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.
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.
- 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.
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.
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.
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
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.
ITEM 2.
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.
(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.
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.
(1) Exploratory Wells are those wells drilled outside the confines of a known productive reservoir area.
(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.
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.
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.
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.
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.
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.
(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.
(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.
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%
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.
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.
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.
The following table reflects the natural gas volumes and the weighted average prices under financial hedges and fixed price contracts at June 15, 2001:
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:
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:
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.
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.
ITEM 7A.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
ITEM 9.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not Applicable.
PART III
ITEM 10.
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
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.
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.
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.
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.
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.
PART IV -------
ITEM 14.
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 -
Consolidated statements of operations.............................F-6
Consolidated statements of stockholders' equity...................F-7
Consolidated statements of cash flows.............................F-8 -
Notes to consolidated financial statements........................F-10 -
(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.
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.
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.
Exhibit Index -------------
Exhibit Index -------------
- -----------------------------------------
(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.
(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.
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
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
2001 CONSOLIDATED FINANCIAL REPORT
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONTENTS
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Page ----
AUDITORS' REPORTS ON THE FINANCIAL STATEMENTS
FINANCIAL STATEMENTS Consolidated balance sheets - Consolidated statements of operations Consolidated statements of stockholders' equity Consolidated statements of cash flows - Notes to consolidated financial statements -
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
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 2001 and 2000 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
March 31, 2001 and 2000 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended March 31, 2001, 2000 and 1999 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years Ended March 31, 2001, 2000 and 1999 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended March 31, 2001, 2000 and 1999 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Years Ended March 31, 2001, 2000 and 1999 - --------------------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization - North Coast Energy, Inc. ("NCE"), a Delaware corporation, was formed in August 1988 to engage in the exploration, development and production of oil and gas, the acquisition of producing oil and gas properties, and the organization and management of oil and gas partnerships.
B. Principles of Consolidation - The consolidated financial statements include the accounts of North Coast Energy, Inc. and its wholly owned subsidiaries (collectively, "the Company"), North Coast Energy Eastern, Inc. (formerly Peake Energy, Inc.), North Coast Operating Company ("NCOC") and NCE Securities, Inc. ("NCE Securities"). In addition, the Company's investments in 21 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 interest in these partnerships varies from 14% to 52%.
All significant intercompany accounts and transactions have been eliminated.
C. Inventories - Inventories consist of material, pipe and supplies valued at the lower of cost or market.
D. Cash Equivalents - Investments having an original maturity of 90 days or less that are readily convertible into cash have been included in, and are a significant portion of, the cash and cash equivalents balances.
E. Property and Equipment - Property and equipment are stated at cost and are depreciated or depleted principally on methods and at rates designed to amortize their costs over their estimated useful lives (proved oil and gas properties using the unit-of- production method based upon estimated proved developed oil and gas reserves, pipelines using the straight-line method over 10 to 25 years, vehicles, furniture and fixtures using accelerated methods over 3 to 15 years, building and improvements using various methods over 7 - 31.5 years).
F. Oil and Gas Investments and Properties - The Company uses the successful efforts method of accounting for oil and gas producing activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip developmental wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, costs of developmental wells on properties the Company has no further interest in, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
Unproved oil and gas properties that are significant are periodically assessed for impairment of value and a loss is recognized at the time of impairment by providing an impairment allowance. Other unproved properties are expensed when surrendered or expired.
When a property is determined to contain proved reserves, the capitalized costs of such properties are transferred from unproved properties to proved properties and are amortized by the unit-of-production method based upon estimated proved developed reserves. To the extent that capitalized costs of groups of proved properties having similar characteristics exceed the estimated future net cash flows, the excess capitalized costs are written down to the present value of such amounts. Estimated future net cash flows are determined based primarily upon the estimated future proved reserves related to the Company's current proved properties and, to a lesser extent, certain future net cash flows related to operating and related fees due the Company related to its management of various partnerships. The Company follows Statement of Financial Accounting Standards ("SFAS") No. 121 which requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment is recorded on a drilling program or property (or groups of properties) specific basis, as applicable.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
F. Oil and Gas Investments and Properties (Continued)
On sale or abandonment of an entire interest in an unproved property, gain or loss is recognized, taking into consideration the amount of any recorded impairment. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. The carrying cost of unproved properties is not significant.
G. Revenue Recognition - The Company recognizes revenue on drilling contracts using the completed contract method of accounting for both financial reporting purposes and income tax purposes. This method is used because the typical contract is completed in three months or less. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Billings in excess of costs on uncompleted contracts are classified as current liabilities.
Oil and gas production revenue is recognized as income as it is extracted from the properties and sold. In the year ended March 31, 2001, oil and gas sales were reduced by approximately $3.9 million for the effect of natural gas hedging activities. Well operating, gathering and other revenues include operating fees charged to outside working interest owners in NCE operated wells, gathering fees (including transportation allowances and compression fees), third party gas sales associated with purchased natural gas and other miscellaneous revenues. Such revenue is recognized at the time it is earned and the Company has a contractual right to receive payment. Administrative fees received from NCE organized and managed oil and gas partnerships are treated as a reduction of the Company's general and administrative expenses.
H. Per Share Amounts - The computation of basic and diluted earnings per share does not assume the conversion of the unconverted Series B (1999) Preferred stock or the effect of warrants and stock options outstanding (2000 and 1999) due to either, the average market price of the common shares being lower than the prices of all of the options and warrants currently outstanding, or the effect being anti-dilutive. For the years ended March 31, 2001, 2000 and 1999, the conversion of Series A stock had the effect of increasing the denominator (average outstanding shares) by 33,624, 16,847 and 17,116 shares, respectively, while the conversion of Series B stock increased the denominator by 76,321 shares in 2001 and 2000. Assumed exercise of stock options had the effect of adding 3,645 shares to the denominator for the year ended March 31, 2001. Assumed debt conversion of NUON's $24 million loan (2000) added approximately 400,000 of common shares to the denominator. For the years ended March 31, 2001 and 2000, additions to the numerator for Series B Preferred stock dividends and interest on convertible debt amounted to approximately $58,000 and $100,000, respectively.
The average number of outstanding shares used in computing basic and diluted net income per share was 14,306,011 and 14,419,601; 5,084,434 and 5,577,602; and 3,949,818 and 3,966,934 for the years ended March 31, 2001, 2000 and 1999, respectively. Net income per share reported on a quarterly basis does not add up to the per share amount for the year due to the weighting of a large stock transaction in the first quarter of fiscal 2001.
I. Risk Factors - The Company operates in an environment with many financial risks including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the continued ability to market drilling programs, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive nature of the industry as well as worldwide economic conditions.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
J. Accounting Estimates - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates used in calculating the Company's depletion, depreciation and amortization which could be subject to significant near term revision include estimated oil and gas reserves. The Company's reserve estimates could vary significantly depending on various factors, including Company and industry volatility of oil and natural gas prices.
K. Financial Instruments - The Company's financial instruments include cash and equivalents, accounts receivable, accounts payable and debt obligations. The book value of cash and equivalents, accounts receivable and accounts payable are considered to be representative of fair value because of the short maturity of these instruments. The Company believes that the carrying value of its borrowings under its bank credit facility and other debt obligations approximates their fair value as they bear interest at adjustable interest rates which change periodically to reflect market conditions. The Company's accounts receivable are concentrated in the oil and gas industry. The Company does not view such a concentration as an unusual credit risk and credit losses have historically been within management's estimate.
L. Reclassifications - Certain reclassifications were made to prior period financial statement presentations to conform with current period presentations.
NOTE 2. ACQUISITIONS
On March 17, 2000, the Company acquired Peake Energy, Inc. ("Peake") through a purchase of all of Peake's outstanding capital stock from Belden & Blake Corporation ("BBC"). Peake owns oil and gas properties consisting of approximately 1,900 wells and in excess of 900 miles of natural gas gathering lines in West Virginia, Kentucky and Virginia. The acquisition was consummated pursuant to a Stock Purchase Agreement dated March 17, 2000 between the Company and BBC, with an effective date of January 1, 2000.
The purchase price for the Peake stock was $69.7 million including approximately $100,000 of acquisition costs. The cash paid in connection with the Acquisition was obtained from loans from NUON International Projects b v ("NUON"), the Company's majority stockholder (see Note 4). The purchase price was determined through arm's-length negotiation between the Company and BBC and was based upon the Company's valuation of Peake's business and assets. There were no material relationships between the Company, its officers, directors or affiliates, and BBC or its officers, directors and affiliates. The acquisition cost was allocated to the net assets acquired based on estimated fair values and no goodwill was recorded. The estimated fair value of tangible assets and liabilities acquired was $71,817,000 and $2,113,000, respectively. The acquisition was accounted for as a purchase and, accordingly, the operating results related to the acquisition are included in the Company's consolidated results of operations from the closing date of March 17, 2000. Operations from the effective date to the closing date were considered a reduction of the purchase price. Peake subsequently changed its name to North Coast Energy Eastern, Inc.
Effective September 11, 1999, the Company acquired, for $3.5 million, the working interest and operations in approximately 220 producing wells, proved undeveloped locations and gas gathering systems from Environmental Exploration of North Canton, Ohio.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 2. ACQUISITIONS (CONTINUED)
Effective April 8, 1998, the Company acquired significantly all of the assets and operations and assumed certain liabilities of Kelt Ohio, Inc. ("Kelt"). The assets acquired from Kelt, an oil and gas producer headquartered in Cambridge, Ohio, included approximately 900 natural gas and oil wells, undeveloped acreage, brine disposal facilities, drilling and service rigs, and natural gas compressors and gas gathering systems. The $16.5 million acquisition cost was allocated to the net assets acquired based on estimated fair values and no goodwill was recorded. The estimated fair value of tangible assets and liabilities acquired was $17,488,876 and $1,000,000, respectively.
NOTE 3. DETAILS OF CURRENT LIABILITIES
Accrued expenses at March 31, 2001 include production taxes of $1.6 million, compensation of $1.2 million, property development costs of $1.0 million, interest of $.7 million and other expenses totalling $1.6 million.
Billings in excess of costs on uncompleted contracts consist of the following at March 31:
At March 31, 2001 and 2000, seven and four wells, respectively, were in the process of being completed.
NOTE 4. LONG-TERM DEBT
Long-term debt consists of the following at March 31:
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4. LONG-TERM DEBT (CONTINUED)
On March 17, 2000, in connection with the Peake acquisition, NUON loaned $72.5 million to the Company in the form of a $48.5 million Non-Negotiable Subordinated Promissory Note and a $24.0 million Non-Negotiable Subordinated Convertible Promissory Note. Interest on both notes is (was) payable semi-annually and accrues (accrued) at the six month LIBOR plus 2.3%. The principal amount of each note was originally payable on February 28, 2015. In May 2000, NUON converted the principal amount of the convertible note to shares of the Company's common stock based upon the exchange price of $2.50 per share. Both notes are (were) subordinated to the Company's senior debt. NUON has the right to secure the indebtedness by a lien on Peake's assets, subject to the rights of the senior lender. On September 26, 2000, the Company drew funds on its new credit facility and paid off its previous revolving loan and paid NUON $38.5 million on the Non-Negotiable Subordinated Promissory Note.
On September 26, 2000, the Company entered into a five year, $125,000,000 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 (presently $65,000,000 of which $57,000,000 is drawn upon) that is determined semiannually by the lenders based on the Company's financial position, oil and gas reserves and certain other factors. 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 $5,000,000 for the issuance of letters of credit. At March 31, 2001 and 2000, amounts outstanding under bank credit agreements bear interest at LIBOR plus 2% and 2.5%, or approximately 7.5% and 8.6%, respectively. The weighted average interest rate on bank borrowings was 8.7%, 8.4% and 8.3% for the years ended March 31, 2001, 2000 and 1999, respectively. Amounts borrowed 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. At March 31, 2001, the Company's credit 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 Company was in compliance with all covenants and restrictions at March 31, 2001.
Future maturities of long-term debt for the years ended March 31 are as follows:
2002 $ 557,400 2003 166,626 2004 - 2005 - 2006 57,000,000 Thereafter 10,000,000 ----------
$67,724,026 ===========
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.
The Company is exposed to market risk from changes in interest rates since it finances a portion of its operations through floating rate debt. The carrying amount of the Company's long-term debt approximates fair value, as all of the Company's significant debt instruments carry adjustable interest rates which change periodically to reflect market conditions.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. STOCKHOLDERS' EQUITY
A. Sale of Common Stock
In September 1997, the Company sold 1,149,426 shares of its common stock for $5 million to NUON, a limited liability company organized under the laws of the Netherlands, pursuant to the terms of a stock purchase agreement ("Agreement") by and between the Company and NUON dated August 1, 1997. In September 1999 and 1998, NUON exercised its option under the Agreement to purchase an additional 1,042,125 and 1,149,425 shares, respectively, of common stock at $4.35 per share. In September 1999, NUON purchased an additional 107,301 shares from the Company's former Chief Executive Officer. Additionally, in May 2000, NUON received 9,600,000 shares from conversion of its $24 million convertible promissory note. NUON, which owns 86% of the Company's common shares at March 31, 2001, has no further contractual rights or options to purchase shares.
B. Preferred Stock
The Board of Directors of NCE has designated 563,270 shares of the 2,000,000 shares of preferred stock authorized as Series A, 6% Noncumulative Convertible Preferred stock (Series A Preferred stock) and 625,000 shares of Preferred stock as Series B, Cumulative Convertible Preferred stock (Series B Preferred stock).
Stockholders of Series A Preferred stock are entitled to vote such shares on any and all matters submitted to a vote of the stockholders of the Company based upon the number of votes such stockholders would have if the Series A Preferred stock had been converted into shares of common stock of the Company. Holders of shares of Series A Preferred stock are entitled to receive, when and if declared by the Board of Directors, noncumulative cash dividends at an annual rate of $.60 per share. Shares of Series A Preferred stock are senior to shares of common stock with respect to such cash dividends and junior to shares of Series B Preferred stock.
Series A Preferred stock is convertible, at the stockholder's option, into shares of common stock at the conversion rate of .46 shares of common stock for each share of Series A Preferred stock converted.
All of, but not less than all, the outstanding shares of Series A Preferred stock shall, at the option of NCE, be converted into fully paid and nonassessable shares of common stock at the conversion price, upon the consummation of the sale of shares of common stock of NCE pursuant to an effective registration statement under the Securities Act of 1933, as amended; provided that such sale yields gross proceeds to the Corporation of not less than $5,000,000 and is made at a public offering price per share of not less than 1.5 times the conversion price in effect on such date.
In the case where NCE issues warrants or rights to purchase shares of common stock of the Company, each record holder of outstanding shares of Series A Preferred stock will receive the kind and amount of such warrants or rights so issued which such holder would have been entitled to upon such issuance had all of the holders of shares of Series A Preferred stock been converted, as defined.
The Series A Preferred stock is redeemable at the option of NCE at a price of $10 per share. NCE does not have any obligation to redeem the Series A Preferred stock.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. STOCKHOLDERS' EQUITY (CONTINUED)
B. Preferred Stock (Continued)
In the event of a voluntary or involuntary liquidation, dissolution or winding up of NCE, holders of the Series A Preferred stock are entitled to be paid $10 per share out of the assets of NCE but after payment of other indebtedness of NCE, after payment or distribution to the holders of Series B Preferred stock, but prior to any distribution to holders of the common stock.
Holders of shares of Series B Preferred stock are entitled to receive, when, as and if declared by the Board of Directors, cash dividends at an annual rate of $1.00 per share, payable quarterly.
In the event of any liquidation, dissolution or winding up of the Company, holders of shares of Series B Preferred stock are entitled to receive the liquidation preference of $10 per share, plus an amount equal to any accrued and unpaid dividends to the payment date, before any payment or distribution is made to the holders of common stock and Series A Preferred stock, as defined. After payment of the liquidation preference, the holders of such shares will not be entitled to any further participation in any distribution of assets by the Company.
Generally, each outstanding share of Series B Preferred stock has no vote, however in certain instances required by Delaware General Corporation Law or by the certificate of designation, each share will be entitled to one-fifth vote, excluding shares held by the Company or any entity controlled by the Company, which shares shall have no voting rights. So long as any Series B Preferred stock is outstanding, the Company cannot, without the affirmative vote of the holders of at least 66 2/3 percent of all outstanding shares of Series B Preferred stock, voting separately as a class, (i) amend, alter or repeal any provision of the Company's Restated Certificate of Incorporation or Bylaws so as to affect adversely the relative rights, preferences, qualifications, limitations or restrictions of the Series B Preferred stock, (ii) authorize or issue, or increase the authorized amount of, any additional class or series of stock of the Corporation, or any security convertible into stock of such class or series, having rights senior to the Series B Preferred stock as to dividends or liquidation, or (iii) effect any reclassification of the Series B Preferred stock. Additionally, the Series A Preferred stock's certificate of designation restricts the ability to significantly modify the Company's capital structure where such modification could be at a detriment to the Series B Preferred stockholders.
Whenever distributions on the Series B Preferred stock have not been paid, as defined, 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 to the Board of Directors, as defined. Such voting right will terminate when all such distributions accrued and in default have been paid in full or set apart for payment, as defined. The amount of dividends in arrears attributable to Series B Preferred is $326,010 ($1.40 per share) as of March 31, 2001.
Effective December 18, 1995, the Series B Preferred stock was redeemable at the option of the Company, at $10 per share plus any accrued and unpaid dividends, as defined.
There is no mandatory redemption or sinking fund obligation with respect to the Series B Preferred stock. In the event that the Company has failed to pay accrued dividends on the Series B Preferred stock, it may not redeem any of the outstanding shares of the Series B Preferred stock until all such accrued and unpaid distributions have been paid in full.
The holders of Series B Preferred stock have the right, exercisable at their option, to convert any or all of such shares into 1.311 (1.15 per share of Preferred stock plus .161 per share related to Preferred dividends in arrears at March 31, 2001) shares of common stock.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. STOCKHOLDERS' EQUITY (CONTINUED)
C. Common Stock Warrants
In fiscal 2000, 1999 and 1998, in conjunction with the NUON Agreement, the Company issued (each year) warrants to purchase 26,800 shares of common stock for $4.375 per share. These warrants (half of which were issued to a former director/officer) expire between September 2002 and September 2004.
Effective April 1999, in connection with the signing of a separation agreement, the Company's then Chief Executive Officer received a ten-year warrant to purchase, at $5.00 per share, 60,000 shares of the Company's common stock.
The Company granted Range Resources, a former shareholder of the Company, certain warrants to purchase 40,000 shares of common stock at $6.00 per share and 60,000 shares of common stock at $5.00 per share, as defined. These warrants were exercisable on June 13, 1995 and expired in the fiscal years ended March 31, 2001 and March 31, 1999, respectively.
D. Stock Options and Stock Appreciation Rights
On December 13, 1999, the shareholders of the Company approved the adoption of the North Coast Energy, Inc. 1999 Employee Stock Option Plan ("the Option Plan"). The Option Plan provides 400,000 shares of common stock reserved for the exercise of options granted under the plan. The Option Plan provides for the granting of stock options to purchase common stock at an option price determined by North Coast's Stock Option and Compensation Committee ("the Committee"). Options granted under the plan have been at or above the fair market value of the stock at the date of grant. The Committee determines the expiration date but no option shall be exercisable for a period of more than 10 years. The aggregate fair market value of the common stock exercisable for the first time during any calendar year can not exceed $100,000. Options granted under the Option Plan terminate upon, or within 90 days of the employee leaving the Company. The Company, from time to time, may issue additional options outside the plan. The Company's original stock option plan expired August 17, 1999.
Stock option transactions during 2001, 2000 and 1999 are summarized as follows:
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5. STOCKHOLDERS' EQUITY (CONTINUED)
D. Stock Options and Stock Appreciation Rights (Continued)
In the years ended March 31, 2000 and 1999, the Company granted 20,000 options to a Company director at $4.375 per share with one-third shares vesting on that date and one-third vesting each year after. In fiscal 2000, the Company granted 5,000 options to a Director/Officer of the Company, 3,429 options to an executive officer and another 2,286 options to a key employee.
In fiscal 2001, the Company granted 30,000 options to a Director of the Company with one-third shares vesting on April 1, 2001 and one-third vesting each year after and 30,000 options to an executive officer.
A summary of stock options outstanding and exercisable at March 31, 2001 follows:
Stock appreciation rights may be awarded by the Committee at the time or subsequent to the time of the granting of options. Stock appreciation rights awarded shall provide that the option holder shall have the right to receive an amount equal to 100% of the excess, if any, of the fair market value of the shares of common stock covered by the option over the option price payable, as defined. No stock appreciation rights have been awarded under the plan.
The Company has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock Based Compensation." Accordingly, no compensation cost has been recognized for the stock option plans. Had compensation cost for the Company's two stock option plans been determined based on the fair value at the grant date for awards in fiscal 2001, 2000 and 1999 consistent with the provisions of SFAS No. 123, the Company's net income per share would not change.
E. Stock Bonus Plan
The Company has a Key Employees Stock Bonus Plan ("the Bonus Plan") to provide key employees, as defined, with greater incentive to serve and promote the interests of the Company and its shareholders. The aggregate number of shares of common stock which may be issued as bonuses shall be 400,000 shares of common stock. The expenses of administering the Bonus Plan are borne by the Company. The Bonus Plan, as amended, terminates on February 1, 2011. The Company issued 3,470 shares of common stock related to the plan during fiscal 1999 and 25,120 shares of common stock since inception.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. INCOME TAXES
The Company accounts for income taxes under SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 is an asset and liability approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's consolidated financial statements or tax returns. The provision for income taxes consisted of the following:
Income taxes differed from the amount computed by applying the federal statutory rates to pretax book income as follows:
The components of the net deferred tax liability as of March 31, 2001 and 2000 were as follows:
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6. INCOME TAXES (CONTINUED)
As of March 31, 2001, the Company had operating loss, percentage depletion and alternative minimum tax credit carryforwards of approximately $4,000,000, $3,200,000 and $397,000, respectively. The operating loss carryforwards begin to expire in 2012. The percentage depletion and alternative minimum tax carryforwards can be carried forward indefinitely. Realization of these items is subject to certain limitations and is contingent upon future earnings. Additionally, a significant portion of the carryforwards may be subject to limitations imposed by Internal Revenue Code Section 382, which could further restrict the Company's utilization and realization of such carryforwards. Due to the uncertainty of the realization of certain tax carryforwards, the Company has established a valuation allowance against these carryforward benefits.
NOTE 7. PROFIT SHARING PLAN
The Company has a profit sharing plan that provides retirement and death benefits to participants and covers substantially all employees. Company contributions are discretionary and are allocated to the participants' accounts based upon their compensation and are subject to a graded vesting schedule which allows 20% vesting after two years of vesting service with an additional 20% vesting for each complete year of vesting service thereafter. Contributions of approximately $120,000, $75,000 and $50,000 were accrued or paid for the years ended March 31, 2001, 2000 and 1999, respectively. The Plan was amended effective April 1, 2000, to permit the immediate participation of individuals who are employed by Peake Energy, Inc. and to change the Plan's Trustee.
NCE provides no significant post-retirement and/or post-employment benefits other than the profit sharing plan discussed above.
NOTE 8. COMMITMENTS AND CONTINGENCIES
North Coast Energy, Inc., as general partner of several limited partnerships, has committed to fund certain costs (primarily tangible well costs and saleslines additions) of the partnerships as they are incurred. At March 31, 2001, management estimates the commitment to fund such costs to be approximately $643,000. The commitment has since been funded.
The Company shares in unlimited liability to third parties with respect to the operations of the partnerships it has sponsored and may be liable to limited partners for losses attributable to breach of fiduciary obligations. In certain partnerships, certain investors have participated as co-general partners in such partnerships. To make such investments more acceptable to potential investors (from a standpoint of risks to such investors), NCE has agreed to indemnify these investor-general partners from any partnership liability which they may incur in excess of their contributions.
NOTE 9. INDUSTRY SEGMENTS AND MAJOR CUSTOMERS
NCE and its subsidiaries operate in a single industry segment, the acquisition, exploration and development of oil and gas properties primarily in the Appalachian Basin. NCE and its subsidiaries both originate and acquire prospects and drill, or cause to be drilled, such prospects through joint drilling arrangements with other independent oil and gas companies or through limited partnerships sponsored by the Company.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9. INDUSTRY SEGMENTS AND MAJOR CUSTOMERS (CONTINUED)
The Company's revenue is derived from oil and gas production and oil and gas related activities in the Appalachian Basin. Gas production revenues represented 91%, 92% and 96% of total oil and gas production revenues for the years ended March 31, 2001, 2000 and 1999, respectively. During fiscal year 2001, two customers purchased 21% and 14% of the gas produced by the Company. During fiscal years 2000 and 1999, two customers purchased 22% and 19% and 52% and 13%, respectively, of the gas produced by the Company. A significant portion of trade accounts receivable at March 31, 2001 and 2000 was attributable to these purchasers.
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 lessen 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. As part of the financial instrument, NCE has supplied a letter of credit totalling $3.95 million to the purchaser of the Company's financial hedge as collateral for its mark to market exposure. 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. To lessen its exposure to commodity price risk, NCE expects to continue to sell natural gas under fixed price contracts, on the spot market and to use financial hedging instruments to realize a fixed price on a portion of its production The following table reflects the natural gas volumes and the weighted average prices under financial hedges and fixed price contracts at June 15, 2001:
NOTE 10. RELATED PARTY TRANSACTIONS
The Company believes that the terms of related party transactions are consistent with terms that could have been obtained from unaffiliated third parties.
Accounts receivable from affiliates consist primarily of receivables from the partnerships managed by the Company and are for administrative fees charged to the partnerships and to reimburse the Company for amounts paid on behalf of the partnerships. A large portion of the Company's revenues, other than oil and gas production revenue, is generated from or a result from the organization and management of oil and gas partnerships sponsored by the Company. During the years ended March 31, 2001 and 2000, the Company acquired limited partnership interests in oil and gas drilling programs that it had sponsored at a cost of approximately $676,000 and $90,000, respectively.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 11. ACCOUNTING STANDARDS
On October 1, 2000, the Company adopted the provisions of Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" ("SAB 101"). The adoption of SAB 101 did not have a material effect on the financial position or results of operations of the Company.
On April 1, 2001, the Company adopted Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" (as amended). SFAS 133 establishes accounting and reporting standards for hedging activities and derivative instruments, including certain derivative instruments embedded in other contracts.
The Company qualifies for special hedge accounting treatment under SFAS 133, whereby the fair value of the hedge is recorded in the balance sheet as either an asset or liability and changes in fair value are recognized in other comprehensive income until settled, when the resulting gains and losses are recorded in earnings. Any hedge ineffectiveness will be charged to earnings. The Company believes that any ineffectiveness of its hedges will be immaterial. The effect on earnings and other comprehensive income as a result of SFAS 133 will vary from period to period and will be dependent upon prevailing oil and gas prices, the volatility of forward prices for such commodities, the volumes of production the Company hedges and the time periods covered by such hedges. The Company expects to record a liability associated with its natural gas hedge based on gas prices in effect at April 1, 2001 of $3,200,000, with offsetting charges to deferred taxes of $1,100,000 and other comprehensive income of $2,100,000.
NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following supplemental unaudited oil and gas information is required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
The tables on the following pages set forth pertinent data with respect to the Company's oil and gas properties, all of which are located within the continental United States.
Property acquisition costs include purchases of proved and unproved oil and gas properties acquired in business acquisitions.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
Provision for income taxes was computed using the statutory tax rates for the years ended March 31, 2001, 2000 and 1999 and reflects permanent differences, including statutory depletion and the Partnership's results of operations for oil and gas producing activities that are reflected in the Company's consolidated income tax provision (credit) for the periods.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED)
Under the guidelines of SFAS No. 69, estimated future cash flows are determined based on year-end prices for crude oil, current allowable prices applicable to expected natural gas production (including transportation allowances), estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves based on current economic conditions, and the estimated future income tax expenses, based on year-end statutory tax rates (with consideration of true tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. Such cash flows are then discounted using a 10% rate.
The estimated quantities of proved oil and gas reserves and standardized measure of discounted future net cash flows include reserves from proved undeveloped acreage. The proved undeveloped acreage includes only the acreage directly offsetting locations to wells that have indicated commercial production in the objective formation and which NCE expects to drill in the near future using prices, operating costs and development costs expected in the area of interest. The quantities for fiscal 2001, 2000 and 1999 were reviewed by an independent petroleum engineering firm.
The methodology and assumptions used in calculating the standardized measure are those required by SFAS No. 69. It is not intended to be representative of the fair market value of the Company's proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves.