ITEM 1. BUSINESS.
GENERAL
North Coast Energy, Inc., a Delaware corporation ("North Coast" or the "Company"), is an independent natural gas and oil company engaged in exploration, development and production activities primarily in the Appalachian Basin. The Company's strategy focuses primarily on its acquisition of proved undeveloped properties and on the drilling and development of such properties. The Company develops these properties in conjunction with drilling programs ("Drilling Programs") which the Company sponsors and manages. The Drilling Programs are funded through the sale of partnership interests to investors and by contributions from the Company. The Company currently obtains an interest of approximately 20% in each Drilling Program for which it contributes (either in cash or in kind) organizational and tangible equipment costs and drill sites. As used in this Annual Report on Form 10-K, the terms "Company" and "North Coast" mean North Coast Energy, Inc., its subsidiaries and predecessors, unless the context otherwise requires.
As of March 31, 1998, the Company serves as the managing general partner of 27 Drilling Programs and operates 691 wells, 374 of which are operated for the Drilling Programs. In connection with the drilling and development of the wells it operates, North Coast currently owns approximately 202 miles of natural gas gathering pipelines which transport gas from 604 wells. At March 31, 1998, the Company had estimated net proved reserves of approximately 17.8 Bcf of natural gas and 135,700 barrels of oil.
The Company began operations in 1981 with the formation of its first Drilling Program. In 1987, the Company expanded its operations by acquiring Capital Oil & Gas, Inc. which also operated in the Appalachian Basin. In 1990, the Company acquired the assets and properties of 21 Drilling Programs which it had sponsored through an exchange offer (the "Exchange Offer") through which the Company issued publicly traded stock listed on NASDAQ. Subsequently, the Company has continued its original business strategy and now serves as the managing general partner of 27 Drilling Programs.
Subsidiaries. The Company's sole active subsidiary is NCE Securities, Inc. ("NCE Securities"), a member of the NASD and a broker dealer registered with the SEC and licensed in three states. NCE Securities' only business activity is the performance of its responsibilities as placement agent and, to a limited degree, the sale of partnership interests in North Coast sponsored Drilling Programs.
EXPLORATION AND DEVELOPMENT
Exploration and development activities conducted by the Company have involved the acquisition of proved undeveloped oil and gas properties and the drilling and development of such properties in conjunction with Drilling Programs and joint ventures. Management has chosen to sponsor limited partnerships and joint ventures to increase the funds available to the Company and enable it to engage in a greater number of drilling opportunities. In addition, the Drilling Programs add to the Company's reserves and produce additional sources of income for the Company, including revenues from serving as general contractor for drilling operations, management services, oilfield service operations, and gas-gathering and marketing services which are provided to the Drilling Programs.
The Company's strategy focuses on increasing its natural gas and oil reserves, as well as production, drilling and oil field service revenues, by acquiring undeveloped oil and gas properties in the Appalachian Basin and financing and conducting the drilling and development of these properties in conjunction with the Drilling Programs. While the Company is pursuing its strategy of increasing reserves through drilling and development in conjunction with the Drilling Programs, it continues to review potential acquisitions, including other gas and oil companies or partnerships and producing properties.
AREAS OF OPERATION
The Appalachian 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 Appalachian 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 Appalachian 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. Historically, most production in the Appalachian 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 as long-lived reserves that produce for more than 20 years.
To date, the Company's drilling operations in the Appalachian Basin have principally involved drilling to the Clinton/Medina sandstone geologic formation. This formation is an oil and gas bearing sandstone formation, which underlies a large section 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 drills in this area have estimated depths of between 3,500 and 6,700 feet. The Clinton/Medina formation is generally characterized by low permeability (the ability of gas and oil bearing rock to flow gas and oil) and low porosity (capacity of rock to hold oil and gas). Generally, in a productive well, both oil and gas initially are produced at rates that rapidly decline after the first one or two years. Although Clinton/Medina wells generally produce for many years, a substantial portion of the total well production can be expected within the first several years of full production.
Certain of the Company's leaseholds are in the Upper Devonian age sandstone geological formations of Washington, Warren, McKean, Potter and Clearfield counties in Pennsylvania, which are a series of oil and gas bearing sands underlying eastern Ohio, western Pennsylvania and northern West Virginia. The Balltown, Cooper, and Bradford Sandstone's, among others, are sandstone formations of Upper Devonian age. Common productive depths range between approximately 1,000 feet and 5,000 feet. The Company's target zones typically range from 1,600 feet to 4,500 feet in depth. Historically, Upper Devonian wells generally have long production lives, and many wells drilled in these formations near the turn of the century are still in production.
The Company also maintains leasehold acreage in portions of Pennsylvania and West Virginia with other potential producing formations. Although there are variances in the nature and characteristics of these producing formations, they are generally typical of the Appalachian area.
ACQUISITION OF PROPERTIES
North Coast 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 in consideration of 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. After obtaining these drilling rights, the Company continues to evaluate the properties for potential drilling. Substantially all of the Company's drilling operations are currently conducted in conjunction with the Drilling Programs. If a prospect is selected for drilling through a Drilling Program, the Company assigns the minimum required acreage for a well to such entity. In such a case, the Company retains the balance of the leasehold acreage for future drilling.
In 1994, the Company acquired certain oil and gas interests in Erie and Crawford Counties in northwestern Pennsylvania previously owned by a private company. These properties included the entire working interest in 163 producing wells, 43 miles of gas gathering lines and additional drilling locations.
In 1998, the Company acquired certain oil and gas interests and operations in 28 wells in Ohio and Pennsylvania previously owned by an employee of the Company and also acquired seven wells and a gathering
system from Lomak Petroleum, an affiliate of the Company. The Company also acquired additional interests in certain of its older Drilling Programs by offering to its investors an exit strategy from the Drilling Programs. The Company currently structures the agreements with the Drilling Programs such that the investor may present their interest to the Company for purchase on a predetermined pricing formula after a five-year holding period.
The Company intends to continue to review potential acquisitions of oil and gas properties, but had no commitment with respect to any material acquisition at March 31, 1998.
DRILLING PROGRAMS
From the Company's inception in 1981 through March 31, 1998, North Coast has sponsored 48 Drilling Programs to engage in oil and gas drilling and development operations. Public Drilling Programs accounted for seven of these programs, while 41 were sold through private placements. Twenty-one of the twenty-two partnerships were dissolved as a result of the Exchange Offer and, the Company currently is managing 27 Drilling Programs.
Each Drilling Program has been conducted as a separate limited partnership with the Company serving as managing general partner of each. To maintain the marketability of its Drilling Programs, the Company continually reviews program structure and performance and makes modifications from program to program, as it deems appropriate. These modifications have included changes to the compensation arrangements between the Company and the Drilling Programs, including charges for its drilling and administrative services, and changes in the Company's interest in the 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 for producing well operations. In the Drilling Programs, typically the entire working interest in the leasehold is acquired by the program, although only the minimum required acreage for a well is assigned by the Company to the Drilling Program.
As managing general partner, North Coast is subject to full liability for the obligations of the Drilling Programs although it is indemnified by each program to the extent of the assets of the Drilling Programs 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.
Typically, each Drilling Program is structured as a "functional allocation" program whereby the non-industry investors contribute cash in an aggregate amount equal to the intangible drilling and development costs to be incurred for the Drilling Program's wells. The Company contributes the drill sites to the Drilling Program and agrees to contribute all tangible equipment necessary to drill, complete and produce each well, as well as organizational and syndication costs of the Drilling Program. The allocation of partnership revenues in each Drilling Program may vary depending upon the structure chosen by the Company, with the Company's percentage interest ranging from 20% to 40%.
Interests in North Coast's Drilling Programs are sold to investors through securities dealers registered with the NASD. In each program, NCE Securities, Inc., acts as placement agent and enters into selling agreements with a number of broker-dealers to assist it in selling the interests.
The Drilling Programs raised $6.5 million during fiscal 1996, $3.0 million during fiscal 1997 and $2.7 million during fiscal 1998 from investors. The Company attributes these decreases to the uncertainties related to natural gas prices and the purchase of approximately 47% of the Company's voting stock outstanding on September 4, 1996 by Lomak Petroleum, Inc. ("Lomak"). The Company intends to continue its efforts to market its Drilling Programs and increase the number of wells drilled and operated. If these efforts are unsuccessful, the Company would anticipate seeking alternatives including joint ventures with industry partners and the financing of drilling activity through internal cash flow and other financing alternatives.
DRILLING SERVICES
The Company enters into turnkey contracts with the Drilling Programs to drill program wells. Pursuant to these drilling contracts, the Company is responsible for the drilling and development of the wells. The Company subcontracts with third parties for the performance of a substantial portion of the operations required to drill, complete and equip these wells for production. Although the Company manages and supervises all necessary drilling and related service and equipment operations on these wells, there are a number of third party services to obtain, including contract drilling, fracturing, logging and pipeline construction which are performed by subcontractors who specialize in those operations. Since the Company contracts with the Drilling Programs on a turnkey (fixed price) basis, the Company is responsible for drilling and completing the wells, regardless of the actual cost. Consequently, the Company is subject to the risk that prices incurred in the actual drilling and development operations could increase beyond its contract price thereby rendering its drilling contracts less profitable or unprofitable. Moreover, difficulties encountered in drilling and completion operations can substantially increase costs sometimes without recourse for the Company. The Company continually monitors the cost incurred in drilling, completion and production operations and reviews its turnkey contract prices for each Drilling Program in order to reduce the risk of unprofitable drilling operations. These turnkey drilling prices are subject to change based on competition, the return sought by Drilling Programs investors, the Company's revenue and profit considerations and other industry conditions.
OIL FIELD SERVICE OPERATIONS
As of March 31, 1998, the Company operated 691 wells, all of which were located in Ohio and Pennsylvania. As 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 and also subcontracts certain oil field operations.
The Company receives a monthly operating fee for each producing well it operates and is reimbursed for most third party costs associated with operations and production of the wells. The Drilling Programs each pay the Company their specified operating fee based upon the investors' aggregate interest in the Drilling Program wells, exclusive of the Company's ownership interest.
GAS-GATHERING ACTIVITIES
In connection with the drilling and development of the wells that it operates, the Company has constructed and owns approximately 202 miles of natural gas-gathering pipelines in various counties throughout eastern Ohio and western Pennsylvania. These pipelines carry natural gas from the wellhead to the gas transmission systems of various utilities for sale to such utilities, to natural gas brokers purchasing gas for resale to others or to industrial purchasers pursuant to self-help gas purchase arrangements. These systems gathered gas from 604 wells as of March 31, 1998. The Company continues its construction of new pipelines and the establishment of compressor facilities in order to expand the number of purchasers available to the Company.
For such gas-gathering services, the Company collects certain allowances from public utilities, end-users or other natural gas purchasers (including natural gas brokers). These gathering fees or transportation allowances averaged approximately $.20 per Mcf of natural gas at March 31, 1998.
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.
Customers of the Company purchasing natural gas include marketing affiliates of the major pipeline companies, natural gas marketing companies, and a variety of commercial/public authorities, industrial, and institutional end users who ultimately consume the gas. 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.
As discussed, the deliverability and price of natural gas are subject to both governmental regulation and supply/demand forces. During the past several years' regional surplus and shortage of natural gas situations have occurred, resulting in wide fluctuations in the prices achieved.
The lengths of the contracts as defined in the "Term" provision in the Company's gas purchase agreements vary widely. Additionally, several of the Company's contracts provide for monthly pricing which are derived from published NYMEX or Appalachian price indexes. The Columbia Transmission (TCO) and Consolidated Natural Gas (CNG) Index prices, which create a basis for spot sales prices in the Mid Atlantic and northeastern United States, ranged from $2.00 to $3.59 per Mcf during fiscal 1998. As of March 31, 1998, approximately one-third of the Company's natural gas contracts are fixed price contracts with industrial end-users. The prices received from these contracts range between $1.97 and $4.43 per Mcf, with one-half of these contracts being committed for less than one year. The remainder of the Company's natural gas contracts are with utilities and marketers. Approximately 90% of the wells operated by the Company, which produce gas to fulfill the contractual obligations to utilities and marketers during the summer months, contain fixed prices ranging from $1.75 to $3.15 per Mcf. In addition, one-third of these wells contain market sensitive provisions during the winter months. The range of Appalachian unit pricing during the winter of 1997/1998 was from $2.12 to $3.59 per Mcf. For the twelve months ended March 31, 1998, the Company received an average price of $2.50 per Mcf of gas sold.
Due to the seasonal supply and demand market pressures, prices paid by purchasers will continue to fluctuate for the next several years. The Company has pursued a strategy of varying the length and pricing provisions of its gas purchase contracts so as to maintain flexibility to react to those fluctuating prices. Due to rising market conditions, the duration of recently renegotiated fixed price contracts has been limited to a year or less. Should market trends change, the Company will endeavor to commit a larger portion of its natural gas to longer-term arrangements to optimize revenues derived from these sales.
During the past several years, an over abundance 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. It is likely that supply and demand factors will continue to be the driving force in the evolving marketplace.
Crude Oil. Oil produced from the Company's properties is generally sold at the prevailing field price to one or more of a number of 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 $16.18 per barrel for its oil during fiscal 1998; however, during the last several years prices paid for crude oil have fluctuated substantially. The price posted for purchase contracts for the sale of oil at March 31, 1998 was $13.25. 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. To the extent that the prices, which the Company receives for its crude oil, decline from current levels, revenues from oil production will be reduced accordingly.
COMPETITION
The gas and oil industry is highly competitive in all phases. The Company encounters strong competition from other independent oil companies in acquiring economically desirable properties as well as in marketing production therefrom and obtaining external financing. Many of the Company's competitors may have financial resources, personnel and facilities substantially greater than those of the Company.
REGULATION
Exploration and Production. The exploration, production and sale of natural gas and oil are subject to various types of 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 salt water 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 $1,000,000 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 addition, FERC recently has proposed several rules or orders concerning transportation and marketing of natural gas. The impact of these rules and other regulatory developments on the Company cannot be predicted.
In 1992, the Federal Energy Regulatory Commission (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 North Coast is not an interstate pipeline, the Company believes the changes brought about by Order 636 have increased competition in the marketplace, resulting in greater market volatility.
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.
EMPLOYEES
At March 31, 1998, the Company had 40 employees, including 15 field employees. No employees are represented by a union and the Company believes that it maintains good relations with its employees.
FORWARD-LOOKING STATEMENTS.
This Annual Report on Form 10-K contains forward-looking statements that involve risks and uncertainties. The Company's actual results may differ significantly from the results discussed in the forward-looking statements. Factors that may cause such a difference include, but are not limited to, the competition within the oil and gas industry, the price of oil and gas in the Appalachian Basin area, the weather in the Company's geographic region, possible acquisitions by the Company, the cost of the locating and drilling oil and gas wells in the Appalachian Basin area, the amount of funds raised in the fiscal 1999 Drilling Programs, and the ability to locate productive oil and gas prospects for development by the Company.
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 affect the Company's working interests (net wells) in its properties and 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, 1998.
RESERVES
Production. The following table summarizes the net oil and gas production (on a rounded basis), average
sales prices, and average production (operating) expenses per equivalent unit of production for the periods indicated.
PRODUCTION
(1) For calculation of average operating cost per equivalent Mcf, the standard ratio of 6:1 for gas to oil was used.
(2) Includes costs of the Company's enhancement program and rework of two wells in the Gulf Coast area of interest.
(3) 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, 1998. Wells are classified as gas or oil according to their predominant product stream.
PRODUCTIVE WELLS
(1) Gross wells include 18 wells in which the Company owns only 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, 1998.
LEASEHOLD ACREAGE
Total Leasehold Acreage:
Gross Acres 69,500 Net Acres 34,700
Developed Acreage:
Gross Acres 39,400 Net Acres 19,700
Proved Undeveloped Acreage:
Gross Acres 1,300 Net Acres 700
Drilling Activity. 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 thereby.
All wells were drilled by March 31st of their respective years and are reflected in the Drilling Activities table. Wells in which the Company owns only a royalty interest are not reflected in the table below.
DRILLING ACTIVITIES
Fiscal year ended March 31, - ---------------------------
(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 1998 includes two gross and net wells as productive development wells that are awaiting pipeline connection or well completion operations at March 31, 1998.
(4) Total Wells is the sum of the Exploratory and Development Wells.
FACILITIES
The Company owns a 12,000 square foot building, its corporate headquarters, in Twinsburg, Ohio. The office facility is in a centralized location, which during fiscal 1997 allowed the Company to relocate certain operations and its personnel from its Cleveland and Youngstown offices. The Youngstown facility owned by the Company is used for field operations.
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, 1998, 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 Small Cap Market under the symbol "NCEB". The following tables sets forth, for the fiscal periods indicated the high and low bid and ask prices for the Common Stock.
Common Stock (Amounts rounded to the nearest 32nd)
As of June 22, 1998, there were approximately 16,617,881 shares of Common Stock outstanding, which were held by approximately 1,300 holders of record.
Holders of Series A Preferred Stock (convertible to 2.3 shares of Common Stock) are entitled to receive semi-annual non-cumulative cash dividends at an annual rate of $.60 per share. Such dividends are payable on June 1 and December 1 of each year. The holders of Series B Preferred Stock (currently convertible to 6.47 shares of Common Stock) are entitled to receive quarterly cumulative cash dividends at an annual rate of $1.00 per share. For the year ended March 31, 1998, the Company paid $67,066 in aggregate cash dividends on its Series B Preferred Stock.
Whenever distributions 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 of payment. The Company has dividends in arrears on its Series B Preferred Stock of $335,330 at March 31, 1998.
The Company has never paid any cash dividends on its Common Stock and is currently restricted from paying cash dividends on any of its capital stock under the terms of its reducing revolving 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 ended March 31, 1994, 1995, 1996, 1997 and 1998.
(1) Net Income (Loss) per share has been restated to reflect stock dividends.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
OVERVIEW
The Company is engaged in the exploration, development and production of natural gas and oil, primarily in conjunction with the Drilling Programs it sponsors and manages. The Company derives its revenues from its own oil and gas production and turnkey drilling, well operations, gas gathering, transportation and gas marketing services performed under contract with the Drilling Programs.
Since inception, the Company has raised approximately $84,000,000 from the sale of partnership interests, which has resulted in the formation of 48 partnerships.
Several factors may affect the amount of the Company's revenues with respect to the activities of the Drilling Programs. The amount of funds raised by each Drilling Program determines the number of wells for which the Company receives drilling revenues. The Company continually monitors the cost incurred in drilling, completion and production operations and reviews its turnkey contract prices for each Drilling Program in order to reduce the risk of unprofitable drilling operations to the Company and the economic considerations of the investors in the Drilling Programs. The turnkey drilling contract price between the Drilling Programs and the Company may vary among Drilling Programs depending on competition and other cost factors and the returns sought by investors in the Drilling Programs. The Company's capital availability, as well as revenue and profit considerations, may result in the Company changing its percentage interest ownership in future Drilling Programs.
The Company's growth depends on a number of factors, including its continued ability to raise Drilling Program funds from non-industry investors to increase the number of wells from which the Company will receive production, contract drilling and service-related revenues and the Company's ability to maintain adequate liquidity to provide its contributions to new Drilling Programs and to acquire additional proved undeveloped or proved producing properties. The Company's growth is also dependent on several external factors, including the price at which gas, and to a lesser extent oil, can be found and sold.
The Company's proved developed natural gas reserves increased to 15 Bcf for fiscal 1998 from 14.5 Bcf for fiscal 1997 while proved developed oil reserves increased to 126,700 barrels from 120,200 barrels, respectively. The increase in proved developed natural gas reserves resulted from the purchase of partnership interests from certain of the Company's Drilling Program investors and working interests in certain wells from unrelated parties coupled with upward revisions of the gas reserves of the Company's existing wells. The proved gas reserves (developed and undeveloped) increased to 17.8 Bcf for fiscal 1998 from 17 Bcf for fiscal 1997. The increase in proved gas reserves was due to the increases mentioned previously for the proved developed reserves coupled with the upward revision to
the proved undeveloped reserves for drilling locations that were proved through the Company's recent drilling programs. Proved oil reserves (developed and undeveloped) increased to 135,700 barrels at March 31, 1998 from 120,200 barrels at March 31, 1997 due primarily to the upward revision of 26,400 barrels for fiscal 1998. The Company recognizes as proved undeveloped reserves the potential oil and gas which can reasonably be expected to be recovered from drillable locations which the Company owned (or had rights to) at fiscal year end which are offsetting locations to wells that have indicated commercial production in the objective formation and which the Company fully expects to drill in the very near future. Changes in the Standardized Measure of Discounted Future Net Cash Flows are set forth in Note 11 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 85% are proved developed and approximately 15% are proved undeveloped based upon equivalent unit Mcfs. Proved undeveloped acreage requires considerable capital expenditures to develop. Management of the Company 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, 1996, 1997 and 1998. All items in the table are calculated as a percentage of total revenues.
The following discussion and analysis reviews the results of operations and financial condition for the Company for the years ended March 31, 1996 1997 and 1998. This review should be read in conjunction with the Financial Statements and other financial data presented elsewhere herein.
COMPARISON OF FISCAL 1998 TO FISCAL 1997
REVENUES
Oil and gas production revenues decreased $123,627 (4%) to $3,013,929 for fiscal 1998 compared to $3,137,556 for the prior corresponding period. The decrease in oil and gas production revenues was a result of a decrease in oil revenues of approximately $110,000 due to a decrease in the oil production and in the average price received for oil by the Company between comparable periods. For fiscal 1998 the Company received an average price of $16.18 per barrel of oil and $2.50 per Mcf of natural gas compared to an average price of $20.65 per barrel of oil and $2.43 per Mcf of natural gas received during fiscal 1997.
Drilling Revenues for the period decreased by $795,259 (21%) for fiscal 1998 compared to fiscal 1997 due to the decrease in the number of wells recognized in revenue. The Company recognized revenues for fiscal 1998 on 20 wells as compared to 29 wells for fiscal 1997. The decrease in the number of wells recognized in drilling revenues was primarily due to the higher number of carryover wells at the end of fiscal 1996 compared to fiscal 1997. The Company has two wells in work-in-progress at fiscal year ended 1998 compared to five at fiscal year ended 1997.
Revenues generated from well operating, transportation and other decreased $237,198 (13%) for fiscal 1998 compared to fiscal 1997. This decrease was primarily due to a decrease in unaffiliated third party gas sales. The unaffiliated third party gas sales fluctuate from year to year based upon the availability of these types of transactions.
Revenue from administrative and agency fees, which are based on a percentage of the total investor capital raised in all of the Drilling Programs, increased by $81,727 (9%) for fiscal 1998 compared to fiscal 1997 due to the formation of the Drilling Programs in fiscal 1998. The administrative fees derived from the fiscal 1998 Drilling Programs were charged a rate equal to 4.5% of total capital raised compared to the prior years programs which are charged an annual fee equal to 2% of total capital raised.
EXPENSES
Oil and gas production expense increased $63,183 (8%) for fiscal 1998 as compared to fiscal 1997. This increase was primarily due to additional costs incurred with relocation of certain production facilities in the Gulf Coast area and costs associated with reworking wells in Pennsylvania.
Drilling costs for fiscal 1998 compared to fiscal 1997 decreased $360,027 (13%) due to the decreased number of wells completed between comparable periods. The profit margin on drilling revenue decreased to 16% for fiscal 1998 compared to 24% for fiscal 1997. The decrease in the drilling profit margin between comparable periods was due to actual completion costs over the estimated accruals from wells recognized in drilling income coupled with increased general and administrative costs allocated to drilling activities. Net drilling income decreased approximately $435,000 between fiscal year ends due to the fewer number of wells drilled and completed.
Oil and gas operations expense decreased $324,271 (33%) for fiscal 1998 as compared to fiscal 1997. This decrease was primarily due to reduced natural gas purchases associated with unaffiliated third party gas sales.
Interest expense decreased to $839,342 for fiscal 1998 from $1,055,409 for fiscal 1997. This decrease was primarily due to the reduction of the borrowings under the Company's Credit Facility and other debt by utilizing funds received from the sale of common stock. At March 31, 1998, $6,565,265 was outstanding under the Company's Credit Facility, as compared to $8,640,000 at March 31, 1997.
Net income was $262,138 for fiscal 1998 compared to $291,750 for fiscal 1997. The decrease reflects the decreased drilling activity and production revenues between comparable periods.
COMPARISON OF FISCAL 1997 TO FISCAL 1996
REVENUES
Oil and gas production revenues increased $288,946 (10%) to $3,137,556 for fiscal 1997 compared to $2,848,610 for the prior corresponding period. Oil and gas production was relatively constant between years. The increase in production revenues was primarily attributable to an average increase in gas prices of 8.5% and an increase of oil prices of 21%. For fiscal 1997 the Company received an average price of $20.65 per barrel of oil and $2.43 per Mcf of natural gas compared to an average price of $17.01 per barrel of oil and $2.24 per Mcf of natural gas received during fiscal 1996.
Drilling Revenues for the period decreased by $1,706,734 (31%) for fiscal 1997 compared to fiscal 1996 due to the decrease in the number of wells recognized in revenue. The Company recognized revenues for fiscal 1997 on 29 wells as compared to 45 wells for fiscal 1996. The decrease in the number of wells recognized in drilling revenues was due to the decrease of $3,444,500 in the amount of funds raised in the fiscal 1997 Drilling Programs of $3,015,500 as compared to $6,460,000 for the fiscal 1996 Drilling Programs. Management of the Company believes that this reduction was caused by the uncertainties arising from the purchase of North Coast common stock by Lomak, a stockholder of the Company. The Company had five wells in work-in-progress at year ended 1997 compared to 14 at year ended 1996.
Revenues generated from well operating, transportation and other increased $249,337 (15%) for fiscal 1997 compared to fiscal 1996. This increase was primarily due to an increase in unaffiliated third party gas sales. The unaffiliated third party gas sales fluctuate from year to year based upon the availability of these types of transactions and Company resources available. The increase was also due to increases in well operating revenue and compression revenue from the Company's five compressor stations.
EXPENSES
Drilling costs for fiscal 1997 compared to fiscal 1996 decreased $1,284,173 (31%) due to the decreased number of wells completed between comparable periods. The gross profit margin was 24% for both fiscal periods presented. Net drilling income decreased approximately $423,000 between fiscal year ends due to the fewer number of wells drilled and completed.
Oil and gas operations expense increased $95,918 (11%) for fiscal 1997 as compared to fiscal 1996. This increase was primarily due to the increase in gas purchases related to unaffiliated third party gas sales as discussed above.
General and administrative expenses decreased $570,768 (20%) for fiscal 1997 compared with fiscal 1996 despite incurring $311,000 in expenses associated with the litigation with Lomak and the Company's offer to convert its Preferred stock. The Lomak litigation was settled on November 12, 1996. This decrease in general and administrative expenses was primarily due to costs savings derived from reduced salaries and employee benefits when the Company reduced the size of its staff. In addition, the staff reductions resulted in certain changes in job responsibility resulting in additional general and administrative costs being allocated to production expense and oil and gas operations.
Depreciation, depletion, amortization, impairment and other decreased $1,912,789 (58%) for fiscal 1997 compared to fiscal 1996. This decrease was primarily due to the implementation of the Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" during fiscal 1996 which resulted in an impairment of $1,561,776 for fiscal 1996 without a corresponding impairment for 1997. In addition, the adoption of SFAS #121 resulted in a decreased basis of existing properties being depleted for future periods.
Interest expense increased to $1,055,409 for fiscal 1997 from $772,731 for fiscal 1996. This increase was primarily due to the Company's additional borrowings on its reducing revolving credit facility. At March 31, 1997, $8,640,000 was outstanding under the Company's Credit Facility compared to $7,560,000 at March 31, 1996.
Operating income for the fiscal year ended 1997 increased $2,482,650 to $1,267,176 compared to an operating loss of $1,215,474 for the fiscal year ended 1996. Net income increased $1,546,168 for fiscal 1997 to $291,750 as compared to a net loss of $1,254,418 for fiscal 1996. These increases in operating income and net income are primarily due to the decrease in general and administrative expenses, depreciation, depletion, amortization, impairment and other as well as increases in oil and gas production and well operating, transportation and other.
INFLATION AND CHANGES IN PRICES
While the costs of operations have been and will continue to be affected by inflation, oil and gas prices have fluctuated during recent years and generally have not followed the same pattern as inflation. With today's global economy, especially in the area of oil and natural gas, Management believes that other forces of the economy and world events, such as OPEC, the weather, economic factors, and the effects of supply of natural gas in the United States and regionally have a more immediate effect on current pricing than inflation. The Company received an average price of $16.18 and $20.65 per barrel for fiscal 1998 and 1997, respectively, and $2.50 and $2.43 per Mcf for natural gas for fiscal 1998 and 1997, respectively. On average, Appalachian natural gas prices decreased $0.30/Mcf from fiscal year 1997 to fiscal year 1998. However, the Company experienced a $0.07/Mcf increase for its natural gas during this period. The increase the Company received can be attributed to a change in marketing strategy including (1) aggressively targeting small to medium-sized commercial end-users, (2) balancing the remainder of the Company's gas prices between spot Appalachian based prices and Nymex based prices. This strategy allows the Company the greatest opportunity to exceed the average regional prices, while minimizing the effects of a negative fluctuation. The industry-wide weakness of natural gas prices can be attributed to the effects of El Nino. Most of the country experienced a relatively mild winter, which lessened demand for natural gas. Although it is anticipated that there will be a decline in gas prices during the summer months, the demand for gas by storage facilities, coupled with the anticipated nationwide hot summer, may keep gas prices above last summer's. Other variables potentially effecting gas prices are increased competition from Canadian gas, effects of gas storage and possibly Federal Energy Regulatory Commission ("FERC") Order 636. The FERC Order may have contributed to the lower spot market prices by mandating an unbundling of pipeline service and allowing open access to a variety of geographical markets. Management cannot predict what long-term effects FERC Order 636 will have on either spot market prices or longer term gas contracts.
Currently, the Company sells natural gas under both fixed price contracts and on the spot market. The spot market price the Company receives for gas production is related to several variables, including the weather and the effects of gas storage. The Company anticipates that spot market prices will continue to fluctuate in response to various factors, primarily weather and market conditions.
In an effort to position itself to take advantage of future increases in demand for natural gas, the Company continues to construct new pipeline systems in the Appalachian Basin and to contract with other pipeline systems in the region to transport natural gas production from Company wells.
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital was $782,000 at March 31, 1998 compared to $325,000 at March 31, 1997. The increase of $457,000 in working capital from March 31, 1997 reflects the Company's improved cash position from the sale of 5 million shares of Common Stock on September 4, 1997. As of March 31, 1998, the Company had $6,565,265 outstanding under its Credit Facility. North Coast's current ratio was 1.32 to 1.0 at March 31, 1998 and 1.11 to 1.0 at March 31, 1997.
The following table summarizes the Company's financial position at March 31, 1997 and 1998:
CAPITAL RESOURCES AND REQUIREMENTS
The oil and gas exploration and development activities of North Coast 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, 1996, 1997 and 1998:
(1) All items in the previous table are calculated as a percentage of total cash sources. Total cash sources include the following items, if positive: cash flow from operations before working capital changes, changes in working capital, net cash provided by investing activities and net cash provided by financing activities, plus any decrease in cash and cash equivalents.
As the above table indicates, the Company's cash flow provided by operating activities remained relatively constant at $1,176,000 for fiscal 1998 compared to $1,162,000 for fiscal 1997.
Net cash used for investing activities increased from $1,827,000 (76% of cash sources) for fiscal 1997 to $2,122,000 (81% of cash sources) for fiscal 1998. The increase of only $295,000 reflects the corporate building purchased during fiscal 1997. During fiscal 1998 the Company purchased additional interests in certain of its older Drilling Programs, purchased interests and operations in 35 wells, and continued to purchase tangible equipment to fulfill its obligations to the partnerships it sponsors.
Net cash provided by financing activities increased by $406,000 from fiscal 1997 to fiscal 1998. This increase reflects the sale of $5,000,000 of Common Stock, reduced dividends paid on the Preferred Stock, the repayment of loans to Lomak Petroleum, Inc. and the reduction of borrowings under the credit facility.
On February 9, 1998, the Company entered an agreement ("Credit Agreement") with ING (US) Capital Corporation to replace the $20,000,000 revolving credit facility ("Credit Facility") with its previous lender. The Credit Agreement provides for a borrowing base which is determined semiannually by the lender based upon the Company's financial position, oil and gas reserves, as well as outstanding letters of credit ($290,000 at March 31, 1998), as defined. The Credit Agreement requires payment of an agent fee (0.75% for Credit Agreement) on amounts available and 1/2% commitment fee on amounts not borrowed up to the available line. At March 31, 1998, the Company's borrowing base was $10,000,000 subject to reduction for the outstanding letters of credit. Available borrowings under the facility at March 31, 1998 were $3,144,735 and may subsequently change based upon the semiannual reserve study and borrowing base determination (see Note 4 to the Company's March 31, 1998 financial statements). The Credit Facility provides that the payment of dividends with respect to the Common Stock of the Company is prohibited. As of March 31, 1998, the Company had $6,565,265 outstanding under the Credit Facility, and was in compliance with its loan covenants. Amounts borrowed under the Credit Facility bear interest at the prime rate of the lending bank plus 1% or LIBOR plus 2.75%. The revolving line of credit is reviewed semi-annually and extended by an amendment to the current facility or converted to a term loan on July 1, 1999.
The amounts borrowed under its reducing revolving line of credit 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 mortgage notes are secured by certain land and buildings.
In addition, at March 31, 1998, the Company had approximately $52,571 outstanding under a mortgage note payable. The mortgage note bears interest at the rate of 8% and requires the Company to make monthly payments of approximately $1,019 through July 2003. The Company purchased a building for its headquarters and entered a mortgage note on May 13, 1996 for $540,000 over a 15-year term with an interest rate of 8.58% to be renegotiated every five years. The amount outstanding under the mortgage note at March 31, 1998 was $507,404.
On September 4, 1997 the Company sold 5,747,127 shares of its Common Stock for $5 million to NUON International bv, a limited liability company organized under the laws of the Netherlands ("NUON"), pursuant to the terms of a stock purchase agreement ("Agreement") by and between the Company and NUON dated August 1, 1997. The Company also issued 134,000 warrants representing the right of the holder to purchase one share of Common Stock for $0.875 per share in connection with the sale of Common Stock to NUON. Pursuant to the terms of the Agreement and subject to the satisfaction of certain conditions, including the development of a plan of complementary business, NUON may purchase an additional 5,747,127 shares of Common Stock by each of September 30, 1998 and September 30, 1999. The Company is also obligated to issue 134,000 warrants on each occasion NUON purchases an additional 5,747,127 shares. The additional warrants represent the right to purchase one share of Common Stock for $0.875 per share.
A portion of the proceeds from the sale of Common Stock was utilized to repay existing subordinated indebtedness in the amount of $1,475,537 plus interest of $50,506 owed to Lomak with the remaining proceeds used for working capital and to reduce the amount outstanding under the Company's Credit Facility.
Subsequent to March 31, 1998, the Company acquired certain assets and assumed certain obligations of Kelt Ohio, Inc., headquartered in Cambridge, Ohio. The acquisition was made pursuant to a Purchase and Sale Agreement dated April 8, 1998 as amended May 12, 1998. The purchase price for the acquired assets was approximately $16 million. The acquired assets include approximately 900 natural gas and oil wells and Kelt's brine disposal facilities, drilling and service rigs, natural gas compressors and gas gathering systems, and a large inventory of oilfield service equipment and supplies. The Company funded the acquisition using cash and an increase in its existing line of credit. Approximately $15 million of the total purchase price was financed under a recently expanded credit facility with the remaining amount paid in cash. An amended credit facility dated May 29, 1998 expands the Company's borrowing base to $25 million. The credit agreement calls for payments to reduce the Credit Facility to $20 million by July 1, 1999 if NUON International bv, the Company's largest stockholder, does not exercise its option to purchase an additional $5 million in common stock by September 4, 1998. The balance availability under the Credit Facility is $1.2 million as of June 8, 1998.
Management of the Company believes that general economic conditions and various sources of available capital, including current available borrowings under the Credit Facility and the expected funds to be received from NUON, will be sufficient to fund the Company's operations and meet debt service requirements through fiscal 1999.
In the event that available borrowings under the Credit Facility are not sufficient, NUON does not exercise its option to purchase additional Common Stock or additional financing cannot be obtained; the Company would need to conserve cash resources. In order to accomplish this objective, the Company believes that it would be necessary to take various actions, including reducing the amount of capital raised in future Drilling Programs, the introduction of additional cost cutting measures and the possible sale of certain assets. Management of the Company believes that measures of this type may have a material adverse effect on the Company.
YEAR 2000
The Company has developed an action plan and identified the resources needed to convert the majority of its computer systems and software applications to achieve a year 2000 date conversion with no effect on customers or disruption to business operations. Implementation of the plan has begun and the Company anticipates completion of testing or replacement of systems by the end of fiscal 1999. The Company estimates that the cost to complete these efforts, which primarily includes the purchase of software and hardware upgrades under normal maintenance agreements with third party vendors, will approximate $60,000, and will be expended primarily in fiscal 1999. In
addition, the Company has discussed with its vendors and customers the need to be 2000 compliant. Although the Company has no reason to believe that its vendors and customers will not be compliant by the year 2000, the Company is unable to determine the extent to which year 2000 issues will effect its vendors and customers, and the Company continues to discuss with its vendors and customers the need for implementing procedures to address this issue.
ACCOUNTING STANDARDS
In February 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" which may require the Company to report certain information about operating segments including product, services and geographical areas. SFAS No. 131 is required to be adopted for financial statements with fiscal years beginning after December 15, 1997. The Company has not determined the impact, if any, of this standard.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA.
The following pages contain the Financial Statements and supplementary data required by Item 8 of Part II of Form 10-K.
NORTH COAST ENERGY, INC.
AND SUBSIDIARIES
CONSOLIDATED FINANCIAL STATEMENTS
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
-----------------------------
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
FINANCIAL STATEMENTS: Consolidated balance sheets - Consolidated statements of operations Consolidated statements of stockholders' equity - Consolidated statements of cash flows - Notes to consolidated financial statements -
All other financial statement schedules have been appropriately omitted if the information is not required or is furnished in the financial statements or in the notes thereto.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of North Coast Energy, Inc.:
We have audited the accompanying consolidated balance sheets of North Coast Energy, Inc. (a Delaware corporation) and Subsidiaries as of March 31, 1997 and 1998, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three fiscal years in the period ended March 31, 1998. 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 generally accepted auditing standards. 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 financial position of North Coast Energy, Inc. and Subsidiaries as of March 31, 1997 and 1998, and the results of their operations and their cash flows for each of the three fiscal years in the period ended March 31, 1998, in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Cleveland, Ohio, June 4, 1998.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
CONSOLIDATED BALANCE SHEETS ---------------------------
MARCH 31, 1997 and 1998 -----------------------
ASSETS ------
The accompanying notes are an integral part of these consolidated balance sheets.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
CONSOLIDATED BALANCE SHEETS ---------------------------
MARCH 31, 1997 and 1998 -----------------------
LIABILITIES AND STOCKHOLDERS' EQUITY ------------------------------------
The accompanying notes are an integral part of these consolidated balance sheets.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY -----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998 -------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY -----------------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998 -------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS -------------------------------------
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998 -------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED MARCH 31, 1996, 1997 AND 1998
The accompanying notes are an integral part of these consolidated financial statements.
NORTH COAST ENERGY, INC. AND SUBSIDIARIES -----------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ------------------------------------------
MARCH 31, 1996, 1997 AND 1998 -----------------------------
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. ORGANIZATION
North Coast Energy, Inc. (North Coast), 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 Operating Company (NCOC), and NCE Securities, Inc. (NCE Securities). In addition, the Company's investments in oil and gas drilling partnerships, which are accounted for under the proportional consolidation method, are reflected in the accompanying financial statements. The Company's ownership of revenues in these drilling partnerships is as follows:
Capital Drilling Fund 1986-1 Limited Partnership 13.2%
North Coast Energy/Capital 1987-1 Appalachian Drilling Program Limited Partnership 40.4%
North Coast Energy/Capital 1987-2 Appalachian Drilling Program Limited Partnership 38.9%
North Coast Energy/Capital 1988-1 Appalachian Drilling Program Limited Partnership 35.1%
North Coast Energy/Capital 1988-2 Appalachian Drilling Program Limited Partnership 41.7%
North Coast Energy/Capital 1989 Appalachian Drilling Program Limited Partnership 31.6%
North Coast Energy 1990-1 Appalachian Drilling Program Limited Partnership 29.4%
North Coast Energy 1990-2 Appalachian Drilling Program Limited Partnership 28.9%
North Coast Energy 1990-3 Appalachian Drilling Program Limited Partnership 25.0%
North Coast Energy 1991-1 Appalachian Drilling Program Limited Partnership 28.4%
North Coast Energy 1991-2 Appalachian Drilling Program Limited Partnership 25.6%
North Coast Energy 1991-3 Appalachian Drilling Program Limited Partnership 28.9%
North Coast Energy 1992-1 Appalachian Drilling Program Limited Partnership 25.0%
North Coast Energy 1992-2 Appalachian Drilling Program Limited Partnership 27.8%
North Coast Energy 1992-3 Appalachian Drilling Program Limited Partnership 39.5%
North Coast Energy 1993-1 Appalachian Drilling Program Limited Partnership 32.6%
North Coast Energy 1993-2 Appalachian Drilling Program Limited Partnership 31.7%
North Coast Energy 1993-3 Appalachian Drilling Program Limited Partnership 30.0%
North Coast Energy 1994-1 Appalachian Drilling Program Limited Partnership 31.4%
North Coast Energy 1994-2 Appalachian Drilling Program Limited Partnership 25.0%
North Coast Energy 1994-3 Appalachian Drilling Program Limited Partnership 25.0%
North Coast Energy 1995-1 Appalachian Drilling Program Limited Partnership 20.0%
North Coast Energy 1995-2 Appalachian Drilling Program Limited Partnership 20.0%
North Coast Energy 1996-1 Appalachian Drilling Program Limited Partnership 20.0%
North Coast Energy 1996-2 Appalachian Drilling Program Limited Partnership 20.0%
North Coast Energy 1997-1 Appalachian Drilling Program Limited Partnership 38.2%
North Coast Energy 1997-2 Appalachian Drilling Program Limited Partnership 22.1%
All significant intercompany accounts and transactions have been eliminated.
C. 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 equivalents balances.
D. 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 14 years, vehicles, furniture and fixtures using accelerated methods over 5 to 7 years, building and improvements using accelerated methods over 31.5 years).
E. 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 development wells are capitalized.
Costs to drill exploratory wells that do not find proved reserves, costs of development 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 such amounts. Impairment is recorded on a drilling program or property specific basis, as applicable.
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 the property had been assessed. 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.
F. 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 and financial position and results of operations do not vary significantly from those which would result from use of the percentage-of-completion method.
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 and sold from the properties. Other revenue is recognized at the time it is earned and the Company has a contractual right to such revenue.
G. PER SHARE AMOUNTS
The computation of basic and diluted earnings per share for 1996, 1997 and 1998 does not assume the conversion of the unconverted Series A and B Preferred stock or the effect of warrants and stock options outstanding due to a calculated loss (after dividends) being incurred in each period and the effect, therefore, being anti-dilutive.
The average number of outstanding shares used in computing both basic and diluted net loss per share was 8,033,642, 8,240,776 and 14,106,492, for the years ended March 31, 1996, 1997 and 1998, respectively.
H. RISK FACTORS
The Company operates in an environment with many financial risks, including, but not limited to, its limited history of profitable operations, 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, and the highly competitive nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base, diversify its operations and continue its marketing efforts for and investments in drilling programs is also dependent upon the Company's ability to obtain the necessary capital through operating cash flow, additional borrowings or additional equity funds.
In the event that available borrowings under the Credit Facility are not sufficient or additional financing cannot be obtained, the Company would be required to continue its current efforts to conserve cash resources. In order to accomplish this objective, the Company believes that it would be necessary to take various actions, including reducing the amount of capital raised in future Drilling Programs, the introduction of additional cost cutting measures and the possible sale of certain assets.
I. ACCOUNTING ESTIMATES
The preparation of financial statements in conformity with generally accepted accounting principles 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.
J. 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 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.
2. BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS:
Billings in excess of costs on uncompleted contracts consist of the following at March 31:
3. LEASE COMMITMENTS:
The Company leases real and personal property under operating leases. The most significant obligations under these lease agreements were for annual building rentals, which included standard maintenance and insurance. Total rental expense under the operating leases for the years ended March 31, 1996, 1997 and 1998, amounted to approximately $82,000, $43,000 and $6,000, respectively. In 1996 and 1997, rent expense of approximately $65,000, and $34,000, respectively, was incurred pursuant to the lease of the Company's previous corporate headquarters from one of the Company's principal stockholders.
The Company currently has no noncancelable operating leases which require future minimum rental payments.
4. LONG-TERM DEBT:
Long-term debt consists of the following at March 31:
The Company has a $20,000,000 revolving credit agreement with its lender at March 31, 1998. The Agreement provides for a borrowing base which is determined semiannually by the lender based upon the Company's financial position, oil and gas reserves, as well as outstanding letters of credit ($290,000 at March 31, 1998), as defined. At March 31, 1998, the Company's borrowing base was $10,000,000 subject to reduction for the outstanding letters of credit. Available borrowings under the facility at March 31, 1998 were $3,144,735 and may subsequently change based upon the semiannual reserve study and borrowing base determination. Subsequent to year end, the availability decreased and borrowing base increased in conjunction with the Kelt Ohio Acquisition (Note 14).
The revolving line of credit is reviewed semi-annually and may be extended by an amendment to the current facility or converted to a term loan on July 1, 1999.
Amounts outstanding under the reducing revolving line of credit bear interest at the lending bank's prime rate plus 1% or LIBOR plus 2.75%, or approximately 10% and 8.5% at March 31, 1997 and 1998, respectively. The weighted average interest rate on these borrowings was 9.9% and 10.1% for fiscal 1997 and 1998, respectively. The agreement requires the Company to pay a commitment fee of .5% on the unused amount of the available borrowings. The agreement contains certain restrictive covenants, including working capital, current ratio, tangible net worth, and EBITDA calculations, as defined. The Company was in compliance with all covenants and restrictions at March 31, 1998.
The revolving credit facility and the notes are collateralized by substantially all of the Company's assets including receivables, inventory, equipment and a first mortgage on certain of the Company's interests in oil and gas wells and reserves.
Future maturities of long-term debt for the years ended March 31, are as follows:
The carrying amount of the Company's long-term debt approximates fair value, as primarily all of the Company's debt instruments carry adjustable interest rates which change periodically to reflect market conditions.
5. STOCKHOLDERS' EQUITY:
In September, 1997, the Company sold 5,747,127 shares of its common stock for $5,000,000 to NUON International (NUON), pursuant to the terms of a stock purchase agreement (NUON Agreement). Under the terms of the NUON Agreement, and subject to the satisfaction of certain conditions, as defined, NUON may purchase an additional 5,747,127 shares of common stock by each of September 30, 1998 and September 30, 1999. Proceeds from the sale of common stock were utilized to repay notes payable to a stockholder, reduce the amount outstanding under the revolving credit facility and for working capital purposes.
A. PREFERRED STOCK
The Board of Directors of North Coast has designated 563,270 shares of the 2,000,000 shares of preferred stock authorized as Series A, 6% Convertible Noncumulative 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 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 2.3 shares of common stock for each share of Series A Preferred stock converted.
All of the outstanding shares of Series A Preferred stock shall, at the option of North Coast, be converted into shares of common stock pursuant to an effective registration statement, as defined.
In the case where North Coast 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 North Coast at a price of $10 per share. North Coast does not have any obligation to redeem the Series A Preferred stock.
In the event of a voluntary or involuntary liquidation, dissolution or winding up of North Coast, holders of the Series A Preferred stock are entitled to be paid $10 per share out of the assets of North Coast but after payment of other indebtedness of North Coast, 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.
Each outstanding share of Series B Preferred stock will be entitled to one vote, excluding shares held by the Company or any entity controlled by the Company, which shares shall have no voting rights.
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 $335,330 as of March 31, 1998.
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 shall have the right, exercisable at their option, to convert any or all of such shares into 6.47 shares of common stock.
In fiscal 1997, the Company commenced a conversion offer to its preferred shareholders (Series A and B) to convert their shares into common stock with additional shares offered as an incentive. Following the termination of the conversion offer in fiscal 1997, 223,159 shares of preferred Series A were tendered and exchanged for 1,115,795 shares of common stock and 195,201 shares of preferred Series B were tendered and exchanged for 1,561,608 shares of common stock.
The following table presents unaudited, pro forma operating results as if the stock conversion and the NUON common stock sale had occurred at the beginning of each period presented.
The pro forma operating results have been prepared for comparative purposes only. They do not purport to present actual operating results that would have been achieved had the conversions and stock sale been made at the beginning of each period presented or to necessarily be indicative of future results of operations.
B. COMMON STOCK WARRANTS
Warrants issued in connection with the Series B Preferred stock entitle the holders thereof to purchase 1.15 shares of common stock with each warrant at a price of $2.61 per share, as defined. The warrants issued in connection with the Series B Preferred stock expired on December 18, 1997. There were 2,500,000 Series B warrants outstanding at March 31, 1996 and 1997, respectively.
The Company has granted a shareholder certain warrants to purchase 200,000 shares of common stock at $1.20 per share and 300,000 shares of common stock at $1.00 per share, as defined. These warrants were exercisable on June 13, 1995 and expire on June 13, 2000 and 1998, respectively. The warrants may be redeemed by the Company for $.10 per share at its option upon 30 days written notice.
In conjunction with the NUON Agreement, the Company issued NUON warrants to purchase 134,000 shares of common stock for $.875 per share. The Company is obligated to issue 134,000 warrants on each occasion NUON purchases an additional 5,747,127 shares of common stock. These warrants expire in September, 2002.
C. SERIES B UNIT WARRANTS
In connection with the issuance of the Series B Preferred stock, the underwriter of the issue received 50,000 warrants to purchase Series B Units at $12.00 per unit. A Series B Unit consists of one share of Series B Preferred stock, and five warrants to purchase 1.15 shares of common stock at $2.61 per share. These warrants expired on December 18, 1997 and none of these warrants were exercised as of March 31, 1998.
D. STOCK OPTIONS AND STOCK APPRECIATION RIGHTS
North Coast has a stock option plan (the Option Plan) to provide incentives to stimulate interest in the development and financial success of the Company. The Option Plan provides for the granting of stock options to purchase common stock at an option price determined by North Coast's Compensation Committee (the Committee). The Committee shall determine 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 shall not exceed $100,000. Options granted under the Option Plan terminate upon the employee leaving the Company. The Company, from time to time, may issue additional options outside the plan.
Stock option transactions during 1996, 1997 and 1998 are summarized as follows:
Subsequent to year end, the Company granted 100,000 options to a company director at $.875 per share.
A summary of stock options outstanding and exercisable at March 31, 1998 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.
The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards 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 1996, 1997 and 1998 consistent with the provisions of SFAS No. 123, the Company's net loss per share would not change materially.
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 230,000 shares of common stock, as defined. The expenses of administering the Bonus Plan shall be borne by the Company. The Bonus Plan will terminate on February 1, 2001. The Company has issued 16,700 shares of common stock related to this plan during fiscal 1998 and 108,249 shares of common stock since inception.
6. INCOME TAXES:
The Company has adopted the Statement of Financial Accounting Standards 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.
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, 1997 and 1998 were as follows:
The Company has certain alternative minimum tax credit carryforwards and net operating loss carryforwards which may be available to offset future taxable income. A valuation allowance has been recorded against these amounts due to uncertainty as to the Company's ability to realize any future benefit.
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 $20,000 and $30,000 were accrued or paid for the years ended March 31, 1997 and 1998, respectively.
North Coast provides no significant postretirement and/or postemployment benefits other than the profit sharing plan discussed above.
8. OTHER 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 sales lines additions) of the partnerships as they are incurred. At March 31, 1998, management estimates the commitment to fund such costs to be approximately $876,000. The commitment is expected to be funded by September 30, 1998.
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) North Coast has agreed to indemnify these investor-general partners from any partnership liability which they may incur in excess of their contributions.
The Company has entered into employment contracts with certain of its officers that provide for a minimum annual salary and incentives based on the Company's sales and profitability. The commitment, including minimum incentives, amounts to $430,000, $430,000 and $330,000, respectively, for the years ending March 31, 1996, 1997 and 1998 plus CPI adjustments. In addition, each employment contract provides for: reimbursement of certain business expenses; life insurance ranging from $500,000 to $1,000,000; disability benefits for a stated period of time as defined, and termination benefits of between one and three years' salary.
9. INDUSTRY SEGMENTS AND MAJOR CUSTOMERS:
North Coast and its subsidiaries operate in a single industry segment, the acquisition, exploration and development of oil and gas properties. North Coast 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 companies or through limited partnerships sponsored by the Company.
The Company's revenue, other than revenue from oil and gas production, is derived primarily from public and private program partnerships sponsored by the Company. During 1996, 1997, and 1998 between 35% and 49% of the Company's oil and gas production
revenues were derived from two and/or three significant purchasers. A significant portion of trade accounts receivable at March 31, 1997 and 1998 was attributable to these purchasers.
10. RECEIVABLES FROM AFFILIATES:
Accounts receivable from affiliates consists 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.
11. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED):
The following supplemental unaudited oil and gas information is required by Statement of Financial Accounting Standards (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 United States.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
Provision (credit) for income taxes was computed using the statutory tax rates for the years ended March 31, 1996, 1997 and 1998 and reflects permanent differences, including 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.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
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, 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 is included at the working interest which the Company estimates to retain in the properties, and the standardized measure was calculated using prices and operating costs and development costs expected in the area of interest. The quantities for fiscal 1997 and 1998 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 do 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.
12. RELATED PARTY TRANSACTIONS:
During fiscal 1997, the Company paid finder's fees to two employees in the amount of $75,000 each. During fiscal 1998, the Company purchased wells and a pipeline from a shareholder for $62,000 and purchased 28 wells from an employee for $339,000.
13. ACCOUNTING STANDARDS:
In fiscal 1996, the Company adopted the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets." Although the Company in the past has routinely reviewed its oil and gas properties for impairment, the Company changed its method of assessing the impairment of the capitalized costs of oil and gas properties, to a drilling program or property specific basis as applicable, to comply with the new standard. As a result of adoption, the Company incurred impairment expense of approximately $1,562,000, on a pretax basis, for the year ended March 31, 1996. The impairment expense is included in the depreciation, depletion, amortization, impairment and other caption in the accompanying consolidated financial statements.
In February 1997, the Financial Accounting Standards Board issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" which may require the Company to report certain information about operating segments including product, services and geographical areas. SFAS No. 131 is required to be adopted for financial statements with fiscal years beginning after December 15, 1997. The Company has not determined the impact, if any, of this standard.
14. SUBSEQUENT EVENT:
In May 1998, the Company acquired oil and gas properties from Kelt Ohio (the "Kelt Ohio Acquisition") for a purchase price of approximately $16 million. The acquisition was accounted for as a purchase. The acquired assets include approximately 900 natural gas and oil wells, brine disposal facilities, drilling and service rigs, and natural gas compressors and gas gathering systems.
The Company funded the acquisition primarily with borrowings under its revolving credit facility which was amended in May 1998 to increase the borrowing base to $25 million, as defined.
The accompanying unaudited pro forma financial information gives effect to the Kelt Ohio Acquisition and the related financing in May 1998 for approximately $16 million. The unaudited pro forma operating results were prepared as if the Kelt Ohio Acquisition had
occurred on April 1, 1997. The accompanying unaudited pro forma balance sheet information of the Company as of March 31, 1998 has been prepared as if the transaction had occurred as of that date.
Balance Sheet Data (at March 31, 1998 unaudited):
Cash and equivalents $ 1,578,984
Total assets $39,811,516
Long-term debt $23,671,035
Stockholders' equity $12,339,287
The pro forma operating results do not purport to present actual operating results that would have been achieved had the acquisition and financing been made at the beginning of the period presented or to necessarily be indicative of future results of operations.
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
The information required by this Item 10 as to the Directors of the Company is incorporated herein by reference to the information set forth under the caption "Information Concerning Nominees for Directors" in the Company's definitive Proxy Statement for the 1998 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. 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.
Executive Officers of the Registrant*
Timothy Wagers, age 38, joined North Coast in 1983 and currently is Treasurer and Chief Financial Officer. Mr. Wagers is also responsible for overseeing the accounting for partnership distributions, oil and gas production and tax reporting, and for monitoring well costs. He received a Bachelor of Science in Accounting from the University of Akron. From 1982 through 1983, Mr. Wagers was employed by Hausser + Taylor, independent certified public accountants, as a staff accountant auditing various entities including oil and gas partnerships. Mr. Wagers is a certified public accountant, a member of the Ohio Society of Certified Public Accountants, the Ohio Petroleum Accountants Society, and the American Institute of Certified Public Accountants.
Thomas A. Hill, age 40, was elected Secretary and General Counsel of North Coast Energy in August 1987. 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 Mahoning County Bar Association and Eastern Mineral Law Foundation.
*The description of the Company's executive officers called for in this item is included herein pursuant to instruction 3 to Section (b) of Item 401 of Regulation S-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 1998 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 1998 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 1998 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)
Report of Independent Public Accountants Consolidated balance sheets - Consolidated statements of operations Consolidated statements of stockholders' equity - Consolidated statements of cash flows - Notes to consolidated financial statements -
(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 current report on Form 8-K dated June 12, 1998.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly cased this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTH COAST ENERGY, INC.
By /s/ Charles M. Lombardy Chief Executive Officer June 26, 1998 - ----------------------------- Charles M. Lombardy, Jr.
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 -------------
- -------------------------
(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 Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 1996.
(J) Incorporated herein by reference to the appropriate exhibit to the Registrant's Report on Form 8-K dated June 12, 1998.
*Exhibit 27.1 furnished for Securities and Exchange Commission purposes only.