104,000) (394,000)
Change in:
Accounts receivable (361,242) (40,274)
Other current assets (177,820) 49,967
Other assets (111,502) 57,492
Accounts payable 870,043 (1,157,701)
Current income taxes payable (95,000) -
Accrued expenses 12,807 (184,222)
Billings in excess of costs on uncompleted contracts 2,355,029 2,350,294
------------- -----------
Total adjustments 3,806,608 2,301,587
Net cash provided by operating activities 3,719,521 1,641,494
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment (3,870,418) (2,155,901)
Proceeds on sale of property and equipment 4,000 12,253
------------- -----------
Net cash used for investing activities (3,866,418) (2,143,648)
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 1,650,000
Borrowings under note payable to stockholder 1,000,000
Other financing for the acquisition of oil and gas properties 660,000 -
Repayments of borrowings under revolving credit facility (435,771) (890,003)
Payments on long-term debt (67,734) (80,529)
Cash paid for deferred financing cost (10,632) (47,353)
Distributions and dividends (537,945) (533,698)
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 3,261,366 861,995
INCREASE IN CASH AND EQUIVALENTS $ 3,114,469 $ 359,841
</TABLE>
The accompanying notes are an integral part of these Financial Statements
5
<PAGE> 7
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
For The Nine Months Ended December 31, 1994 and 1995
(Unaudited)
<TABLE>
<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 $ 4,410,111 $ 2,726,501
=============== ================
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest $ 345,054 $ 539,329
Income taxes 95,000 71,135
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING ACTIVITIES:
Long-term debt incurred for the purchase of property and equipment $ 60,967 $ 91,365
Accounts payable incurred for the purchase of property and equipment 305,359 140,501
Increase in accounts receivable due to the sale of property and
equipment 8,034 -
Accounts payable from interest incurred on long term debt - (44,055)
</TABLE>
The accompanying notes are an integral part of these Financial Statements
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 27.0%
North Coast Energy/Capital 1988-1 Appalachian
Drilling Program Limited Partnership 25.5%
North Coast Energy/Capital 1988-2 Appalachian
Drilling Program Limited Partnership 26.0%
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 25.7%
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%
North Coast Energy 1991-3 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 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%
North Coast Energy 1995-2 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 December 31, 1995
-------------- -----------------
<S> <C>
Revolving credit notes
payable - bank $ 6,050,003 $ 6,810,000
Other financing 335,000 1,379,054
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 68,972
Various installment notes payable, in aggregate monthly
installments (including interest of $8,585 at March 31,
1995 and $11,027 at December 31, 1995). 170,757 186,412
------- ----------
6,629,550 8,444,438
Less current portion 432,100 279,200
---------- ----------
$ 6,197,450 $ 8,165,238
========== ==========
</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 ($140,000 at
December 31, 1995). The borrowing base is reduced monthly by an
amount determined by the lender at the semi-annual borrowing base
determination. 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. At
December 31, 1995, the borrowing base was $7,960,000, with required
monthly reductions of $100,000.
Amounts outstanding under the reducing revolving line of credit, which
were $6,810,000 at December 31, 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 December 31, 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
plus accrued interest may be converted into shares of Common Stock at
the rate of $1.00 per share or paid in cash at the election of the
Company (with approval of the Company's senior lender). 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, December 31,
1995 1995
---- ----
<S> <C> <C>
Billings on uncompleted contracts $ 687,850 $ 4,991,172
Costs incurred on uncompleted contracts 402,970 2,355,998
----------- ------------
$ 284,880 $ 2,635,174
============ ============
</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 $140,000 in lieu of
coverage provided by insurance or road bond deposits against damage.
At December 31, 1995, the Company has committed to fund certain costs
of the North Coast Energy Appalachian Drilling Programs estimated to
be approximately $2,006,000 for tangible well equipment and
pipeline construction. This commitment is expected to be realized by
August 1996.
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 nine 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 nine months ended December 31, 1994 and 1995.
All items in the table are calculated as a percentage of total revenues.
<TABLE>
<CAPTION>
Three Months Nine Months
Ended Ended
December 31, December 31,
------------ ------------
1994 1995 1994 1995
-------------- ---------------
Revenues:
- ---------
<S> <C> <C> <C> <C>
Oil and gas production 14% 21% 23% 33%
Drilling revenues 63 59 51 34
Well operating, transportation and other 16 10 18 20
Administrative and agency fees 6 9 7 12
Other 1 1 1 1
--- --- --- ---
Total Revenues 100% 100% 100% 100%
--- --- --- ---
</TABLE>
11
<PAGE> 13
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Expenses:
Oil and gas production expenses 3% 5% 5% 9%
Drilling costs 54 42 44 27
Oil and gas operations 11 7 11 10
General and administrative expenses 16 25 23 35
Depreciation, depletion, amortization and other 9 21 14 27
Abandonment of oil and gas properties 0 2 2 1
Provision (credit) for taxes on income 1 ( 4) ( 2) ( 8)
Other 3 7 4 10
--- ---- ----- ----
Total Expenses 97% 105% 101% 111%
-- --- --- ---
Net (Income) Loss 3% ( 5%) ( 1%) ( 11%)
==== ===== ===== =====
</TABLE>
The following discussion and analysis reviews the results of
operations and the financial condition for the Company for the three and nine
months ended December 31, 1995 and 1994. The review should be read in
conjunction with the financial information presented elsewhere herein.
COMPARISON OF NINE MONTHS ENDED DECEMBER 31, 1995 TO NINE MONTHS ENDED
DECEMBER 31, 1994.
REVENUES
Oil and gas production revenues decreased $105,744 (5%) to $1,943,384
for the nine months ended December 31, 1995 compared to $2,049,128 for the prior
corresponding period. Revenues were effected by lower oil and gas production
from wells in the Gulf Coast area with two wells being shut-in at various
intervals for reworking, coupled with lower gas prices received by the Company
primarily in the Appalachian Basin. The average gas price the Company received
decreased approximately 8% to $2.06 per Mcf for the nine months ended December
31, 1995 compared to $2.24 per Mcf for the nine months ended December 31, 1994.
Drilling revenues for the period decreased by $2,522,710 (55%) for the
nine months ended December 31, 1995 compared to the nine months ended December
31, 1994 due to the decrease in the number of wells recognized in revenue.
Several factors have affected drilling revenues including the timing of the
formation of the Company's first Drilling Program and the commencement of
drilling activities, the type of wells drilled, the amount of funds raised from
Drilling Programs and the timing of the completion of the wells contracted to
drill. Drilling revenues were recognized on 17 wells for the nine months ended
December 31, 1995 compared to 36 wells for the nine months ended December 31,
1994. At December 31, 1995, the Company had 41 wells in progress and not yet
recognized in drilling revenues as compared to 45 at December 31, 1994. The
Company's shallow wells range in depth from 1,800 feet to 2,200 feet for which
the Company generally charges a lower turnkey drilling contract price compared
to deeper gas wells ranging from 3,300 feet to 6,300 feet. The Company formed
two Drilling Programs raising investor funds of $6,460,000 for the nine months
ended December 31, 1995 compared to three Drilling Programs with investor funds
of $8,406,000 for the nine months ended December 31, 1994. The first drilling
program of fiscal 1996 was formed forty-five days later than the first fiscal
1995 Drilling Program thereby delaying the number of wells completed and the
recognition of revenue for the current period.
For the nine months ended December 31, 1995, well operating,
transportation and other revenues decreased $478,043 (29%) compared to the
nine months ended December 31, 1994 primarily due to a $471,000 decline in third
party gas sales. The Company reduced the number of low margin third party gas
transactions in favor of focusing its gas marketing department on its
proprietary gas sales during the recent period of generally lower natural gas
prices.
12
<PAGE> 14
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 $87,153 (14%) for the nine months ended December 31,
1995 compared to the nine months ended December 31, 1994 due to the formation
of the Drilling Programs 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 $145,385 (35%) for the
nine months ended December 31, 1995 compared to the nine months ended December
31, 1994. This increase was primarily due to costs associated with reworking
two wells in the Gulf Coast area and costs associated with the production
enhancement program on the 163 wells the Company acquired in December 1994.
Drilling costs for the nine months ended December 31, 1995
compared to the nine months ended December 31, 1994 decreased $2,323,547 (59%)
primarily due to the decreased number of wells completed between comparable
periods. The profit margin on drilling revenue increased to 21% for the nine
months ended December 31, 1995 compared to 14% for the nine months ended
December 31, 1994. The increase in the drilling profit margin between
comparable periods is due to lower drilling costs associated with the average
depth of the wells currently recognized in revenues and improved cost controls.
The wells recognized in revenue averaged 4,700 feet in depth for the nine
months ended December 31, 1995 compared to an average of 6,000 feet in depth
for the nine months ended December 31, 1994. The Company anticipates that the
average depth of the wells in its fiscal 1996 Drilling Programs will be less
than the wells drilled in the Company's fiscal 1995 Drilling Programs which is
expected to reduce the drilling costs on a per well basis. The Company also
reduced its interest in the fiscal 1996 Drilling programs to 20% compared to
25% in the fiscal 1995 Drilling Programs increasing the per well drilling
revenue the Company receives thereby increasing the Company's profit margin.
Oil and gas operations expense decreased $420,966 (41%) for the
nine months ended December 31, 1995 compared to the nine months ended December
31, 1994. This decrease was primarily due to the decrease in unaffiliated
third party gas purchases related to third party gas sales as discussed
previously.
Depreciation, depletion, amortization and other increased $297,625
(23%) for the nine months ended December 31, 1995 compared to the nine months
ended December 31, 1994. This increase was due to increased investment in
pipelines and equipment during recent periods and amortization of costs
associated with the reducing revolving line of credit. The increase was also
due to an increase in depletion associated with the Company's investment in
its prior Drilling Programs. The increase in depletion on these Drilling
Programs reflects the revision of reserve estimates anticipated through the
Company's fiscal year end for the wells drilled in these programs. Also, the
Company continues to capitalize certain costs associated with its Drilling
Programs resulting in an increased depletable basis of its investment
Abandonment of oil and gas properties decreased $77,903 (54%) for
the nine months ended December 31, 1995 compared to the nine months ended
December 31, 1994. The Company abandoned a deep zone in two wells associated
with its drilling on acreage acquired in the December 1994 purchase of 163
wells in Western Pennsylvania. The Company incurred the cost of abandoning the
deeper formation and completed both of the wells in a shallower formation.
Interest expense increased to $576,420 for the nine months ended
December 31, 1995 from $373,165 for the nine months ended December 31, 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, a principal shareholder of the Company, and an increase in the
prime interest rate.
Net loss for the nine months ended December 31, 1995 increased
$573,006 compared to the nine months ended December 31, 1994 due primarily to
the increase in depreciation, depletion, amortization and other, coupled with
the lower net drilling income. The Company's net loss was $660,093 for the nine
months ended December 31, 1995 compared to a net loss of $87,087 for the nine
months ended December 31, 1994.
13
<PAGE> 15
COMPARISON OF THREE MONTHS ENDED DECEMBER 31, 1995 TO THREE MONTHS ENDED
DECEMBER 31, 1994.
REVENUES
Oil and gas production revenues for the three months ended
December 31, 1995 decreased $31,022 (5%) to $622,504 compared to $653,526 for
the prior corresponding period. The decrease in oil and gas production
revenues is primarily due to the decrease in oil and gas production in the
Company's Gulf Coast wells and the decrease in the gas price received for Ohio
production between the comparable periods.
The Company recognized revenue on the drilling of 13 wells for the
three months ended December 31, 1995 compared to 22 wells for the three months
ended December 31, 1994 resulting in a decrease in drilling revenue of
$1,071,510 (38%). The decrease in revenue is primarily due to the timing of
the formation of the Company's first Drilling Program of fiscal 1996 on
September 29, 1995, forty five days later than its first Drilling Program of
fiscal 1995 thereby delaying the commencement of drilling and completion of
additional wells.
Revenue from well operating, transportation and other decreased
$413,461 (57%) due primarily to a reduction in third party gas sales.
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 $15,889 (6%) for the three months ended December 31,
1995 compared to the three months ended December 31, 1994 primarily due to the
formation of the Drilling Programs of fiscal 1996 coupled with the increase
from ongoing administrative fees accrued from the fiscal 1995 Drilling
Programs.
EXPENSES
Drilling costs for the three months ended December 31, 1995
compared to the three months ended December 31, 1994 decreased $1,154,777
(48%) due primarily to the decreased number of wells completed for the periods
presented. The profit margin on drilling activities increased to 28% for the
three months ended December 31, 1995 compared to 14% for the three months ended
December 31, 1994 due to the Company reducing its interest in the fiscal 1996
Drilling Programs to 20% from 25%, the decreased average depth on wells
recognized in revenue, and the implementation of additional cost controls in
this period compared to the prior corresponding period.
Depreciation, depletion, amortization and other increased $203,981
(50%) for the three months ended December 31, 1995 compared to the three months
ended December 31, 1994. This increase was due to increased investment in
pipelines and equipment during recent periods and amortization of costs
associated with the reducing revolving line of credit. The increase was also
due to an increase in depletion associated with the Company's investment in
its prior Drilling Programs. The increase in depletion on these Drilling
Programs reflects the revision of reserve estimates anticipated through the
Company's fiscal year end for the wells drilled in these programs.
Interest expense increased to $203,556 for the three months ended
December 31, 1995 from $157,556 for the three months ended December 31, 1994.
This increase was associated with increased borrowings under the Credit
Facility, a placement of debt financing from NAGIT, 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 at December 31,
1995 were $8,189,054 compared to $5,125,003 at December 31, 1994.
The Company's net loss of $143,302 for the three months ended
December 31, 1995 compared to a net income of $137,471 for the three months
ended December 31, 1994 is due primarily to an increase in depreciation,
depletion, amortization and other and abandonment of oil and gas properties.
14
<PAGE> 16
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
United States and regionally have a more immediate effect on current pricing
than inflation. The Company received an average price of $ 16.73 and $15.75
per barrel in the nine months ended December 31, 1995 and 1994, respectively,
and $2.06 and $2.24 per Mcf for natural gas in the nine months ended December
31, 1995 and 1994, respectively. The general market for natural gas in the
Appalachian Basin remained weak for a longer period than the Company previously
anticipated, however, with the colder Appalachian area weather experienced
within the thirty days after December 31,1995 gas prices have increased
dramatically. The reasons for continued weak natural gas prices and
fluctuations in the gas prices can be attributed to supply and demand
fluctuations caused by the weather sensitive nature of the industry. Other
reasons for the weak gas prices are 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 $847,000
at December 31, 1995 compared to approximately negative $482,000 at March 31,
1995. The decrease of $365,000 in working capital from March 31, 1995 reflects
the Company's use of cash to purchase property and equipment to meet its
obligations to fund its investments to the Drilling Programs. Also, the
Company's current obligations through billing in excess of costs increased
during the nine months ended December 31, 1995 associated with the wells its
has contracted to drill for its Drilling Programs. 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 December 31, 1995, the Company had
$6,810,000 outstanding under its Credit Facility. North Coast's current ratio
was .85 to 1.0 at December 31, 1995 and .90 to 1.0 at March 31, 1995.
The following table summarizes the Company's financial position at
March 31, 1995 and December 31, 1995:
<TABLE>
<CAPTION>
March 31, 1995 December 31, 1995
-------------- -----------------
Amount % Amount %
------ - ------ -
(Dollars in Thousands)
<S> <C> <C> <C> <C>
Working capital $( 482) ( 3%) $( 847) ( 5%)
Property and equipment (net) 16,387 100 17,243 103
Other 445 3 350 2
------ --- ------ ---
Total $ 16,350 100% $ 16,746 100%
======== === ======== ===
Long-term debt $ 6,197 38% $ 8,165 49%
Deferred income taxes 930 6 552 3
Stockholders' equity 9,223 56 8,029 48
--------- --- -------- ---
Total $ 16,350 100% $ 16,746 100%
======== === ======== ===
</TABLE>
15
<PAGE> 17
The following table summarizes the Company's Statements of Cash Flows for the
nine months ended December 31, 1994 and 1995:
<TABLE>
<CAPTION>
Nine Months Ended December 31,
1994 1995
Amount % Amount %
------ - ------ -
(Dollar in Thousands)
<S> <C> <C> <C> <C>
Net cash provided by operating activities $ 3,720 53% $ 1,642 66%
Net cash used for investing activities (3,866) (55) (2,144) (86)
Net cash provided by financing activities 3,261 47 862 34
-------- -------- -------- -------
Increase in cash and equivalents $ 3,115 45% $ 360 14%
======== ======== ======== =======
</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 cashprovided 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 $2,078,000 for the nine months
ended December 31, 1995 compared to the period ended December 31, 1994. This
decrease reflects the reduced number of wells recognized in drilling revenues,
the payment of drilling and completion costs associated with the Drilling
Programs and the Company's production enhancement program on the December 1994
purchase of 163 wells in Western Pennsylvania.
Net cash used for investing activities decreased to approximately
$2,144,000 (86% of cash sources) for the nine months ended December 31, 1995
from approximately $3,866,000 (55% of cash sources) for the nine months ended
December 31, 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
$2,399,000 for the nine months ended December 31, 1995 compared to the prior
period. This decrease reflects the sale of Common Stock for the nine months
ended December 31, 1994 without a corresponding sale of Common 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 December 31, 1995 the Company's borrowing base
under its Credit Facility was $7,960,000 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
($140,000 as of December 31, 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 December 31, 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 December
31, 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.
16
<PAGE> 18
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 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
December 31, 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
plus accrued interest may be converted into shares of common Stock at the rate
of $1.00 per share or paid in cash at the election of the Company (with
approval of the Company's senior lender). 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 continued production
enhancement program related to the December 1994 163 well acquisition, the
possibility of future joint ventures, reserve acquisitions 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 diversified its drilling activities which has resulted
in a decrease in the average depth of the wells for which the Company contracts
which in turn decreases its drilling completion costs and increases drilling
revenue. Although, Management has taken the steps outlined above it expects to
review additional financing options, including additional borrowings and sales
of securities, in order to meet the commitment to its Drilling Programs and the
needs of the Company's growth oriented business plan.
ACCOUNTING STANDARDS
In March 1995, the FASB issued Statement of Financial Accounting
Standards (SFAS) No. 121, "Accounting for the Impairment of Long- Lived Assets
and for Long-Lived Assets to Be Disposed Of". This Standard requires the
review of long-lived assets for impairment. Although the Company in the past
has routinely reviewed its oil and gas assets for impairment on a state by
state basis, the new accounting rules may require a different grouping which
may affect the amount of impairment, if any. SFAS No. 121 is required to be
adopted for financial statements issued with fiscal years beginning after
December 15, 1995 and allows the cumulative effect of the accounting change to
be reported in net income in the year of adoption.
17
<PAGE> 19
The Company is currently reviewing the accounting standard and has
not yet determined the affect, if any, on its consolidated financial position.
18
<PAGE> 20
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.
27.1 Financial Data Schedule*
b). No reports on Form 8-K have been filed during the quarter
for which this report was filed.
- ----------
*Exhibit 27.1 furnished for Securities Exchange Commission purposes only.
19
<PAGE> 21
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.
February 13, 1996 /s/ Charles M. Lombardy, Jr.
--------------------------------------
Charles M. Lombardy, Jr.
Chief Executive Officer and Director
February 13, 1996 /s/ Tim Wagers
--------------------------------------
Tim Wagers
Principal Accounting and Financial Officer
20
<PAGE> 1
Exhibit 11.1
Computation of Primary and Fully Diluted Earnings Per Common Share
<TABLE>
<CAPTION>
EARNINGS
Three Months Ended Nine Months Ended
12/31/94 12/31/95 12/31/94 12/31/95
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Net Income (Loss) $ 137,471 $ (143,302) $ ( 87,087) $ (660,093)
Series A Preferred Stock Dividends (93,456) (92,361) (188,571) (185,199)
Series B Preferred Stock Dividends (116,166) (116,166) (349,374) (348,499)
---------- ---------- ---------- ----------
Pro Forma (Loss) Applicable to Common Stock $ (72,151) $(351,829) $ (625,032) $(1,193,791)
========== ========= ========== ===========
- ------------------------------------------------------------------------------------------------------
SHARES
Weighted Average Common Shares for the
period ended 8,025,378 8,033,747 6,942,587 8,032,351
Additional Shares Assuming Conversion of:
Employee Options Exercised 0 0 0 0
------------ ------------ ------------ ------------
Pro Forma Shares for Primary Earnings
Per Common Share 8,025,378 8,033,747 6,942,587 8,032,351
----------- --------- ----------- -----------
Additional Shares Assuming Conversion of:
Preferred Stock 0 0 0 0
------------ ------------ ------------ ------------
Pro Forma Shares for Fully Diluted Earnings
Per Common Share 8,025,378 8,033,747 6,942,587 8,032,351
=========== =========== =========== ===========
- -------------------------------------------------------------------------------------------------------
Primary Earnings Per Common Share $( .01) $(.04) $(.09) $(.15)
Fully Diluted Earnings Per Share *$( .01) *$(.04) *$(.09) *$(.15)
</TABLE>
* Common Stock Equivalents Have an Anti-Dilutive Effect on
Earnings Per Share and are Excluded From This Exhibit.
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000839950
<NAME> NORTH COAST ENERGY, INC.
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> MAR-31-1996
<PERIOD-START> APR-1-1995
<PERIOD-END> DEC-31-1995
<CASH> 2,726,501
<SECURITIES> 0
<RECEIVABLES> 1,691,838
<ALLOWANCES> 0
<INVENTORY> 115,721
<CURRENT-ASSETS> 4,653,682
<PP&E> 27,469,792
<DEPRECIATION> 10,226,350
<TOTAL-ASSETS> 22,247,158
<CURRENT-LIABILITIES> 5,500,824
<BONDS> 0
<COMMON> 80,340
0
7,726
<OTHER-SE> 12,083,004
<TOTAL-LIABILITY-AND-EQUITY> 22,247,158
<SALES> 5,858,835
<TOTAL-REVENUES> 5,858,835
<CGS> 6,475,183
<TOTAL-COSTS> 6,475,183
<OTHER-EXPENSES> 77,675
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 576,420
<INCOME-PRETAX> (1,115,093)
<INCOME-TAX> (455,000)
<INCOME-CONTINUING> (660,093)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (660,093)
<EPS-PRIMARY> (.09)
<EPS-DILUTED> (.09)
</TABLE>
