Back to GetFilings.com
1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 2001
COMMISSION FILE NUMBER 0-18691
NORTH COAST ENERGY, INC.
(Exact name of Registrant as specified in its charter)
DELAWARE 34-1594000
(State of incorporation) (I.R.S. Employer Identification No.)
1993 CASE PARKWAY
TWINSBURG, OHIO 44087-2343
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (330) 425-2330
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $0.01 PAR VALUE
(Title of class)
SERIES A 6% CONVERTIBLE NON-CUMULATIVE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
SERIES B CUMULATIVE CONVERTIBLE PREFERRED STOCK, $0.01 PAR VALUE
(Title of class)
WARRANTS TO PURCHASE COMMON STOCK, $0.01 PAR VALUE
(Title of class)
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 the filing
requirements for the past 90 days.
Yes X . No .
------ ------
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. _______
As of June 15, 2001, the Registrant had outstanding 15,208,031 shares of Common
Stock, 73,096 shares of Series A Preferred Stock, and 232,864 shares of Series B
Preferred Stock. All shares reflect the 1 for 5 reverse Common Stock split
effective June 7, 1999.
The aggregate market value of Common Stock held by non-affiliates of the
Registrant at June 15, 2001, was $10,017,535 which value was computed on the
basis of $4.68 per share of Common Stock, the mean between the closing bid and
ask price as reported for that day on NASDAQ.
DOCUMENTS OR PARTS THEREOF INCORPORATED BY REFERENCE
Part of Form 10-K
-----------------
Part III (Items 10, 11, 12, and 13)
Document Incorporated by Reference
----------------------------------
Portions of the Registrant's definitive Proxy Statement to be used in connection
with its 2001 Annual Meeting of Stockholders. Except as otherwise indicated, the
information contained in this Report is as of March 31, 2001.
2
PART I
ITEM 1. BUSINESS
GENERAL
North Coast Energy, Inc., ("NCE" or the "Company") is a Delaware
corporation and an affiliate of nv NUON. With its subsidiaries and predecessors,
NCE is an independent natural gas and oil company engaged in exploration,
development and production activities in the Appalachian Basin. The Company's
business strategy focuses primarily on its acquisition of proved developed and
undeveloped properties and on the enhancement, drilling and development of such
properties. As used in this Annual Report on Form 10-K, the terms "Company" and
"NCE" mean North Coast Energy, Inc., its subsidiaries and predecessors, unless
the context otherwise requires. The Company currently has three wholly-owned
subsidiaries, NCE Securities, Inc. ("NCE Securities"), North Coast Operating
Company ("NCOC"), and North Coast Energy Eastern, Inc. ("NCE Eastern"), two of
which are considered active (NCE Securities and NCE Eastern).
The Company began operations in 1981. In 1997, NUON International
Projects bv ("NUON") and the Company formed a strategic alliance that has
resulted in NUON acquiring a majority ownership position (86%) in the Company as
of May 2000. Moreover, NUON has provided significant financial and technical
resources that have enabled the Company to acquire additional oil and gas
producing assets, increase its daily production and reserves, improve its
efficiency as an owner and operator and substantially improve its financial
structure and results.
As of March 31, 2001, NCE owned interests in 3,818 wells, operating
3,730 of these wells. In connection with the drilling and development of the
wells it operates, NCE currently owns and operates approximately 1,420 miles of
natural gas gathering systems with access to the commercial and industrial gas
markets of the northeastern United States. At March 31, 2001, the Company had
estimated net proved reserves of approximately 143 Bcf (billion cubic feet) of
natural gas and 1.2 million Bbls (barrels) of oil. The estimated future net cash
flows from these reserves had a present value (discounted at 10 percent) before
income taxes of approximately $183 million at March 31, 2001. Daily net
production as of March 31, 2001 was approximately 21 MMcf (million cubic feet of
natural gas) and 243 Bbls of oil. At that date, the Company held leases on
375,457 gross (287,576 net) acres, including 198,741 gross (147,377 net)
undeveloped acres.
SIGNIFICANT EVENTS
In March 2000, the Company purchased the stock of Peake Energy, Inc. of
Ravenswood, West Virginia for $72.5 million, based upon the effective date of
January 1, 2000. The name was changed to North Coast Energy Eastern, Inc. in May
2001. The actual funds transferred at the time of closing were $69.5 million to
reflect net proceeds from the effective date. The purchase was financed through
borrowings from NUON. NCE Eastern is a large, successful producer and operator
of Appalachian natural gas and oil which provided the Company a foothold for
continued growth in West Virginia and Kentucky. The acquisition of NCE Eastern
added significantly to the Company's production, reserves and financial results.
NCE Eastern's operations and personnel have been fully integrated with those of
the Company.
On May 4, 2000, NUON converted $24 million of debt related to the NCE
Eastern acquisition to 9.6 million shares of common stock of the Company.
2
3
AREA OF OPERATIONS
The Appalachian Basin (the "Basin") is located in close proximity to
major natural gas markets in the northeast United States. This proximity to a
substantial number of large commercial and industrial gas markets, coupled with
the relatively stable nature of the Basin production and the availability of
transportation facilities has resulted in generally higher wellhead prices for
Appalachian natural gas than those prices available in the Gulf Coast and
Mid-continent regions. The Basin is the oldest gas and oil-producing region in
the United States and includes portions of Ohio, Pennsylvania, New York, West
Virginia, Kentucky and Tennessee. Although the Basin has sedimentary formations
indicating the potential for gas and oil reserves to depths of 30,000 feet or
more, most production in the Basin has been from wells drilled to a number of
relatively shallow blanket formations at depths of 1,000 to 7,500 feet. These
formations are generally characterized by long-lived reserves that produce for
more than 20 years. Drilling success rates of the Company and other operators
drilling to these formations historically have exceeded 90%.
Long production life and high drilling success rates to these shallow
formations has resulted in a highly fragmented, extensively drilled, low
technology operating environment in the Basin. As a result, there has been
limited testing or development of productive and potentially productive
formations at deeper depths in the Basin. The Company believes that significant
exploration and development opportunities exist in these deeper, less developed
formations for those operators with the capital, technical expertise and ability
to assemble the large acreage positions needed to justify the use of advanced
exploration and production technologies.
BUSINESS STRATEGY
The Company's business strategy is to increase shareholder value by
increasing production, operating margins and cash flow by making strategic
acquisitions that are either accretive to operating results and/or beneficial to
the Company's future strategic positioning; through the exploration and
development of the Company's existing and acquired acreage base; by improving
profit margins through operational and technological efficiencies; and through
the further expansion of the Company's gas gathering systems. The key elements
of the Company's business strategy are as follows:
- MAKE STRATEGIC ACQUISITIONS ACCRETIVE TO OPERATING AND FINANCIAL
RESULTS. The Company uses a highly disciplined approach to
acquisition analysis that requires each acquisition to be
accretive to the Company's operational and financial performance.
Approval to proceed with an acquisition requires input and
approval from all key areas of the Company. These areas include
field operations, exploration and production, finance, legal, land
management and environmental compliance.
- MAINTAIN A BALANCED DRILLING PROGRAM. The Company intends to focus
its exploration and development activities on a well-balanced
portfolio of development drilling in the shallow blanket
formations of the Basin and development and exploratory drilling
in the deeper more prolific formations in the Basin. This broad
portfolio approach allows the Company to optimize economic returns
and minimize certain of the geological risks associated with oil
and gas development and exploration.
- IMPROVE PROFIT MARGINS. The Company intends to become one of the
most efficient operators in the Basin. To accomplish this goal,
the Company intends to improve its profit margins on the
production from existing and acquired properties through advanced
production techniques, operating efficiencies, mechanical
improvements and the use of enhanced recovery methods.
- EXPAND ITS NATURAL GAS GATHERING SYSTEMS. The Company currently
owns and operates approximately 1,420 miles of gas gathering lines
in Ohio, Pennsylvania, West Virginia and Kentucky. All of these
lines connect or have the ability to connect to various intrastate
and interstate natural gas transmission and distribution systems.
The interconnections with these pipelines gives the Company access
to numerous natural gas markets, including existing and proposed
electric power generating facilities. The Company intends to
continue to expand its gas gathering systems to further improve
the rate of return on its exploration and development operations.
3
4
- RISK MANAGEMENT. The Company manages its exposure to natural gas
price volatility by selling a portion of its future gas production
under fixed price contracts with varying expiration dates, using
financial hedging instruments to realize the price for a portion
of its future gas production, and by monitoring technical and
fundamental information to determine when to use various financial
hedging techniques. NCE believes that over the next decade those
companies that master the ability to manage the volatility of
natural gas prices will be successful - given the anticipated
fundamental shift in the price of this commodity.
ACQUISITIONS
Recent Acquisitions
In March 2000, the Company acquired 100% of the stock of Peake Energy,
Inc. ("Peake") of Ravenswood, West Virginia, providing the Company with a
substantially expanded operating area in the Basin. The Company's objective in
acquiring Peake was to increase production, reserves and its overall critical
mass to allow it to operate in a more effective and cost-efficient manner.
Peake's operations and personnel have been fully integrated into the Company,
and the name was changed to North Coast Energy Eastern, Inc. in May 2001.
Acquisition Strategy
The Company's acquisition strategy focuses on oil and gas properties
and entities that can provide:
- enhanced cash flow,
- additional drilling and development opportunities,
- synergies with the Company's properties,
- enhancement potential of current operations, and/or
- economies of scale and cost efficiencies.
During fiscal 2000 and 2001, the Company completed the acquisition of
working interests in approximately 3,300 wells, adding approximately 78 Bcfe of
proved reserves at an average cost of $.74 per Mcfe. In addition during such
period, the Company acquired various gas gathering systems and numerous
additional drilling locations. The Company has also acquired additional
interests in wells operated for its prior Drilling Programs by offering to
purchase investors' oil and gas interests for cash.
EXPLORATION AND DEVELOPMENT
Exploration and development activities conducted by the Company have
primarily involved the acquisition of proved undeveloped oil and gas properties
and the drilling and development of such properties by the Company or in
conjunction with Drilling Programs and joint ventures.
The Company's strategy focuses on increasing its natural gas and oil
reserves, as well as production, drilling and oilfield service revenues, by
acquiring undeveloped oil and gas properties in the Basin and financing and
conducting the drilling and development of these properties by the Company or in
conjunction with the Drilling Programs.
The Company's historical drilling operations in the Basin have
principally involved drilling to the Clinton/Medina sandstone formation. This
formation is an oil and gas bearing sandstone, which underlies a large portion
of eastern Ohio and western Pennsylvania in varying thicknesses and at depths
ranging generally from 2,800 to 7,500 feet. Substantially all of the wells that
the Company has drilled to this formation have estimated depths ranging between
3,500 and 6,700 feet.
In 1998, the Company began a seismic data program that led to the
inception of exploratory drilling to formations below the Clinton/Medina
Sandstone on a portion of its Ohio leasehold acreage. This exploratory drilling
has focused on the Knox unconformity, a sequence of sandstone and dolomite
formations that includes the Rose Run, Beekmantown and Trempealeau productive
zones, at depths ranging from 2,500 to 8,000 feet. In the Company's area of
interest the Knox formations are found approximately 2,000 feet below the
Clinton formation at depths between 6,000 and 7,000 feet. To date, the Company's
exploration of the Knox formations has resulted in eight commercially productive
wells of the nine exploratory wells drilled to the Knox formations.
4
5
The Company also maintains substantial leasehold acreage in portions of
Ohio, Pennsylvania and West Virginia with the potential for production from
other deeper, less developed formations.
DRILLING ACTIVITY
NCE continually evaluates undeveloped prospects originated by its staff
or other independent geologists as well as other gas and oil companies. If
review of a prospect indicates that it may be geologically and economically
attractive, the Company will attempt to obtain a lease of the mineral rights on
the acreage.
Typically, the Company will acquire the entire working interest in a
lease by paying a lease bonus and annual rentals subject to a landowner's
royalty and, where the property is acquired through a third party, possibly an
overriding royalty interest. During fiscal year 2001, the Company participated
in the drilling of 51 wells, all of which were commercially productive.
DRILLING PROGRAMS
From the Company's inception in 1981 through March 31, 2001, NCE has
raised approximately $98 million and has sponsored 51 Drilling Programs to
engage in oil and gas drilling and development operations. Each Drilling Program
has been conducted as a separate limited partnership with the Company serving as
managing general partner of each. Currently, NCE serves as the managing general
partner of 21 Drilling Programs.
The Company acts as operator and general contractor for drilling and
production operations, undertaking to drill and complete Drilling Program wells
and to serve as operator for producing wells. At March 31, 2001, the Company
operated 354 wells for the Drilling Programs.
DRILLING SERVICES
NCE derives revenue and net income from the drilling services it
provides to the Drilling Programs. NCE enters into turnkey (fixed price)
contracts with the Drilling Programs to drill Program wells. Pursuant to these
drilling contracts, the Company is responsible for the drilling and completion
of the wells. The Company manages and supervises all necessary drilling and
related service and equipment operations on these wells and contracts a number
of third party services including contract drilling, fracturing, logging and
pipeline construction, which are performed by subcontractors who specialize in
those operations. Since NCE contracts with the Drilling Programs on a turnkey
basis, the Company is subject to the risk that prices incurred in the actual
drilling and completion operations could exceed its contract price.
OIL FIELD SERVICE OPERATIONS
As of March 31, 2001, NCE operated 3,730 wells located in Ohio,
Pennsylvania, West Virginia and Kentucky. As an operator of producing wells, the
Company is responsible for the maintenance and verification of all production
records, contracting for oil and gas sales, distribution of production proceeds
and information, and compliance with various state and federal regulations.
Generally, the Company provides the routine day-to-day production operations for
producing wells. The Company may, however, subcontract certain oil field
operations that require third party services.
The Company receives a monthly operating fee for each producing well it
operates for third parties and is reimbursed for most unaffiliated third party
costs associated with operations and production of the wells. Each working
interest owner in a well pays the Company its share of the operating fee based
upon its aggregate interest in the well.
5
6
GAS-GATHERING ACTIVITIES
In connection with the drilling and completion of the wells that it
operates, NCE has acquired, constructed and owns approximately 1,420 miles of
gas gathering systems in various counties throughout Ohio, Pennsylvania, West
Virginia and Kentucky. These gathering lines carry natural gas from the wellhead
to various gas transmission systems for sale to utilities, the Company's
industrial customers and to natural gas marketers purchasing gas for resale to
others. The Company intends to continue its acquisition and construction of
gathering systems and the establishment of compressor facilities in order to
expand its existing and future potential markets.
For such gas gathering services, the Company collects certain
allowances from public utilities, end users or other natural gas purchasers,
including natural gas marketers. These gathering fees or transportation
allowances averaged approximately $.44 per Mcf of natural gas at March 31, 2001.
MARKETS
The ability of the Company to market oil and gas depends to an extent,
on factors beyond its control. The potential effects of governmental regulation
and market factors including alternative domestic and imported energy sources,
available pipeline capacity, and general market conditions are not entirely
predictable.
Natural Gas. Natural gas is generally sold pursuant to individually
negotiated gas purchase contracts, which vary in length from spot market sales
of a single day to term agreements that may extend several years. The Company's
natural gas customers include utilities, natural gas marketing companies, and a
variety of commercial and industrial end users. Gas purchase contracts define
the terms and conditions unique to each of these sales. The price received for
natural gas sold on the spot market may vary daily reflecting changing market
conditions.
The deliverability and price of natural gas are subject to both
governmental regulation and the forces of supply and demand. During the past
several years, regional natural gas surpluses and shortages have occurred
resulting in wide fluctuations in the prices paid to producers.
The contract duration for each of the Company's gas purchase agreements
varies widely. Additionally, several of the Company's contracts provide for
prices to be set monthly based on published NYMEX (New York Mercantile Exchange)
or Appalachian price indices. The Columbia Gas Transmission Corporation (TCO)
and CNG Southpoint Index prices, which create a basis for spot sale prices in
the Mid-Atlantic and northeastern regions of the United States, ranged from
$3.01 to $10.91 per MMBtu during fiscal 2001. (MMBtu represents one million
British Thermal Units. One MMBtu is approximately equal to one Mcf.) As of March
31, 2001, approximately 18% of the Company's natural gas contracts are
fixed-price contracts with industrial end-users. The prices received from these
contracts range between $3.05 and $6.67 per Mcf. The remainder of the Company's
natural gas fixed-price contracts are with utilities and natural gas marketers.
The prices received from these contracts range between $2.07 and $5.86 per Mcf.
For the fiscal year ended March 31, 2001, the Company received an average price
of $3.40 per Mcf.
During fiscal year 2001, two customers purchased 21% and 14% of the gas
produced by the Company, respectively. During fiscal years 2000 and 1999, two
customers purchased 22% and 19% and 52% and 13%, respectively, of the gas
produced by the Company.
Due to the seasonality of supply and demand, prices paid by purchasers
for natural gas will continue to fluctuate. The Company has pursued a strategy
of varying the length and pricing provisions of its gas purchase contracts in
order to maintain flexibility to react to those fluctuating prices. Due to
current market conditions, the duration of recently renegotiated fixed price
contracts have been extended to from one to three years in length. In order to
reduce the volatility of natural gas prices, the Company has fixed approximately
49% of its fiscal 2002 gas production at an average price of $3.33 through a
combination of fixed price contracts and financial hedges.
6
7
During the past several years, an overabundance of natural gas supplies
and promulgation of state and federal regulations pertaining to the sale,
transportation, and marketing of natural gas resulted in increasing competition
and declining prices. However, recent trends have shown that there may be an
imbalance between supply and demand. This is evidenced by increased natural gas
futures prices on the NYMEX and quoted regional natural gas indices. This upward
trend in prices has been attributed to increased demand in the residential and
commercial sectors in the face of declining domestic production.
Crude Oil. Oil produced from the Company's properties is generally sold
at the prevailing field price to one or more unaffiliated purchasers in the
area. Generally, purchase contracts for the sale of oil are cancelable on 30
days notice. The price paid by these purchasers is generally an established, or
"posted," price that is offered to all producers. The Company received an
average price of $28.28 per barrel for its oil during fiscal 2001; however,
during the last several years prices paid for crude oil have fluctuated
substantially. The price posted for purchase contracts for the sale of
Pennsylvania-grade crude oil at March 31, 2001, was $22.50. Future oil prices
are difficult to predict due to the impact of worldwide economic trends, coupled
with supply and demand variables, and such non-economic factors as the impact of
political considerations on OPEC pricing policies and the possibility of supply
interruptions. Oil production comprised approximately 7% of NCE's total oil and
gas production calculated on a Mcfe basis for fiscal year 2001. Therefore, a
price increase or decrease in oil prices will have a minimal impact on revenues
when compared to the effect of the price of natural gas. To the extent that the
price that the Company receives for its crude oil increases or decreases from
current levels, revenues from oil production will be affected accordingly.
COMPETITION
The gas and oil industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties and
the sale of oil and gas production. There is competition among oil and gas
producers as well as with other industries in supplying energy and fuel to end
users.
The Company's competitors in oil and gas exploration, development and
production include major integrated oil and gas companies as well as numerous
independent oil and gas companies, individual proprietors, natural gas pipelines
and their affiliates. Many of these competitors possess and employ financial and
personnel resources substantially in excess of those of the Company. The ability
of the Company to increase its production and add to its reserves in the future
will depend on the availability of capital, the ability to exploit its current
lease holdings and the ability to identify and acquire suitable producing
properties and prospects for future exploration and development.
REGULATION
Exploration and Production. The exploration, production and sale of
natural gas and oil are subject to various local, state and federal laws and
regulations. Such laws and regulations govern a wide range of matters, including
the drilling and spacing of wells, allowable rates of production, restoration of
surface areas, plugging and abandonment of wells and requirements for the
operation of wells. Such regulations may adversely affect the rate at which the
Company's wells produce gas and oil. In addition, legislation and new
regulations concerning gas and oil exploration and production operations are
constantly being reviewed and proposed. Most of the states in which the Company
owns and operates properties have laws and regulations governing several of the
matters enumerated above. Compliance with the laws and regulations affecting the
gas and oil industry generally increases the Company's cost of doing business
and consequently affects its profitability.
Environmental Matters. The discharge of oil, gas or other pollutants
into the air, soil or water may give rise to liabilities to the government and
third parties and may require the Company to incur costs to remedy the
discharge. Natural gas, oil or other pollutants (including brine) may be
discharged in many ways, including from a well or drilling equipment at a drill
site, leakage from pipelines or other gathering and transportation facilities,
leakage from storage tanks and sudden discharges from damage or explosion at
natural gas facilities or gas and oil wells. Discharged hydrocarbons may migrate
through soil to water supplies or adjoining property, giving rise to additional
liabilities. A variety of federal and state laws and regulations govern the
environmental aspects of natural gas and oil production, transportation and
processing and may, in addition to other laws, impose liability in the event of
discharges (whether or not accidental), failure to notify the proper authorities
of a discharge, and other noncompliance with those laws. Compliance with such
laws and regulations may increase the cost of gas
7
8
and oil exploration, development and production although the Company does not
currently anticipate that compliance will have a material adverse effect on
capital expenditures or earnings of the Company.
The Company does not believe that its environmental risks are
materially different from those of comparable companies in the oil and gas
industry. The Company believes its present activities substantially comply, in
all material respects, with existing environmental laws and regulations.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or material increase in the cost
of production, development or exploration or otherwise adversely affect the
Company's operations and financial condition. Although the Company maintains
liability insurance coverage for certain liabilities from pollution, such
environmental risks generally are not fully insurable; the amount of such
coverage is currently $1 million and is provided on a "claims made" basis.
Marketing and Transportation. The interstate transportation and sale
for resale of natural gas is regulated by the Federal Energy Regulatory
Commission (the "FERC") under the Natural Gas Act of 1938 ("NGA"). The wellhead
price of natural gas is also regulated by FERC under the authority of the
Natural Gas Policy Act of 1978 ("NGPA"). The Natural Gas Wellhead Decontrol Act
of 1989 (the "Decontrol Act"), which was enacted on July 26, 1989, eliminated
all gas price regulation effective January 1, 1993.
In 1992 FERC finalized Order 636, regulations pertaining to the
restructuring of the interstate transportation of natural gas. Pipelines serving
this function have since been required to "unbundle" the various components of
their service offerings, which include gathering, transportation, storage, and
balancing services. In their current capacity, pipeline companies must provide
their customers with only the specific service desired, on a non-discriminatory
basis. Although NCE is not an interstate pipeline, the Company believes the
changes brought about by Order 636 have increased competition in the
marketplace.
Various rules, regulations and orders, as well as statutory provisions
may affect the price of natural gas production and the transportation and
marketing of natural gas.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's gas and oil operations are subject to all operating
hazards and risks normally incident to drilling for and producing gas and oil,
such as encountering unusual formations and pressures, blow-outs, environmental
pollution, and personal injury. The Company will maintain such insurance
coverage as it believes to be appropriate, taking into account the size of the
Company and its proposed operations. The Company currently does not maintain
insurance coverage for physical loss or damage to equipment located on the wells
or for selected properties (such as crude oil stored in tanks). The Company's
insurance policies also have standard exclusions. Losses can occur from an
uninsurable risk or in amounts more than existing insurance coverage. The
occurrence of an event, which is not insured or not fully insured, could have an
adverse impact on the Company's revenues and earnings.
As managing general partner of the Drilling Programs, NCE is subject to
full liability for the obligations of the Drilling Programs although it is
indemnified by each Program to the extent of the Program's assets under certain
circumstances. The partnership interests in the Drilling Programs constitute
securities and the Company is subject to potential liability for failure to
comply with applicable federal and state securities laws and regulations.
EMPLOYEES
At March 31, 2001, the Company had 136 full-time employees, including
105 field employees, 2 petroleum engineers, 3 geologists, 6 accountants, 2 land
men, 1 attorney, and 2 gas marketers. No employees are represented by a union,
and the Company believes that it maintains good relations with its employees.
8
9
ITEM 2. PROPERTIES
Oil and Gas Properties
- ----------------------
In the following tables, "gross" refers to the total acres or wells in
which the Company has a working interest and "net" refers to gross acres or
wells multiplied by the Company's percentage working interests therein. Royalty
interests held by the Company will not be reflected in net wells.
PROVED RESERVES. The following table reflects the estimates of the
Company's proved reserves as of March 31, 2001.
RESERVES
Oil Reserves (MBbls)
Proved Developed 1,119
Proved Undeveloped 88
-------
Total 1,207
=====
Gas Reserves (MMcf)
Proved Developed 124,444
Proved Undeveloped 18,952
-------
Total 143,396
=======
MMcf Equivalent(1)
Proved Developed 131,158
Proved Undeveloped 19,480
-------
Total 150,638
=======
(1) Oil was converted to Mcfe in the standard ratio of one Bbl
equals six Mcf.
PRODUCTION. The following table summarizes the net oil and gas
production (on a rounded basis), average sales prices, and average production
(operating) expenses per equivalent unit of production for the periods
indicated.
PRODUCTION
Production Sales Price Average Operating
Years Ended Cost
March 31 Oil (Bbls) Gas (Mcf) Per Bbl Per Mcf per Mcfe(1)
-------- ---------- --------- ------- ------- -----------
1998 13,900 1,116,000 $16.18 $2.50 $0.70(2)
1999 28,100 2,688,000 $11.39 $2.57 $0.91
2000 31,000 2,947,000 $20.08 $2.58 $1.14
2001 96,200 7,835,000 $28.28 $3.40 $1.08
(1) For calculation of average operating cost per Mcfe, the standard ratio of
6:1 for gas to oil was used.
(2) Includes costs for the rework of ten wells located in Pennsylvania and
relocation of production facilities in Louisiana.
PRODUCTIVE WELLS. The following table sets forth the number of gross
and net productive oil and gas wells of the Company as of March 31, 2001. Wells
are classified as gas or oil according to their predominant product stream.
PRODUCTIVE WELLS
Gross Wells (1) Net Wells
Oil Gas Total Oil Gas Total
--- --- ----- --- --- ----
388 3,430 3,818 367 2,581 2,948
(1) Gross wells include 100 wells in which the Company owns a royalty
interest.
9
10
ACREAGE. The following table sets forth the developed and undeveloped
acreage of the Company, on both a gross and net basis, as of March 31, 2001. The
amount included in proved undeveloped acreage recognizes only the acreage
directly offsetting locations to wells that have indicated commercial production
in the objective formation, and that the Company expects to drill in the near
future.
LEASEHOLD ACREAGE
Total Leasehold Acreage
Gross Acres 375,457
Net Acres 287,576
Developed Acreage
Gross Acres 165,596
Net Acres 131,303
Proved Undeveloped Acreage
Gross Acres 11,120
Net Acres 8,896
Undeveloped Acreage
Gross Acres 198,741
Net Acres 147,377
DRILLING ACTIVITIES
The following table sets forth the results of drilling activities on
the Company's properties. Such information and the results of prior drilling
activities should not be considered as necessarily indicative of future
performance, nor should it be assumed that there is necessarily any correlation
between the number of productive wells drilled and the oil and gas reserves
generated.
All wells were drilled by March 31 of their respective years and are
reflected in the Drilling Activities table. Wells in which the Company owns only
a royalty interest are not reflected in the table below.
DRILLING ACTIVITIES
Fiscal year ended March 31, 2001 2000 1999 1998
- --------------------------- ---- ---- ---- ----
Exploratory Wells (1)
Productive
Gross 5 1 0 0
Net 4.3 1 0 0
Dry
Gross 0 0 0 0
Net 0 0 0 0
Development Wells (2)
Productive (3)
Gross 46 34 37 16
Net 13.2 8.15 20.20 4.50
Dry
Gross 0 0 1
Net 0 0 0 0.22
Total Wells (4)
Productive
Gross 51 35 37 16
Net 17.44 9.15 20.20 4.50
Dry
Gross 0 0 0 1
Net 0 0 0 0.22
(1) Exploratory Wells are those wells drilled outside the confines of
a known productive reservoir area.
10
11
(2) Development Wells are those wells drilled within the confines of a
known productive reservoir.
(3) The number of productive wells for fiscal 2001 includes nine gross
wells and 2.9 net wells as productive wells that are awaiting
pipeline connection or well completion operations at March 31,
2001.
(4) Total Wells is the sum of the Exploratory and Development Wells.
FACILITIES
NCE owns a 12,000 square foot building, its corporate headquarters, in
Twinsburg, Ohio. As part of the NCE Eastern acquisition NCE acquired 11,280
square feet of office and operation facilities near Ravenswood, Jackson County,
West Virginia. The Company also owns or leases operating facilities in
Youngstown and Cambridge, Ohio and Maben and Clarksburg, West Virginia. It also
leases a small operating facility in Shrewsbury, Kentucky.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings to which the Company is
a party or to which any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of the fiscal year ended March 31, 2001,
there were no matters submitted to a vote of security holders through the
solicitation of proxies or otherwise.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Common Stock is traded on the NASDAQ SmallCap Market under the
symbol "NCEB." The following tables sets forth, the high and low bid and ask
prices for the Common Stock for the fiscal periods indicated.
Common Stock
(Amounts rounded to the nearest 32nd and third decimal)
High Low
---- ---
Bid Ask Bid Ask
--- --- --- ---
FISCAL 2000
First Quarter $ 5-5/16 $ 5-15/16 $ 2-7/8 $ 3-3/8
Second Quarter 4-15/16 5 3-5/16 3-11/16
Third Quarter 3-15/16 4-1/8 1-13/16 2
Fourth Quarter 3-5/16 3-7/16 1-15/16 2-5/16
FISCAL 2001
First Quarter $4.375 $5.188 $2.250 $2.438
Second Quarter 4.438 4.500 2.813 3.125
Third Quarter 4.875 5.125 3.000 3.750
Fourth Quarter 4.625 4.750 3.625 3.813
As of June 15, 2001, there were 15,208,031 shares of Common Stock
outstanding, which were held by approximately 1,467 holders of record. On June
7, 1999, a 1 for 5 reverse stock split became effective thereby reducing the
number of shares of outstanding Common Stock from 22,784,070 to 4,556,814. Of
the total 15,208,031 outstanding shares of the Company's Common Stock, 9,600,000
were issued on May 4, 2000, to NUON in compliance with NUON's election to
convert a $24 million Non-Negotiable Subordinated Convertible Promissory Note
from debt to equity. The Note had been entered into between the Company and NUON
on March 17, 2000, and represented a portion of the financing that had been
provided by NUON in conjunction with the purchase of the stock of NCE Eastern.
11
12
Holders of Series A Preferred Stock may be entitled to receive
semi-annual non-cumulative cash dividends at an annual rate of $.60 per share
when and if declared by the Board of Directors. Such dividends are payable on
June 1 and December 1 of each year. The Series A Preferred Stock was convertible
to 2.3 shares of Common Stock prior to the reverse stock split and is
convertible to 0.46 shares of Common Stock after the reverse stock split. The
holders of Series B Preferred Stock are entitled to receive quarterly cumulative
cash dividends at an annual rate of $1.00 per share. The Series B Preferred
Stock is convertible to 6.56 shares of Common Stock prior to the reverse stock
split and is convertible to 1.311 shares of Common Stock after the stock split.
For the fiscal year ended March 31, 2001, the Company paid $232,864 in aggregate
cash dividends on its Series B Preferred Stock.
Whenever dividends on the Series B Preferred Stock have not been paid
for an amount equal to six quarterly dividend payments, the number of directors
of the Company may be increased, and the holders of the Series B will be
entitled to elect such additional directors on the Board of Directors. Such
voting right will terminate when all such distributions accrued and in default
have been paid in full or set apart for payment. The Company has dividends in
arrears on its Series B Preferred Stock of $326,010 at March 31, 2001.
The Company has never paid any cash dividends on its Common Stock and
is currently restricted from paying cash dividends on any of its Common Stock
under the terms of its credit facility. The Company currently intends to retain
future earnings in order to provide funds for use in the operation of its
business.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth-selected financial data for the Company
for each of the five fiscal years in the periods ended March 31, 2001, 2000,
1999, 1998 and 1997.
Years Ended March 31
(In thousands, except per share amounts)
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues $45,535 $15,640 $12,982 $7,625 $8,781
Net Income 6,759 1,312 870 262 292
Net Income (Loss) per share (1) 0.46 0.21 0.16 0.00 (0.75)
Total Assets 135,353 123,618 43,573 22,312 21,229
Long Term Debt (less current portion) 67,167 90,122 21,494 7,171 10,721
Stockholders' equity 53,952 23,392 17,943 12,339 7,309
(1) Net Income (Loss) per share has been restated to reflect stock
dividends and all per share amounts have been restated to give
retroactive effect to the reverse stock split effective June 7, 1999.
The following table sets forth summary unaudited financial information
on a quarterly basis for the past two years.
(In thousands, except per share amounts)
2001
Quarter Ended
-------------
June 30 Sept. 30 Dec. 31 March 31
------- -------- ------- --------
Revenues $8,096 $10,006 $9,304 $18,129
Net Income 406 1,013 1,909 3,431
Net Income per share (1) 0.03 0.06 0.12 0.22
Total Assets 129,460 127,297 136,799 135,353
Long Term Debt (less current portion) 67,493 70,564 70,635 67,167
12
13
(In thousands, except per share amounts)
2000
Quarter Ended
-------------
June 30 Sept. 30 Dec. 31 March 31
------- -------- ------- --------
Revenues $2,258 $2,394 $3,145 $7,844
Net Income (Loss) (561) (245) 589 1,529
Net Income (Loss) per share (1) (0.14) (0.07) 0.10 0.25
Total Assets 44,550 51,140 51,061 123,618
Long Term Debt (less current portion) 23,543 21,516 20,390 90,122
(1) Net Income (Loss) per share has been restated to reflect stock
dividends and all per share amounts have been restated to give
retroactive effect to the reverse stock split effective June 7, 1999.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
NCE is engaged in the acquisition and enhancement of developed natural
gas and oil producing properties and the exploration, development and production
of undeveloped natural gas and oil properties, owned by the Company or in
conjunction with joint ventures or partnerships sponsored and managed by the
Company. NCE derives its revenues from its own oil and gas production, turnkey
drilling, well operations, gas gathering, transportation and gas marketing
services it provides for third parties.
During the fiscal year ended March 31, 2001, NCE successfully
integrated NCE Eastern which was acquired in March 2000, and successfully
executed drilling and development activities that resulted in significant
increases in its operations, proved reserves and financial results. Average
wells operated increased from approximately 1,700 in 2000 to approximately 3,800
in 2001 as a result of the NCE Eastern acquisition. NCE's proved developed
natural gas reserves increased to 124.4 Bcf for fiscal 2001 from 109.2 Bcf for
fiscal 2000 and proved developed oil reserves increased to 1,119,000 Bbls from
924,000 Bbls. The increase in proved reserves at the fiscal year-end resulted
from a successful exploration and development program and the extension of well
lives due to higher prices for natural gas at March 31, 2001 compared to March
31, 2000. The proved gas reserves (developed and undeveloped) increased to 143.4
Bcf for fiscal 2001 from 124.9 Bcf for fiscal 2000. The increase in proved gas
reserves was due to the increases mentioned previously for the proved developed
reserves. Proved oil reserves (developed and undeveloped) increased to 1,206,600
Bbls for fiscal 2001 from 1,021,400 Bbls for fiscal 2000.
NCE recognizes as proved undeveloped reserves only the potential oil
and gas which can reasonably be expected to be recovered from drillable
locations which it owned (or to which it had rights) at fiscal year end which
are directly offsetting locations to wells that have indicated commercial
production in the objective formation and which NCE fully expects to drill in
the near future. Changes in the Standardized Measure of Discounted Future Net
Cash Flows are set forth in Note 12 of the Company's financial statements. The
above mentioned additions and sales of natural gas, coupled with the development
costs associated with undeveloped acreage, create timing differences which are
reflected in the other category of the Standardized Measure. Of the Company's
total proved reserves, approximately 87% are proved developed and approximately
13% are proved undeveloped based upon equivalent unit Mcfs. Proved undeveloped
acreage requires considerable capital expenditures to develop. Management
believes that a significant percentage of the proved undeveloped reserves should
be recovered in future years, although no assurance of such recovery can be
given.
The following table is a review of the results of operations of the
Company for the fiscal years ended March 31, 2001, 2000 and 1999. All items in
the table are calculated as a percentage of total revenues.
2001 2000 1999
---- ---- ----
Revenues:
Oil and gas production 65% 53% 56%
Drilling 12% 28% 28%
Well operating, gathering and other 23% 19% 16%
--- --- ---
Total Revenues 100% 100% 100%
13
14
2001 2000 1999
---- ---- ----
Expenses:
Oil and gas production 20% 23% 20%
Drilling costs 10% 22% 23%
Well operating, gathering and other 12% 10% 9%
General and administrative 6% 10% 9%
Depreciation, depletion and amortization 18% 15% 19%
Interest (Net) 13% 12% 13%
Income taxes 6% 0% 0%
-- -- --
Total Expenses 85% 92% 93%
Net Income 15% 8% 7%
=== == ==
Net Income Applicable to Common Stock 14% 7% 5%
=== == ==
(1) Dividends were paid or accrued on the Series B cumulative preferred
stock in the amount of $232,864, $232,864 and $236,654 for fiscal 2001,
2000 and 1999.
The following discussion and analysis reviews the results of operations
and financial condition for the Company for the years ended March 31, 2001, 2000
and 1999. This review should be read in conjunction with the Financial
Statements and other financial data presented elsewhere herein.
COMPARISON OF FISCAL 2001 TO FISCAL 2000
REVENUES
Oil and gas production increased from 3.1 billion cubic feet equivalent
(Bcfe) in fiscal 2000 to 8.4 Bcfe in fiscal 2001. The acquisition of assets from
Environmental Exploration Corporation was completed in October of 1999 and the
acquisition of Peake Energy, Inc. was completed in March of 2000. The Company's
operating results for the year ended March 31, 2001, increased substantially due
to the inclusion of both acquisitions for the entire year 2001. Increased
production also resulted from the Company's drilling and development activities.
Oil and gas production revenues increased $21.2 million (258%) to $29.4 million
for fiscal 2001 compared to $8.2 million for fiscal 2000. The increase in oil
and gas revenues is attributed to higher volumes resulting from the above
acquisitions and higher prices received for oil and gas sold.
The Company received an average price of $3.49 per thousand cubic feet
equivalent (Mcfe) in fiscal 2001 compared to $2.63 in fiscal 2000.
Drilling revenues increased $1.3 million to $5.7 million for fiscal
2001 compared to $4.4 million in fiscal 2000 due to the increase in the number
of wells completed in fiscal 2001 in connection with the Company's 2000 Drilling
Program. Revenue was recognized on 34 wells in fiscal 2001 compared to 26 wells
for fiscal year 2000.
Well operating, gathering and other revenues increased $7.4 million to
$10.4 million for fiscal 2001 compared to $3.0 million for fiscal 2000. The
increases result primarily from increased volumes of gas transported through
facilities owned by the Company and an increase in wells operated for third
parties.
EXPENSES
Oil and gas production expense increased $5.5 million to $9.1 million
for fiscal 2001 from $3.6 million for fiscal 2000 primarily as a result of the
wells acquired and operated during the fiscal year. The Company's average
operating cost per Mcfe was $1.08 in fiscal 2001 compared to $1.14 in fiscal
2000.
Drilling costs for fiscal 2001 increased $1.3 million (38%) as a result
of the increased number of Drilling Program wells drilled and completed in
fiscal 2001 compared to fiscal 2000. The Company maintained a 17% profit margin
for wells drilled in fiscal 2001 compared to 21% in fiscal 2000.
14
15
Well operating, gathering and other expenses increased $3.7 million
(237%) to $5.3 million in fiscal 2001 from $1.6 million in fiscal 2000. The
increased costs resulted from the increase in the number of wells operated by
the Company through its acquisitions and drilling activities.
General and administrative expense increased $1.5 million (102%) to
$3.0 million from $1.5 million in fiscal 2000 as a result of costs associated
with the Company's business process reengineering efforts, the implementation of
a new software system including training and conversion expenses and additional
general and administrative expenses associated with the Company's recent
acquisitions. General and administrative expenses were 6% of revenue in fiscal
2001 compared to 10% in fiscal 2000.
Depreciation, depletion and amortization, increased $5.6 million to
$8.0 million in fiscal 2001 compared to $2.4 million in fiscal 2000 primarily as
a result of higher volumes resulting from the acquisitions discussed earlier.
Income from operations for fiscal 2001 increased $12.3 million (388%)
to $15.4 million from $3.1 million for fiscal 2000. The increase in income from
operations was primarily due to higher production resulting from the recent
acquisitions and the Company's drilling activity and higher prices paid for
natural gas and oil coupled with increased drilling revenues, well operating,
transportation and other revenues.
Net interest expense increased $4.1 million to $5.9 million from $1.8
million primarily reflecting the increase in the average outstanding borrowings
resulting from financing recent acquisitions.
The Company's higher level of income required a provision for deferred
taxes in fiscal 2001 where as no provision was required in fiscal 2000.
The Company's net income increased $5.5 million (415%) to $6.8 million
for the fiscal year ended March 31, 2001, from $1.3 million for the fiscal year
ended March 31, 2000, as a result of the items discussed above.
COMPARISON OF FISCAL 2000 TO FISCAL 1999
REVENUES
Oil and gas production increased from 2.9 Bcfe in fiscal 1999 to 3.1
Bcfe in fiscal 2000. The acquisition of assets from Environmental Exploration
was completed in October of 1999 and provided six months of operating results
for the fiscal year and the acquisition of NCE Eastern in March of 2000,
resulted in 14 days of operating results to the Company for the year ended March
31, 2000. Increased production also resulted from the Company's drilling and
development activities. Oil and gas production revenues increased $1.0 million
(14%) to $8.2 million for fiscal 2000 compared to $7.2 million for fiscal 1999.
The increase in oil and gas revenues is attributed to higher volumes and higher
prices received for oil and gas sold.
The Company received an average price of $20.08 and $11.39 per barrel
of oil for fiscal 2000 and 1999, and $2.58 and $2.57 per Mcf for natural gas for
fiscal years 2000 and 1999, respectively.
Drilling revenues increased $0.7 million (19%) to $4.4 million for
fiscal 2000 compared to $3.7 million for fiscal 1999 due to the increase in the
number of wells recognized in revenue for the comparable year ends. Drilling
revenues were recognized on 26 wells for fiscal year 2000 compared to 23 wells
for fiscal 1999.
Well operating, gathering and other revenues increased $1.0 million
(47%) to $3.0 million for fiscal 2000 compared to $2.0 million for fiscal 1999.
The increases result primarily from increased volumes of gas transported through
facilities owned by NCE and an increase in wells operated for third parties. The
Company also recognized $0.3 million in revenues from oilfield services provided
to third parties.
15
16
EXPENSES
Oil and gas production expense increased to $3.6 million for fiscal
2000 from $2.6 million for fiscal 1999 primarily as a result of the wells
acquired and operated during the fiscal year. The Company's average operating
cost per equivalent Mcf was $1.14.
Drilling costs for fiscal 2000 increased $0.5 million (18%) as a result
of the increased number of Drilling Program wells drilled and completed compared
to fiscal 1999. The Company maintained a 21% profit margin for wells drilled
during the fiscal year.
Well operating, gathering and other expenses increased $0.4 million
(31%) as a result of the increase in the number of wells operated by the Company
through its acquisition and drilling activities.
General and administrative expense increased $0.3 million (30%) as a
result of a one-time payment of $0.4 million to a former executive officer of
the Company in lieu of continuing his employment contract. As a percentage of
revenues, general and administrative expenses, excluding the one-time payment of
$0.4 million, decreased to 7% in fiscal year 2000 from 9% in fiscal year 1999.
Depreciation, depletion, amortization, impairment and other decreased
$76,744 primarily as a result of higher prices paid for oil and gas.
Interest expense increased $0.2 million to $2.0 million from $1.8
million primarily reflecting the increase in the average outstanding borrowings
resulting from the Company's acquisition activities.
Income from operations for fiscal 2000 increased $0.5 million (20%) to
$3.1 million from $2.6 million for fiscal 1999. The increase in income from
operations was primarily due to higher production and higher prices paid for
natural gas and oil and increased drilling revenues, well operating,
transportation and other revenues.
The Company's net income as a result of the aforementioned areas of
improvement increased $0.4 million (51%) to $1.3 million for the fiscal year
ended March 31, 2000, from $0.9 million for the fiscal year ended March 31,
1999.
INFLATION AND CHANGES IN PRICES
Inflation affects the Company's operating expenses as well as interest
rates, which may have an affect on the Company's profitability. Oil and gas
prices have not followed inflation and have fluctuated during recent years as a
result of other forces such as OPEC, economic factors, demand for and supply of
natural gas in the United States and within the Company's regional area of
operation. Oil prices during the Company's fiscal year have increased as a
result of continued production constraints by members of OPEC which has reduced
the available supply of crude oil to world markets. Natural gas prices have also
increased particularly during the third quarter of the fiscal year ended March
31, 2001, but have retreated since then. These increases in price are attributed
to lower storage supplies following the winter of 2000/2001 and higher natural
gas demand for the generation of electricity in the United States. As a result
of these market forces, the Company received an average price of $28.28 per
barrel of oil for fiscal 2001 compared to $20.08 for fiscal 2000. The Company
received an average price of $3.40 per Mcf for its natural gas for fiscal 2001
compared to $2.58 for fiscal 2000.
The Company cannot predict the duration of the current strength of oil
and gas markets and price, as those forces noted above, as well as other
variables, may change.
Currently, NCE sells natural gas under fixed price contracts, on the
spot market and uses financial hedging instruments to realize a fixed price on a
portion of its production. The Company has positioned itself to take advantage
of current market conditions by fixing a greater portion of its gas to contracts
of a year or longer at prices substantially higher than were received in recent
years. Additionally, the Company continues to acquire and construct new
gathering systems to transport natural gas from Company wells and third parties.
16
17
The following table reflects the natural gas volumes and the weighted
average prices under financial hedges and fixed price contracts at June 15,
2001:
FINANCIAL HEDGES FIXED PRICE CONTRACTS
---------------- ---------------------
ESTIMATED ESTIMATED
NYMEX WELLHEAD WELLHEAD
QUARTER ENDING MMCF PRICE PRICE MMCF PRICE
- -------------- ---- ----- ----- ---- -----
September 30, 2001 727 $4.01 $3.99 1,093 $3.39
December 31, 2001 727 4.30 3.99 954 3.32
March 31, 2002 327 4.39 4.50 507 3.09
June 30, 2002 0 -- -- 507 3.09
September 30, 2002 0 -- -- 507 3.09
December 31, 2002 0 -- -- 507 3.09
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to
and dependent on the current prices paid principally for natural gas and to a
lesser extent, oil.
The Company's working capital was $16.1 million at March 31, 2001,
compared to $5.3 million at March 31, 2000. The increase of $10.8 million in
working capital reflects the working capital generated by operations during
fiscal 2001, the recent acquisitions and the funds received from the formation
of the 2000 Drilling Program. As of March 31, 2001, the Company had $57.0
million outstanding under its Credit Facility and $10.0 million in borrowings
from NUON.
The following table summarizes the Company's financial position at
March 31, 2001 and 2000:
(Amounts in Thousands) 2001 2000
---- ----
Amount % Amount %
------ - ------ -
Working capital $ 16,075 13 $ 5,351 5
Property and equipment 105,243 84 104,763 91
Other 3,506 3 4,491 4
-------- --- -------- ---
Total $124,824 100 $114,605 100
======== === ======== ===
Long-term debt $ 67,167 54 $ 90,122 79
Deferred income taxes and other liability 3,705 3 1,091 1
Stockholders' equity 53,952 43 23,392 20
-------- --- -------- ---
Total $124,824 100 $114,605 100
======== === ======== ===
The oil and gas exploration and development activities of NCE
historically have been financed through the Drilling Programs, through
internally generated funds, and from bank financing.
The following table summarizes the Company's Statements of Cash Flows
for the years ended March 31, 2001, 2000 and 1999:
(Amounts in thousands) 2001 2000 1999
---- ---- ----
Net cash provided by operating activities $21,589 $ 3,901 $ 2,385
Net cash used in investing activities (7,102) (75,443) (20,913)
Net cash provided by (used in) financing activities (2,405) 75,792 18,906
------- ------ ------
Increase in cash and cash equivalent $12,082 $ 4,250 $ 378
======= ======= =======
As the above table indicates, the Company's cash provided by operating
activities was $21.6 million for fiscal 2001 compared to $3.9 million for fiscal
2000. The increase results mainly from the recent acquisitions and higher prices
for natural gas and oil.
17
18
Net cash used for investing activities was $7.1 million for fiscal
2001. The decrease in fiscal 2001 was due to the acquisitions of NCE Eastern and
the assets of Environmental Exploration in fiscal 2000.
Net cash used in financing activities was $2.4 million for fiscal 2001.
The decrease from $75.8 million in fiscal 2000 reflects the financing in fiscal
2000 of the above mentioned acquisitions.
On September 26, 2000, the Company entered into a five year, $125
million Credit Agreement with a group of four banks with Union Bank of
California acting as agent Bank. The new Credit Agreement replaced the Company's
previous credit agreement with ING (US) Capital Corporation. The Credit
Agreement provides for a borrowing base that is determined semiannually by the
lenders based on the Company's financial position, oil and gas reserves and
certain other factors (presently $65.0 million). The agreement provides for a
3/8% commitment fee on amounts not borrowed up to the borrowing base and allows
for a sub-limit of $5.0 million for the issuance of letters of credit. The
agreement restricts the Company from incurring additional debt or liens,
prohibits dividends and distributions (except for the outstanding preferred A
and B shares), and requires the Company to maintain positive working capital and
minimum interest and fixed charge coverage.
The amounts borrowed under its Credit Agreement are secured by the
Company's receivables, inventory, equipment and a first mortgage on certain of
the Company's interests in oil and gas wells and reserves.
The Company elected to pay off the mortgage on its headquarters
building in April 2001. As a result the entire amount is reflected as a current
liability.
During fiscal 2002, the Company expects to spend approximately $9.4
million on drilling and lease acquisition and $0.6 million on other capital
expenditures. These capital expenditures will be financed from cash on hand,
free cash flow generated during the year and, if needed, from available
borrowings.
The Company acquired 100% of the stock of NCE Eastern per the terms of
a Stock Purchase Agreement dated March 17, 2000. The Company borrowed $72.5
million from NUON to finance the acquisition. On May 4, 2000, the Company
honored NUON's election to convert $24.0 million of the NUON debt to 9.6 million
common shares, and the Company later repaid $38.5 million to NUON from the
proceeds of the above mentioned Credit Agreement.
ACCOUNTING STANDARDS
On April 1, 2001, the Company adopted Statement of Financial Accounting
Standard No. 133 (SFAS 133), "Accounting for Derivative Instruments and Hedging
Activities," as amended. As a result of the adoption of SFAS 133, the Company
will recognize all derivative financial instruments as either assets or
liabilities at fair value. Derivative instruments that are not effective hedges
must be adjusted to fair value through the income statement. Changes in the fair
value of derivative instruments that are fair value hedges are offset against
changes in the fair value of the hedged asset, liability or firm commitment in
the income statement. Changes in fair value of derivative instruments that are
cash flow hedges are recognized as a component of other comprehensive income or
loss until such time as the hedged items are recognized in the income statement.
Ineffective portions of the derivative instrument's change in fair value are
immediately recognized in the income statement.
The adoption of SFAS 133 will result in an April 1, 2001 transaction
adjustment to increase current liabilities by $3.2 million, increase deferred
tax assets by $1.1 million and decrease shareholders equity by $2.1 million to
record the fair value of open cash flow hedges and the related income tax
effect. The decrease in stockholders equity will be reflected as a transition
adjustment in other comprehensive income on April 1, 2001.
FORWARD LOOKING INFORMATION
The forward looking statements regarding future operations and
financial performance contained in this report involve risks and uncertainties
that include, but are not limited to the supply of and market demand for natural
gas and oil, levels of natural gas and oil production and cost of operations,
results of the Company's drilling, availability of capital to the Company,
uncertainties associated with reserve estimates, environmental risks and other
factors included in the Company's filings with the SEC. Actual results may
differ materially from forward-looking information included in this report.
18
19
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to commodity price and interest rate risks.
The Company's primary interest rate risk exposure results from floating
rate debt including debt under the Company's revolving Credit Facility and the
Subordinated Promissory Note between the Company and NUON. At March 31, 2001,
substantially all of the Company's total long-term debt consisted of floating
rate debt. If interest rates were to increase 100 basis points (1%) from March
31, 2001, and assuming no changes in long-term debt from the March 31, 2001,
levels, the additional annual expense would be approximately $670,000 on a
pre-tax basis. The Company currently does not hedge its exposure to this
floating interest rate risk.
The Company is exposed to commodity price risks related to natural gas
and oil. The Company's financial results can be significantly impacted by
changes in commodity prices. Effective with May 2000 production, the Company
entered into a natural gas hedge to eliminate exposure to changes in natural gas
prices that may affect a portion of its net production contracted to one large
industrial customer. The hedge involves the use of a financial swap and fixes
the Company's price at $3.51 per Mcf on 5,000 Mcf per day through December 2001.
Gains or losses on the hedge relative to the market are recognized monthly as
additions to or subtractions from oil and gas sales. Subsequent to March 31,
2001, the Company entered into a costless collar arrangement that establishes a
floor and ceiling price ($4.10 and $5.30 per Mcf, respectively) for 4,000 Mcf
per day through March 31, 2002.
The information included in this Item is considered to constitute "forward
looking statements" for purposes of the statutory safe harbor provided in
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. See "Management's discussion and
Analysis of Financial Condition and Results of operations - Forward Looking
Information" in Item 7 of this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
19
20
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of June 15, 2001
were as follows:
Name Age Position
---- --- --------
Omer Yonel 37 President, Chief Executive Officer and
Director
Dale E. Stitt 56 Chief Financial Officer
Thomas A. Hill 43 Secretary and General Counsel
Carel W.J. Kok 35 Chairman of the Board and Director
Cok van der Horst 56 Director
Ron L. Langenkamp 56 Director
Ralph L. Bradley 60 Director
C. Rand Michaels 64 Director
Garry Regan 51 Director
20
21
OMER YONEL was appointed Executive Vice President-Corporate Development
of North Coast Energy, Inc. in January 1999; in May 1999 he was promoted to
Chief Operating Officer and in October 1999 Mr. Yonel was promoted to Chief
Executive Officer and appointed as a Director. In May 2001, he was appointed to
the additional position of President. Mr. Yonel has over ten years of
international experience in project engineering, project management and sales in
the European oil and gas industry. Prior to joining NUON in January 1998, he was
a project manager for the construction of co-generation and power plants at
Schelde Engineering & Contractors bv. Previous to his service with Schelde, Mr.
Yonel held various project engineering, management and sales positions at ABB
Lummus, an Asea Brown Boveri subsidiary that provides engineering, management
and consultancy services to global chemical, petrochemical, petroleum refining,
oil and gas and other industries. Mr. Yonel holds a B.S. as well as a MSc.
degree in Engineering from Delft University of Technology in The Netherlands.
Additionally, Mr. Yonel has a certification of Project Management, is a
certified Cost Engineer through the International Cost Engineering Council and
holds several certifications from Executive Education programs and Post-Graduate
programs, including Mergers & Acquisitions from Columbia University in New York.
DALE E. STITT has served as Chief Financial Officer since January 2001.
He is a Certified Public Accountant, and was previously employed by Ernst &
Young LLP from June 1967 to December 2000, serving most recently as an audit
partner. Mr. Stitt has extensive experience in the oil and gas industry, where
he has specialized in mergers and acquisitions, transaction financing and the
public offering of securities. He holds a Bachelor of Science degree in
Accounting from Miami University, and attended the Executive Program at the J.L.
Kellogg Graduate School of Management at Northwestern University. Mr. Stitt is a
member of the American Institute of Certified Public Accountants, the Ohio
Society of Certified Public Accountants, the Independent Petroleum Association
of America, the Ohio Oil & Gas Association, the Ohio Petroleum Producers
Accountants Society and the Miami University Business Advisory Council.
THOMAS A. HILL served as Secretary and General Counsel of North Coast
Energy from August 1988 until his resignation from the Company in June 2001. Mr.
Hill joined Capital Oil & Gas, Inc. in 1984 before its acquisition by North
Coast. He graduated from Hiram College with a Bachelor of Arts degree in History
and Political Science and from George Washington University National Law Center
with a Juris Doctor degree. Mr. Hill is a member of the state bars of Ohio,
Pennsylvania, Texas, Oklahoma and the District of Columbia and the Energy Bar
Association.
CAREL W.J. KOK was elected as a Director in December 1998 and currently
serves as Chairman of the Board of Directors of the Company. Mr. Kok has been
Chief Growth Officer and a member of the Nuon Executive Management Board since
July 1, 2000. Previously he was Director of Mergers & Acquisitions and Strategy
with the Nuon Energy Group. Prior to that he held various positions with Nuon's
International Division. From 1990 to 1995, he was with Royal Dutch Shell Group
working in a variety of downstream commercial, trading and new business
development functions in East Asia, the Middle East as well as Europe. Mr. Kok
holds various board positions with subsidiaries of the Nuon Group and is a
Supervisory Board Member of the Amsterdam Power Exchange (APX). Mr. Kok holds a
B.A. from Princeton University and an M.B.A. from the Rotterdam School of
Management at Erasmus University.
COK VAN DER HORST was appointed to the Board of Directors in October
1999. Mr. van der Horst is currently Advisor to the Management Board of nv NUON.
He previously served as the Director, NUON East and North Holland, where he was
the Chief Financial Officer between 1993 and 1999, and was also in charge of
technical affairs, information technology, personnel and activities in the
national energy market. He has recently assumed responsibilities in the area of
regulatory affairs, mergers, acquisitions and divestments for the parent
company, nv NUON. Prior to joining NUON in January of 1993, Mr. van der Horst
was chairman of the board of PEB, the energy distribution company of the
province of Friesland (a regional government in The Netherlands). At PEB he was
responsible for financial and economic policy. Mr. van der Horst holds a
Master's degree in business administration from Erasmus University in Rotterdam.
21
22
RON L. LANGENKAMP is currently Manager of Energy and Wholesale Trading
for NUON. Mr. Langenkamp most recently served for two years as an external
consultant to Reliant Energy, Inc. and supervised all European commercial
activities in his role as Acting Chief Commercial Officer. From 1994 to 1997 Mr.
Langenkamp served in various capacities, including President, of Norstar, a
natural gas retail sales partnership between Orange and Rockland Utilities, Inc.
and Shell Oil Company. From 1977 to 1994 Mr. Langenkamp held various management
positions in the energy industry including the office of President of Cabot
Transmission Company and then as President of Chippewa Gas Corporation. Mr.
Langenkamp received his B.A. degree from Sam Houston State University and a
Master's degree from the University of Texas at Austin.
RALPH L. BRADLEY was elected as a Director in December 1997. Mr. Bradley
is currently President of Bradley Energy USA, which provides energy solutions
for the oil and gas industry. Prior to forming this entity, Mr. Bradley was
chief executive officer of The Eastern Group, Inc., and its predecessor, Eastern
States Exploration Company, Inc. Mr. Bradley currently chairs the Stock Option
and Compensation Committee of the Board of Directors.
C. RAND MICHAELS was elected a Director of North Coast in 1996. Mr.
Michaels retired from the office of Vice Chairman of Range Resources Corporation
(formerly Lomak Petroleum, Inc.) and is Chairman Emeritus of Range Resources
Corporation. He served as the President and Chief Executive Officer of Lomak
Petroleum, Inc. from 1976 through 1988 and Chairman of the Board from 1984
through 1988, when he became Vice Chairman of Lomak Petroleum, Inc. Mr. Michaels
received his B.S. from Auburn University and his M.B.A. from the University of
Denver. Mr. Michaels currently chairs the Audit Committee of the Board of
Directors.
GARRY REGAN participated in the organization of North Coast's
predecessor in 1981, and served as an executive officer and Director since that
time, serving as President from August 1988 through April 2001. He holds a B.S.
degree from Ohio State University and a Masters degree from Indiana University.
Mr. Regan is a member of the Independent Petroleum Association of America.
Information required by this Item 10 as to the Executive Officers of the
Company is included in Part I of this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item 11 is incorporated by reference to
the information set forth under the caption "Executive Compensation" in the
Company's definitive Proxy Statement for the 2001 Annual Meeting of
Stockholders, since such Proxy Statement will be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal year pursuant to Regulation 14A.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item 12 is incorporated by reference to
the information set forth under the captions "Principal Shareholders" and "Share
Ownership of Directors and Officers" in the Company's definitive Proxy Statement
for the 2001 Annual Meeting of Stockholders, since such Proxy Statement will be
filed with the Securities and Exchange Commission not later than 120 days after
the end of the Company's fiscal year pursuant to Regulation 14A.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item 13 is incorporated by reference to
the information set forth under the caption "Transactions with Management" in
the Company's definitive Proxy Statement for the 2001 Annual Meeting of
Stockholders, since such Proxy Statement will be filed with the Securities and
Exchange Commission not later than 120 days after the end of the Company's
fiscal year pursuant to Regulation 14A.
22
23
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) Financial Statements
The following Consolidated Financial Statements of the Registrant and
its subsidiaries are included in Part II, Item 8:
Page(s)
-------
Auditor's Report on the Financial Statements......................F-3
Consolidated balance sheets.......................................F-4 - F-5
Consolidated statements of operations.............................F-6
Consolidated statements of stockholders' equity...................F-7
Consolidated statements of cash flows.............................F-8 - F-9
Notes to consolidated financial statements........................F-10 - F-26
(a) (2) Financial Statements Schedules
All schedules for which provision is made in the applicable accounting
regulation of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable, and therefore have been omitted.
(a) (3) Exhibits
Reference is made to the Exhibit Index.
(b) Reports on Form 8-K:
The Company's report on Form 8-K dated April 5, 1999.
The Company's report on Form 8-K dated March 22, 2000.
The Company's report on Form 8-K/A dated May 23, 2000.
23
24
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
By /s/ Omer Yonel President and Chief Executive Officer June 28, 2001
- ----------------------------------
Omer Yonel
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
President, Chief Executive Officer June 28, 2001
/s/ Omer Yonel and Director (principal executive officer)
- ----------------------------------
Omer Yonel
Chief Financial Officer and Secretary June 28, 2001
/s/ Dale E. Stitt (principal accounting and financial officer)
- ----------------------------------
Dale E. Stitt
Carel W. J. Kok Chairman of the Board and Director June 28, 2001
- ----------------------------------
Carel W. J. Kok
Cok van der Horst Director June 28, 2001
- ----------------------------------
Cok van der Horst
Ron L Langenkamp Director June 28, 2001
- ----------------------------------
Ron L. Langenkamp
/s/ Ralph L. Bradley Director June 28, 2001
- ----------------------------------
Ralph L. Bradley
/s/ C. Rand Michaels Director June 28, 2001
- ----------------------------------
C. Rand Michaels
/s/ Garry Regan Director June 28, 2001
- ----------------------------------
Garry Regan
24
25
Exhibit Index
-------------
Exhibit Sequential
Number Description of Documents Page
- ------- ------------------------ ----
3.1 Certificate of Incorporation of the Registrant dated August 30, 1988. (B)
3.2 Certificate of Stock Designation of the Registrant filed September 12, 1988. (B)
3.3 Certificate of Stock Designation of the Registrant filed September 14, 1989. (B)
3.4 Certificate of Correction filed March 22, 1991. (C)
3.5 Certificate of Amendment to Certificate of Incorporation filed November 4, 1992. (A)
3.6 Certificate of Stock Designation filed December 29, 1992. (D)
3.7 Certificate of Amendment to Certificate of Incorporation filed August 29, 1994. (G)
3.8 Certificate of Amendment of Certificate of Incorporation filed December 16, 1998. (J)
3.9 Certificate of Correction filed November 15, 1999. (M)
10.1 1988 Stock Option Plan. (B)
10.2 Form of Profit Sharing Plan. (B)
10.3 Form of Indemnity Agreement between the Registrant and each of its Directors and (B)
executive officers.
10.4 North Coast Energy, Inc. Key Employees Stock Bonus Plan. (B)
10.5 Stock Option Agreement dated as of May 17, 1991 between Registrant and Timothy Wagers. (C)
10.6 Stock Option Agreement dated as of May 17, 1991 between the Registrant and Thomas A. (C)
Hill.
10.7 Option Agreement dated February 22, 1994 by and between Registrant and Charles M. (E)
Lombardy, Jr.
10.8 Option Agreement dated February 22, 1994 by and between Registrant and Garry Regan. (E)
10.9 Warrant to purchase 200,000 shares of Common Stock of the Company. (G)
10.10 Warrant to purchase 300,000 shares of Common Stock of the Company. (G)
10.11 Restated Employment Agreement dated May 3, 1995 by and between Registrant and Charles (H)
M. Lombardy, Jr.
10.12 Restated Employment Agreement dated May 3, 1995 by and between Registrant and Garry (H)
Regan.
10.13 Open End Mortgage and Promissory Note by and between ING Capital and the Company dated (K)
February 9, 1998.
10.14 Purchase and Sale Agreement dated April 8, 1998 between Kelt Ohio, Inc., and North (I)
Coast Energy, Inc.
10.15 Ratification and Amendment to Purchase and Sale Agreement dated May 12, 1998 between (I)
Kelt Ohio, Inc., and North Coast Energy, Inc.
10.16 First Amendment to Credit Agreement and Promissory Note dated May 29, 1998 between ING (I)
(U.S.) Capital Corporation and North Coast Energy, Inc.
10.17 Second Amendment to Credit Agreement and Promissory Note dated September 2, 1998 (K)
between ING (U.S.) Capital Corporation and North Coast Energy, Inc.
10.18 Warrants to purchase 300,000 shares (pre-split) of Common Stock of the Company. (K)
25
26
Exhibit Index
-------------
Exhibit Sequential
Number Description of Documents Page
- ------- ------------------------ ----
10.19 Separation Agreement dated April 30, 1999 by and among North Coast Energy, Inc., NUON (K)
International Projects, bv, Charles M. Lombardy, Jr., and Betty M. Lombardy.
10.20 Third Amendment to Credit Agreement and Promissory Note dated June 23, 1999 between (K)
ING (U.S.) Capital Corporation and North Coast Energy, Inc.
10.21 North Coast Energy, Inc. 1999 Employee Stock Option Plan (M)
10.22 Stock Purchase Agreement between Belden & Blake Corporation and North Coast Energy, (L)
Inc. dated March 17, 2000.
10.23 Non-Negotiable Subordinated Promissory Note in the amount of $48,500,000 between North (L)
Coast Energy, Inc. as maker and NUON International Projects, bv as holder, dated March
17, 2000.
10.24 Non-Negotiable Subordinated Convertible Promissory Note in the amount of $24,000,000 (L)
between North Coast Energy, Inc. as maker and NUON International Projects, bv as
holder dated March 17, 2000.
10.25 Fourth Amendment to Credit Agreement and Promissory Noted dated March 17, 2000 between (M)
ING (U.S.) Capital LLC, as Agent, and North Coast Energy, Inc., as Borrower.
10.26 Amendment to North Coast Energy, Inc. Employees' Profit Sharing Plan, effective April (M)
1, 2000.
10.27 $125 million Credit Agreement dated September 26, 2000, between North Coast Energy, (N)
Inc. as Borrower, Union Bank of California, NA, as Agent, Bank One, Texas, NA,
as Syndication Agent, and certain financial institutions as Lenders.
10.28 First Amendment to Credit Agreement dated March 27, 2001 between North Coast Energy, --
Inc., as Borrower, Union Bank of California, NA, as Agent, and certain other financial
institutions as Lenders.
10.29 North Coast Energy, Inc. 2000 Employee Stock Bonus Plan, effective February 1, 2001. --
21.1 List of Subsidiaries. (M)
23.1 Consent of Hausser + Taylor LLP. --
27.1 Financial Data Schedule *
- -----------------------------------------
(A) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Registration Statement on Form S-2 (Reg. No.
33-54288).
(B) Incorporated herein by reference to the appropriate exhibits to
the Company's Registration Statement on Form S-1 (File No.
33-24656).
(C) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1991.
(D) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1993.
(E) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1994.
(F) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Quarterly Report on form 10-Q for the fiscal
quarter ended September 30, 1994.
26
27
(G) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1995.
(H) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1996.
(I) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Report on Form 8-K dated June 12, 1998.
(J) Incorporated herein by reference to the appropriate exhibits to
the Company's Registration Statement on Form S-1 (File No.
33-71855).
(K) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 1999.
(L) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Report on Form 8-K dated March 22, 2000.
(M) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Annual Report on Form 10-K for the fiscal year
ended March 31, 2000.
(N) Incorporated herein by reference to the appropriate exhibit to
the Registrant's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000.
*Exhibit 27.1 furnished for Securities and Exchange Commission purposes only.
27
28
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.
June 28, 2001 /s/ Omer Yonel
-----------------------------------------
Omer Yonel
President, Chief Executive Officer and Director
28
29
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
2001 CONSOLIDATED FINANCIAL REPORT
F-1
30
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONTENTS
- --------------------------------------------------------------------------------
Page
----
AUDITORS' REPORTS ON THE FINANCIAL
STATEMENTS F-3
FINANCIAL STATEMENTS
Consolidated balance sheets F-4 - F-5
Consolidated statements of operations F-6
Consolidated statements of stockholders' equity F-7
Consolidated statements of cash flows F-8 - F-9
Notes to consolidated financial statements F-10 - F-26
F-2
31
Report of Independent Public Accountants
----------------------------------------
To the Board of Directors and Stockholders
North Coast Energy, Inc.
Cleveland, Ohio
We have audited the accompanying consolidated balance sheets of North
Coast Energy, Inc. (a Delaware corporation) and subsidiaries as of March 31,
2001 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended March 31, 2001. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of North
Coast Energy, Inc. and subsidiaries as of March 31, 2001 and 2000, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended March 31, 2001, in conformity with accounting
principles generally accepted in the United States of America.
HAUSSER + TAYLOR LLP
Cleveland, Ohio
June 20, 2001
F-3
32
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 2001 and 2000
- --------------------------------------------------------------------------------
2001 2000
---- ----
ASSETS
------
CURRENT ASSETS
Cash and equivalents $ 18,288,814 $ 6,206,686
Accounts receivable:
Trade, net 7,846,469 7,202,492
Affiliates - 205,775
Inventories 307,195 450,718
Other, net 161,819 297,720
------------ ------------
Total current assets 26,604,297 14,363,391
PROPERTY AND EQUIPMENT, at cost
Land 222,822 222,822
Oil and gas properties (successful efforts) 108,466,905 102,177,522
Gathering systems 16,092,838 15,798,806
Vehicles 1,986,671 1,970,687
Furniture and fixtures 659,103 627,414
Building and improvements 1,847,463 1,845,457
------------ ------------
129,275,802 122,642,708
Less accumulated depreciation, depletion, amortization and
impairment 24,032,646 17,879,417
------------ ------------
105,243,156 104,763,291
OTHER ASSETS, net 3,505,711 4,491,322
------------ ------------
$ 135,353,164 $ 123,618,004
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
33
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 2001 and 2000
- --------------------------------------------------------------------------------
2001 2000
------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt $ 557,400 $ 3,124,600
Accounts payable 3,012,992 2,132,158
Accrued expenses 6,081,521 3,188,718
Billings in excess of costs on uncompleted contracts 877,281 568,056
------------- -------------
Total current liabilities 10,529,194 9,013,532
LONG-TERM DEBT, net of current portion
Affiliates 10,000,000 72,500,000
Non-affiliates 57,166,626 17,622,181
------------- -------------
67,166,626 90,122,181
ACCRUED PLUGGING LIABILITY 638,877 724,535
DEFERRED INCOME TAXES 3,066,200 366,200
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Series A, 6% Noncumulative Convertible Preferred stock, par value $.01
per share; 563,270 shares authorized; 73,096 issued and outstanding
(aggregate liquidation value of $730,960) 731 731
Series B, Cumulative Convertible Preferred stock, par value $.01 per
share; 625,000 shares authorized; 232,864 issued and outstanding
(aggregate liquidation value of $2,328,640 plus dividends in arrears
of $326,010) 2,329 2,329
Undesignated Serial Preferred stock, par value $.01 per share; 811,730
shares authorized; none issued and outstanding - -
Common stock, par value $.01 per share; 60,000,000 shares authorized;
15,208,031 and 5,599,706 issued and outstanding 152,080 55,997
Additional paid-in capital 50,213,422 26,274,574
Retained earnings (deficit) 3,583,705 (2,942,075)
------------- -------------
Total stockholders' equity 53,952,267 23,391,556
------------- -------------
$ 135,353,164 $ 123,618,004
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
34
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended March 31, 2001, 2000 and 1999
- --------------------------------------------------------------------------------
2001 2000 1999
------------ ------------ ------------
REVENUE
Oil and gas production $ 29,399,487 $ 8,223,202 $ 7,233,763
Drilling revenues 5,710,640 4,375,922 3,686,158
Well operating, gathering and other 10,425,066 3,040,547 2,062,213
------------ ------------ ------------
45,535,193 15,639,671 12,982,134
COSTS AND EXPENSES
Oil and gas production expenses 9,071,659 3,572,027 2,601,555
Drilling costs 4,758,722 3,454,287 2,927,302
Well operating, gathering and other 5,306,277 1,573,963 1,200,514
General and administrative expenses 3,011,233 1,492,000 1,148,782
Depreciation, depletion, amortization, impairment and other 8,032,873 2,402,800 2,479,544
------------ ------------ ------------
30,180,764 12,495,077 10,357,697
------------ ------------ ------------
INCOME FROM OPERATIONS 15,354,429 3,144,594 2,624,437
OTHER INCOME (EXPENSE)
Interest income 724,367 162,413 82,505
Other - 62,548 4,380
Interest expense (6,620,152) (2,057,739) (1,841,108)
------------ ------------ ------------
(5,895,785) (1,832,778) (1,754,223)
------------ ------------ ------------
INCOME BEFORE PROVISION FOR INCOME TAXES 9,458,644 1,311,816 870,214
PROVISION FOR INCOME TAXES 2,700,000 - -
------------ ------------ ------------
NET INCOME $ 6,758,644 $ 1,311,816 $ 870,214
============ ============ ============
NET INCOME APPLICABLE TO COMMON STOCK (after
dividends on cumulative Preferred Stock of $232,864,
$232,864 and $236,654, respectively) $ 6,525,780 $ 1,078,952 $ 633,560
============ ============ ============
NET INCOME PER SHARE (basic and diluted) $ 0.46 $ 0.21 $ 0.16
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
35
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years Ended March 31, 2001, 2000 and 1999
- --------------------------------------------------------------------------------
Series A Series B
Preferred Stock Preferred Stock
---------------------------- ----------------------------
Shares Amount Shares Amount
------------ ------------ ------------ ------------
BALANCE, MARCH 31, 1998 75,481 $ 755 268,264 $ 2,683
Net income - - - -
Shares converted (1,665) (17) (35,400) (354)
Dividends on Series B Preferred stock ($.85
per share) - - - -
Issuance of common stock - - - -
------------ ------------ ------------ ------------
BALANCE, MARCH 31, 1999 73,816 738 232,864 2,32