Item 1. Business
General
NGAS Resources, Inc. (the “Company”) is an independent energy company focused on natural gas development and production in the southern portion of the Appalachian Basin. We specialize in generating our own geological prospects in this region, where we have established expertise and recognition. We develop our prospects through our operating subsidiary, Daugherty Petroleum, Inc. (“DPI”), and its interests in sponsored drilling programs. Directly and through its subsidiaries, DPI also constructs and maintains gas gathering systems for our wells, operates natural gas distribution facilities for two communities in Kentucky, operates a gas gathering system connecting major natural gas supply basins, coordinates our private placement financings and owns inactive gold and silver prospects in Alaska. Our principal and administrative offices are located at 120 Prosperous Place, Suite 201, Lexington, Kentucky 40509. Our common stock is traded on the Nasdaq National Market under the symbol “NGAS,” and we maintain a website with information about us at www.ngas.com.
We commenced oil and gas operations in 1993 with the acquisition of DPI and have sponsored 30 separate drilling programs through the date of this report. In June 2004, we changed our corporate name from Daugherty Resources, Inc. to NGAS Resources, Inc. The name change reflects our focus on natural gas development and production and reinforces our association with the NGAS acronym from its use as the Nasdaq trading symbol for our common stock and the Internet address of our website. Unless otherwise indicated, references in this report to “we,” “our” or “us” include the Company as well as DPI, its subsidiaries and its interests in drilling programs. As used in this report, “Mcf” means thousand cubic feet, “Mmcf” means million cubic feet, “Bbl” means barrel, “Mbbl” means thousand barrels, “Mcfe” means thousand cubic feet of gas equivalents (determined at the ratio of six Mcf of natural gas to one Bbl of oil), “Mmcfe” means million cubic feet of gas equivalents and “Dth” means dekatherms. This report includes various other capitalized terms that are defined when first used.
Objectives
We have structured our business to achieve capital appreciation through growth in our natural gas production, reserves, cash flow and earnings per share. During 2005, we increased our production by 112% and our total revenues by 30%, while adding 9.2 Bcfe to our proved reserves through both drilling and acquisitions. At December 31, 2005, the standardized measure of discounted future net cash flows from our proved reserves was $207.6 million, up 125% from the prior year end. We drilled 155 wells in 2005, all successfully. During the year, we also consolidated our core interests in the Appalachian Basin with the completion of our Leatherwood gathering system, while diversifying our asset base with initiatives in the Illinois and Arkoma Basins. At year end, our lease position exceeded 315,000 acres, and our gathering systems for connecting our wells to interstate pipelines with access to major natural gas markets in the eastern United States spanned over 311 miles. To support our growth during 2005, in addition to outside capital of $44.1 million for sponsored drilling programs, we raised $53.6 million in financing transactions, while earning $0.05 per weighted average basic share outstanding for the year. Our goal is to sustain and efficiently manage our growth.
Strategy
Our strategy for continuing to realize our operational and financial objectives emphasizes several components. Each is aimed at positioning us to capitalize on natural gas development opportunities and long range pricing expectations for this commodity.
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Concentrated Drilling Operations. Drilling is our mainstay for production and reserve growth. Over the next few years, we plan to focus our drilling resources in our Leatherwood Field, where we have identified over 600 additional drilling locations. To help finance our Leatherwood and various diversified drilling initiatives, we expect to continue sponsoring drilling programs for private investors. We generally contribute between 20% to 40% of total program capital and maintain proportionate program interests. Since 2000, we drilled 472 gross (141.1518 net) gas wells through our drilling programs, including 155 gross (44.3040 net) wells in 2005. Our two largest 2005 programs concentrated on development of our Leatherwood Field and other core properties in the southern Appalachian Basin. We maintain a 30.7% interest in both programs. During 2005, we also sponsored a specialized program for a mix of exploratory and development wells in our Martin’s Fork and Amvest Fields, an exploratory program to test the New Albany Shale formation on recently acquired acreage within the Illinois Basin in western Kentucky, and a joint venture for coalbed methane (“CBM”) wells in the Arcoma Basin. Our ability to attract outside capital through our drilling programs has enabled us to solidify our position in the Appalachian Basin, while also accelerating our development of new prospects in other regions with similar characteristics.
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Planned Drilling Program Financings. We plan to sponsor at least four drilling programs during 2006 for up to 195 wells. We anticipate contributing up to 75% of total program capital for Leatherwood development and at least 30% of total capital for drilling initiatives in our Fonde, Amvest and Martin’s Fork Fields. We also plan to continue our CBM project in the Arkoma Basin and sponsor a new initiative with a joint venture partner on its acreage in Jackson County, West Virginia. We intend to change the structure of our new drilling programs from turnkey pricing to cost plus, with a view to reducing our exposure to well completion complexities and price volatility for drilling services, equipment and steel casing requirements.
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Acquisition of Additional Drilling Prospects. We focus on expanding our substantial inventory of drilling prospects that meet our criteria for building predictable, long-lived reserves. In three separate transactions during 2004, we acquired oil and gas interests covering approximately 90,000 acres in Bell, Harlan and Leslie Counties, Kentucky and Lee County, Virginia, including key interests in the Martin’s Fork and Amvest Fields purchased from Stone Mountain Energy Company (“SME”). During the fourth quarter of 2005, we acquired a significant position in approximately 14,000 acres of CBM properties in the Arkoma Basin within Leflore County, Oklahoma and Sebastian County, Arkansas. We also initiated an exploratory play during 2005 in the Illinois Basin on acquired tracts spanning approximately 15,500 acres within Breckinridge, Grayson, Hardin, Meade and Ohio Counties in western Kentucky. We plan to continue capitalizing on opportunities to assemble or acquire large tracts with significant unproved gas development potential. Our goal is to consolidate our position in Appalachian Basin, while also diversifying our inventory of drilling prospects in other basins that offer comparable natural gas and CBM plays.
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Disciplined Approach to Drilling. As of December 31, 2005, we had interests in a total of 815 wells. Most of our wells are drilled to relatively shallow total depths up to 5,000 feet, encountering as many as five distinct and predictable natural gas pay zones. This disciplined approach focused on repeatable prospects helps reduce drilling risks, as reflected in our success rate. Historically, over 99% of our wells have been completed as producers. We complete and produce our wells from several pay zones whenever possible, eliminating the costs and complexities of deferred completions with behind-pipe gas. The primary pay zone for most of our wells is the Devonian Shale formation. This is considered an unconventional target due to its low porosity and permeability. To be productive, natural fracturing must be present and generally must be enhanced by effective acidizing or other fracturing treatment. While this typically results in modest initial volumes and pressures, it also accounts for the low annual decline rates demonstrated by our wells, many of which are expected to produce for 25 years or more. During 2005, we implemented a program to leverage our core expertise with evolving technologies in horizontal drilling, which may provide advantages in extracting this type of tight gas. The initial phase of the program is being conducted on recently acquired acreage in the Illinois Basin to test the New Albany Shale formation, which has similar geologic characteristics to the Devonian Shale in our core areas of the Appalachian Basin.
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Extension of Gas Gathering Systems. We construct and operate gas gathering facilities to connect our wells to interstate pipelines with access to major east coast natural gas markets. As of December 31, 2005, our gas gathering facilities spanned 311 miles, including over 140 miles of gathering and production lines added during the year. In addition to generating gas transmission and compression revenues, our 100% ownership of these systems gives us control over third-party access, providing competitive advantages in acquiring and developing nearby acreage. The extension of our gathering systems during 2005 included the completion of our 23-mile, eight-inch steel line for connecting our wells in the Leatherwood Field and a 16-mile, six-inch line that connects our Leatherwood system with the Stone Mountain gathering system owned by Duke Energy Gas Services, LLC (“Duke Energy”). See “Recent Initiatives” below. At year end, we had installed compressors, dehydration units and lateral lines for connecting 51 wells in the Leatherwood Field. As of the date of this report, we have a total of 78 Leatherwood wells producing to sales and an additional 62 wells awaiting connection. With our Leatherwood gathering infrastructure now in place, we expect to bring current and future wells on line soon after completion.
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Purchase of Producing Properties. The purchase of third party production offers a means in addition to drilling for accelerating our growth, while continuing to capitalize on our operating experience. Our acquisition criteria for producing properties include reserve life, profit enhancement potential, existing infrastructure, geographic concentration and working interest levels permitting operation of acquired properties. During the second half of 2004, we added over 29.7 Bcf of gas equivalents to our estimated proved reserves in three separate transactions at an acquisition price averaging $1.17 per Mcfe. In the fourth quarter of 2005, we acquired a 25% interest in producing properties within the Arkoma Basin, with an estimated 7.0 Bcf of proved CBM reserves, at an acquisition price of $1.63 per Mcfe. We continuously evaluate opportunities to acquire producing properties meeting our criteria for long-lived reserves in targeted geographic areas.
Recent Initiatives
Gathering System Acquisition. In January 2006, we entered into an agreement with Duke Energy to purchase part of its Stone Mountain gathering system for $18 million. The agreement covers 116 miles of the system, spanning parts of southeastern Kentucky and southwestern Virginia. It ties into Duke Energy’s East Tennessee Natural Gas pipeline system, which connects major natural gas supply basins to growing markets in the eastern United States. The acquisition also includes five delivery measuring and regulation stations, four compression stations and a liquids extraction plant. Since our SME acquisition in October 2004, we have operated the Stone Mountain system for Duke Energy and dedicated our SME production, and subsequently, our Straight Creek and Leatherwood production for delivery through the system. The current through-put of the system is 12,000 Mcf per day, two-thirds of which we own or control. As currently configured, the system has an estimated through-put capacity of 24,000 Mcf per day. With compression upgrades, we can substantially increase the through-put capacity of the system. By acquiring this system, we expect to ensure deliverability from our core properties and further enhance our competitive position in the region. On an annualized basis, we also expect to realize up to $3 million in gathering revenues and cost savings from ownership of the system. Closing of the transaction is subject to customary conditions, including regulatory approval involving the portion of the Stone Mountain system not included in our acquisition.
Property Acquisition. Effective November 1, 2005, we acquired the CBM assets of Dart Energy Corporation covering approximately 14,000 gross (3,500 net) acres in the Arkoma Basin within Sebastian County, Arkansas and Leflore County, Oklahoma. The acquired assets include a 25% interest in 48 producing wells, with average daily net production of 1,400 Mcfe as of the acquisition date. We also acquired a 25% interest in a limited liability company that owns and operates the gathering system servicing the project area. The gathering facilities include 22 miles of low-pressure polyethylene pipe, 8.5 miles of high pressure steel pipe and a compressor discharge system. The purchase price for the acquired CBM interests and gas gathering assets was $11.4 million. Earlier in the fourth quarter of 2005, we entered into a farmout agreement with CDX Gas, LLC, the operator of this project, covering 90% of its majority (75%) interest in proved undeveloped (“PUD”) locations within the project area. Under the terms of the farmout agreement, we assumed 100% of future developments costs attributable to the CDX working interest and granted CDX a 25% carried working interest, increasing to 50% after payout of project wells. Combined with our interests from the Dart Energy acquisition, this gives us an overall position of approximately 73% in future development of the CBM project. As of the date of this report, we have drilled 5 gross (2.047 net) CBM wells through a specialized drilling program and have identified an additional 19 PUD locations in the project area.
Williston Basin Leasing Initiative. During 2005, we initiated a leasing program in the Williston Basin. We have targeted the southwestern portion of Dunn County, North Dakota. As of year end, our acquired position in the project area aggregated 12,406 gross (8,138 net) areas.
Convertible Note Financing. In December 2005, we completed an institutional private placement of our 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. We used part of the proceeds from the financing to purchase our CBM interests in the Arkoma Basin and expect to fund our Stone Mountain gathering system acquisition from part of the remaining proceeds. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”
Regional Advantages
Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian Basin. This is one of the oldest and most prolific natural gas producing areas in the United States. Historically, wells in this part of the Appalachian Basin produce between 150 to 500 Mmcf of natural gas over a reserve life of 25 years or more. The natural gas production, known as sweet gas, is environmentally friendly because it is substantially free of sulfur compounds, carbon dioxide or other chemical impurities. In addition, most of our wells produce no water with the gas production. This helps us minimize production (lifting) costs. Appalachian gas also has the advantage of high energy (Dth) content, ranging from 1.1 to 1.3 Dth per Mcf. Our gas sales contracts provide upward adjustments to index based pricing for throughput with an energy content above 1 Dth per Mcf, resulting in realized premiums averaging 17% over normal pipeline quality gas. Our proximity to major east coast markets generates further realization premiums above Henry Hub spot prices. These factors contribute to enhanced cash flows and long term returns on our Appalachian properties.
Drilling Programs
Drilling Program Structure. We sponsor and manage drilling programs to participate in our drilling initiatives and accelerate our growth. Most of our drilling programs are limited partnerships structured to minimize drilling risks on repeatable prospects and optimize tax advantages for private investors. To develop exploratory prospects with higher risk profiles, we generally rely on smaller, specialized drilling programs with strategic and industry partners or other suitable investors. At the commencement of operations, we assign drilling rights for specified wells to an operating partnership between DPI and the drilling program. Historically, we have conducted these operations under turnkey drilling contracts, requiring DPI to drill and complete the wells at specified prices. We are responsible under these turnkey arrangements for any drilling and completion costs exceeding the contract price, and we are entitled to any surplus if the contract price exceeds our costs. In view of increased demand and price volatility for drilling services and equipment, we plan to structure our new drilling programs on a cost-plus basis designed to share this exposure with our outside investors.
Drilling Program Investments. In addition to managing program operations, we invest in each drilling program on substantially the same terms as unaffiliated investors. We contribute capital to each program in proportion to our initial ownership interest, and we share program distributions in the same ratio until program
distributions reach “payout,” which ranges from 100% to 110% of partners’ investment. After payout, we are entitled to specified increases in our distributive share, up to 15% of the total program interests. During 2005, we sponsored five separate drilling programs. We contributed 30% of total capital to our two largest programs, 40% to a specialized program for a mix a development and exploratory wells on prospects included in our SME acquisition, 20% to a specialized program for testing the New Albany Shale formation in western Kentucky and 33% to a specialized program for CBM wells in the Arkoma Basin. Historically, we have paid all selling costs for drilling program financings and all direct overhead and administrative costs for program operations. Under that structure, the return on our investment has been limited to our share of program distributions, profits realized under our turnkey drilling contracts, net of our proportionate share of those profits, plus customary fees for well operating and gas gathering services.
Drilling Program Benefits. Our structure for sharing drilling program costs, risks and returns helps us attract outside capital from private investors. This addresses the high capital costs of our business, enabling us to accelerate the development of our properties without relinquishing control over drilling and operating decisions. The structure also provides economies of scale with operational benefits at several levels.
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Based on our 30% capital investment in our largest drilling programs, we control a drilling budget over three times greater than we could support on our own. This helps us compete for attractive properties by increasing our drilling commitments. It also leverages our buying power for drilling services and materials, contributing to lower overall development costs.
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Aggregating our capital with private investors in our drilling programs enables us to maintain a larger and more capable staff than we could otherwise support if we were operating solely for our own account.
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Accelerating the pace of development activities through our drilling programs expands the production capacity we can make available to gas purchasers, contributing to higher and more stable sales prices for our production.
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By conducting drilling operations on our undeveloped prospects through specially tailored drilling programs and retaining larger ownership interests, we expand our inventory of developmental locations with lower risk profiles for subsequent programs, while adding to our proved reserves, both developed and undeveloped.
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Our drilling program strategy substantially increases the number of wells we could drill solely for our own account, diversifying the risks of drilling operations.
Drilling Program Financings. Our strategy for developing our oil and gas properties through drilling programs has benefited from substantial increases in the demand and market price for natural gas, attracting investment capital to our industry. In 2004, we increased our contribution to sponsored drilling programs from 25% to 30% of total program capital. During 2005, we sponsored two traditional development programs as well as three specialized drilling programs with various new structures for a mix of development and exploratory wells outside our core areas.
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Our two largest drilling programs were initiated in January and April 2005 for a total of 130 development wells in the southern portion of the Appalachian Basin. We have an initial 30% interest in each of these programs, which have concentrated drilling activities in our Leatherwood Field. Exercise of third-party participation rights for part of the working interest in wells drilled on the Leatherwood acreage during 2005 has reduced the interest of the drilling programs in those wells by the amount of the third-party participants’ working interests. See “Participation Rights” below.
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The first of our specialized programs in 2005 was sponsored for 20 wells in the Martin’s Fork and Amvest Fields on acreage acquired from SME. We have an initial 40% interest in this program, which has retained our traditional turnkey drilling structure.
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In a second specialized program sponsored in 2005, we have an initial 20% interest in 30 exploratory wells to test the New Albany shale formation, both through conventional and horizontal drilling, on recently acquired tracts spanning approximately 15,500 acres within the Illinois Basin in western Kentucky. Half of
the wells in the exploratory program will await completion, either conventionally or horizontally, through a subsequent program to be sponsored in 2006, based on our evaluation of the initial wells.
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In addition to our 25% interest in producing CBM wells acquired from Dart Energy Corporation in the Arkoma Basin, we drilled five wells through a specialized drilling program in the project area covered by our farmout arrangement with the operator of the CBM project. See “Recent Initiatives - Properties Acquisition” above. This is the first program to implement our new cost plus drilling structure.
The following table summarizes our financing activities through private placements of interests in sponsored drilling programs during the last two years.
Participation Rights. The leases and farmouts for drilling prospects on some of our acreage in the Appalachian Basin, primarily the Leatherwood Field, are subject to third-party participation rights for up to 50% of the working interests in new wells drilled on the covered acreage. During 2005, participation rights in a total of 60 wells in the Leatherwood Field were exercised for an average working interest of 28.75%. Exercise of those rights for development wells included in our 2005 drilling programs has reduced the programs’ working interest in the wells by the amount of the third-party participants’ working interests. This increases the total number of gross wells to be drilled by these programs, but does not affect their net well position. To maintain our net well position, we plan to increase our ownership interest in new drilling programs for development of our Leatherwood prospects.
Conversion Rights of Program Participants. The partnership agreements governing most of our drilling programs organized since 2000 provide program participants with the right, exercisable for 90 days at the end of the fifth through ninth years following the program’s organization, to convert their program interests into our common shares at prevailing market prices. Any converted program interests will be valued at their proportionate share of the program’s year-end oil and gas reserves, based on the standardized measure of discounted future net cash flows from those reserves, as reflected in the program’s year-end reserve report from independent petroleum engineers. Each program participant’s annual conversion right is limited to 49% of his program interest. The conversion rights in all programs are also limited in any year to 19% of our common shares then outstanding.
Drilling Operations
Structure. We drill and operate most of our wells under drilling contracts with sponsored drilling programs. We do not own or operate any of the rigs or drilling equipment used in performing these contracts, relying instead on specialized subcontractors we engage for all drilling and completion work. This enables us to streamline our operations and conserve capital for our drilling program investments, gathering line extensions and property acquisitions, while retaining control over all geological, drilling, engineering and operating decisions. The geological characteristics of our properties enable us to drill most of our wells in seven to ten days, although we generally wait until gathering lines for new wells are in place before undertaking completion operations. Under the terms of our drilling contracts, we serve as the operator at a monthly rate up to $300 for each gas well and $500 for each well that produces oil. We perform regular inspection, testing and monitoring functions on our producing wells and gathering systems with our own personnel.
Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during the last three years. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests in wells drilled through our drilling programs, without giving effect to any reversionary interest we may subsequently earn in those programs. During the fourth quarter of 2005, we drilled 37 gross (10.6088 net) wells. Drilling results shown in the table for 2005 include 87 gross (25.0186 net) wells that were drilled and successfully tested in at least one primary pay zone by year end but were awaiting installation of gathering lines prior to completion.
Producing Activities
Production Profile. Most of our wells share a relatively predictable production profile, producing high quality natural gas at low pressures from several pay zones on core properties in the Appalachian Basin. Wells in this region generally demonstrate moderate annual production declines throughout their economic life, which may continue for 25 years or more without significant remedial work or the use of secondary recovery techniques.
Production Volumes. The following table shows our total net oil and gas production volumes during the last three years.
Production Prices and Costs. Our production revenues and estimated oil and gas reserves are substantially dependent on prevailing market prices for our natural gas, which represents over 97% of our proved reserves on an energy equivalent basis at December 31, 2005. Although natural gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand, weather conditions and many other factors, we have benefited from a market-wide rebound in domestic natural gas prices in the last few years. Our production prices and costs also reflect the quality of natural gas in our operating areas. Known as sweet gas, its high energy content generally commands a premium averaging 17% over normal pipeline quality gas. Our proximity to major east coast markets generates further realized premiums above Henry Hub spot prices.
The following table shows the average sales prices and lifting costs for our oil and gas production during the last three years. Average sales prices for our natural gas do not reflect certain transportation charges for some of our production during the reported periods. During 2005, these transportation charges ranged from approximately $0.29 to $0.62 per Dth.
Horizontal Drilling Initiatives. During 2005, we implemented a program on recently acquired acreage in the Illinois Basin to test the New Albany shale formation, which has many of the same geologic characteristics as the Devonian Shale formation throughout our core properties in the southern portion of the Appalachian Basin. Both formations are considered unconventional targets due to their low porosity and permeability. Our Illinois Basin initiative is designed to leverage our core expertise with evolving technologies in horizontal drilling, which may provide advantages in extracting this type of tight gas by allowing the well bore to stay in contact with the reservoir longer and intersect more vertical fractures in the formation. While substantially more expensive, horizontal drilling may improve overall returns on investment by limiting the number of wells necessary to deplete an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells.
Production Purchase Initiatives. We continuously evaluate opportunities to acquire producing natural gas wells meeting defined criteria in targeted geographic areas. Our acquisition criteria for producing properties include the longevity of remaining reserves, profit enhancement potential, geographic concentration and majority working interest levels.
Gas Gathering Facilities
We construct and operate various gas gathering facilities to provide compression, connection and local distribution capabilities for many of our wells. As of December 31, 2005, our gas gathering facilities spanned 311 miles in our producing areas, including over 140 miles of gathering and production lines added in 2005. Our gathering system initiatives during 2005 included completion of a 23-mile, eight-inch steel gathering system to connect our wells in the Leatherwood Field and a 16-mile, six-inch line that connects with the Stone Mountain system we operate for Duke Energy. See “Strategy - Extension of Gas Gathering Systems” above. In January 2006, we entered into an agreement to acquire a 116-mile portion of the Stone Mountain system from Duke Energy. See “Recent Initiatives - Gas Gathering Acquisition” above.
Customers
Natural Gas Sales. We sell our natural gas production primarily to various unaffiliated gas marketing intermediaries. In addition to gas marketing services, these firms generally provide gas transportation arrangements and perform revenue receipt and related services. Our customers also include pipelines and transmission companies. During 2005, approximately 30% of our natural gas production was sold under fixed-price contracts at rates ranging from $5.83 to $11.81 per Dth, before certain transportation charges. The balance of our natural gas production for the year was sold primarily at prices determined monthly under formulas based on prevailing market indices.
Crude Oil Sales. Production from our oil wells is sold primarily to local refineries. Our oil production is generally picked up and transported by our customers from storage tanks located near the wellhead. Sales are generally made at posted field prices, net of transportation costs.
Utility Sales. Through Sentra Corporation, a wholly owned subsidiary of DPI, we own and operate distribution systems for retail sales of natural gas to two communities in southcentral Kentucky. As a public utility, Sentra’s gas sales are regulated by the Kentucky Public Service Commission. As of December 31, 2005, Sentra had 216 customers, of which 74 were commercial and agri-business accounts. Demand for these services has benefited from continued growth in the acceptance and use of natural gas by participants in the poultry industry, which is a major segment of the economy in Sentra’s service areas.
Competition
Competition in the oil and gas industry is intense, particularly for the acquisition of producing properties and proved undeveloped acreage. Independent oil and gas companies, drilling and production purchase programs and individual producers and operators actively bid for desirable oil and gas properties and for the equipment and labor required to develop and operate them. Substantial increases in natural gas prices over the last few years have heightened the demand, competition and cost for these resources. Many industry competitors have exploration and development budgets substantially greater than ours, potentially reducing our ability to compete for desirable prospects. To compete effectively, we have structured our business to capitalize on our experience and strengths, We maintain a focused acquisition strategy and disciplined approach to drilling, with a view to consolidating our position as a niche developer and building our track record as a producer in our operating areas.
Regulation
General. The oil and gas business is subject to broad federal and state laws that are routinely under review for amendment or expansion. Various federal, state and local departments and agencies empowered to administer these laws have issued extensive rules and regulations binding on industry participants. Many of these laws and regulations, particularly those affecting the environment, have become more stringent in recent years, and some impose penalties for noncompliance, creating the risk of greater liability on a larger number of potentially responsible parties. The following discussion of oil and gas industry regulation is summary in nature and is not intended to cover all regulatory matters that could affect our operations.
State Regulation. State statutes and regulations require permits for drilling operations and construction of gathering lines, as well as drilling bonds and reports on operations. These requirements often create delays in drilling and completing new wells and connecting completed wells. Kentucky and other states in which we conduct operations also have statutes and regulations governing conservation matters. These include regulations affecting the size of drilling and spacing or proration units, the density of wells that may be drilled and the unitization or pooling of oil and gas properties. State conservation laws generally prohibit the venting or flaring of gas and impose certain requirements on the ratability of production, and some states have established maximum rates of production from oil and gas wells. None of the existing statutes or regulations in states where we operate currently impose restrictions on the production rates of our wells or the prices received for our production.
Federal Regulation. The sale and transportation of natural gas in interstate commerce is subject to regulation under various federal laws administered by the Federal Energy Regulatory Commission (“FERC”). Historically, these laws included restrictions on the selling prices for specified categories of natural gas sold in “first sales,” both in interstate and intrastate commerce. While these restrictions were removed in 1993, enabling sales by producers of natural gas and all sales of crude oil to be made at market prices, federal legislation reinstituting price controls could be adopted in the future.
During the last decade, a series of initiatives were undertaken by FERC to remove various barriers and practices that historically limited producers from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. These regulations have had a profound influence on domestics natural gas markets, primarily by increasing access to pipelines, fostering the development of a large short term or spot market for gas and creating a regulatory framework designed to put gas sellers into more direct contractual relations with gas buyers. These changes in the federal regulatory environment have greatly increased the level of competition among suppliers. They have also added substantially to the complexity of marketing natural gas, prompting many producers to rely on highly specialized experts for the conduct of gas marketing operations.
Environmental Regulation. Participants in the oil and gas industry are subject to numerous federal, state and local laws and regulations designed to protect the environment, including comprehensive regulations governing the treatment, storage and disposal of hazardous wastes. Liability for some violations of these laws and regulations may be unlimited in cases of willful negligence or misconduct, and there is no limit on liability for environmental clean-up costs or damages on claims by the state or private parties. Under regulations adopted by the Environmental Protection Agency and similar state agencies, producers must prepare and implement spill prevention control and countermeasure plans to deal with the possible discharge of oil into navigable waters. State and local permits or approvals may also be needed for waste-water discharges and air pollutant emissions. Violations of environment
related lease conditions or environmental permits can result in substantial civil and criminal penalties as well as injunctions curtailing operations.
We conduct our drilling and production activities to comply with all applicable environmental regulations, permits and lease conditions, and we monitor subcontractors under our turnkey drilling contracts for environment compliance. While we believe our operations conform to those conditions, we remain at risk for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities by prior owners or operators of properties in which we own interests. In any of those events, we could be exposed to liability for clean-up costs or damages in excess of insurance coverage, and we could be required to remove improperly disposed waste, remediate property contamination or undertake plugging operations to prevent future contamination.
Occupational Safety Regulations. We are subject to various federal and state laws and regulations intended to promote occupational health and safety. Although all of our wells are drilled by independent subcontractors under our turnkey drilling contracts, we have adopted environmental and safety policies and procedures designed to protect the safety of our own supervisory staff and to monitor all subcontracted operations for compliance with applicable regulatory requirements and lease conditions, including environmental and safety compliance. This program includes regular field inspections of our drill sites and producing wells by members of our operations staff and internal assessments of our compliance procedures. We consider the cost of compliance a manageable and necessary part of our business.
Employees
As of December 31, 2005, we had 84 full-time employees. Our staff includes professionals experienced in geology, petroleum engineering, land acquisition and management, finance, energy law and accounting. None of our employees are represented by a union. We have never experienced an interruption in operations from any kind of labor dispute, and we consider the working relationships among the members of our staff to be excellent.
Item 1A.
Item 1A. Risk Factors
Our business involves many risks. The risks factors we consider material to our business are summarized below.
Uncertainty of Profits
The profitability of our oil and gas operations depends upon various factors, many of which are beyond our control. They include:
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natural gas and crude oil prices, which are subject to substantial fluctuations based on supply and demand, seasonality, access to and capacity of transportation facilities, price and availability of alternative fuels, worldwide political and economic conditions, the nature and extent of governmental regulation and taxation and the effect of energy conservation measures;
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future market, economic and regulatory factors that may materially affect our sales of gas production; and
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business and operating practices of our competitors.
Depletion of Oil and Gas Reserves
Unless we continue to acquire additional properties with proved reserves and expand our reserves through successful exploration and development activities, our reserves will decline as they are produced. This, in turn, would reduce cash flow for future growth as well as the assets available to secure financing for part of our capital expenditures.
Dependence on Capital Markets
Our business involves significant ongoing capital requirements. The rate of production from oil and gas properties generally declines as reserves are depleted. Without the capital to fund ongoing development activities,
our proved reserves would decline as oil and gas is produced from our proved developed reserves. Our long term performance and profitability depends not only on developing our existing oil and gas reserves, but also on our ability to find or acquire additional reserves that we can develop and operate efficiently and finance on acceptable terms.
Financial Leverage
We are substantially leveraged, and our ability to repay or refinance our debt will be subject to our future performance and prospects as well as market and general economic conditions beyond our control. We issued $37 million principal amount of convertible notes in December 2005. They will mature in December 2010 unless previously redeemed by us or converted by the holders into our common stock. We also maintain a credit facility secured by liens on all corporate assets. The borrowing base for the facility was raised from $15 million to $35 million during the first quarter of 2006. We may increase the facility for future acquisitions or capital expenditures. Because our business is capital intensive, we will likely be dependent on additional financing to repay our outstanding long term debt at maturity. There can be no assurance that we will be able to secure the necessary refinancing on acceptable terms.
Lack of Dividends on Common Stock
We have never paid cash dividends on our common stock. Our current policy is to retain future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend upon our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant. If we issue any preferred stock, it will be eligible for dividends prior and in preference to our common stock, when and if declared by the board of directors.
Volatility of Market Price for Common Stock
The market price of our common stock could be subject to significant volatility in response to variations in results of operations and other factors. In addition, the equity markets in general or in our industry sector may experience wide price and volume fluctuations that may be unrelated and disproportionate to the operating performance of particular companies, and the trading price of our common stock could be affected by those fluctuations.
Affect of Future Sales on Market Price for Common Stock
Sales of substantial amounts of our common stock could depress its market price. As of December 31, 2005, there were 21,357,628 shares of our common stock issued and outstanding. If all our convertible notes, stock options and warrants outstanding as of that date are converted or exercised, there will be an additional 6,879,578 shares of our common stock outstanding. Most of them are eligible for public resale without restrictions. Sales of substantial amounts of our common stock in the public market, or the perception that substantial sales could occur, could adversely affect prevailing market prices of the common stock.
Listing Requirements for Common Stock
To remain eligible for trading on the Nasdaq National Market, we must meet various requirements, including corporate governance standards, specified shareholders’ equity and a market price above $1.00 per share. If our common stock were to be delisted, liquidity in the common stock would be impaired. Any delisting of our common stock would also be an event of default requiring us to redeem our outstanding convertible notes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.”
Unprofitability of Gold and Silver Properties
Our gold and silver properties in Alaska are undeveloped, dormant and unprofitable. To retain our interests in the properties, we must expend funds each year to maintain the validity of our gold and silver exploration rights. We have no plans to develop these properties independently and instead are seeking either a joint venture partner to
provide funds for additional exploration of the prospects or a buyer for the properties. Our ability to find a strategic partner or buyer will depend on the anticipated profitability of potential production activities as well as the price of gold and silver, which in turn is affected by factors such as inflation, interest rates, currency rates, geopolitical and other factors beyond our control. We have not derived any revenues from our gold and silver properties and may never be able to realize any production revenues or sale proceeds from the properties.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Proved Oil and Gas Reserves
General. This report includes estimates of our proved oil and gas reserves and future net cash flows from those reserves as of December 31, 2005, 2004 and 2003. The reserves were estimated Wright & Company, Inc., independent petroleum engineers (“Wright & Co.”), in accordance with regulations of the Securities and Exchange Commission (the “SEC”), using market or contract prices at the end of each reported period. These prices were held constant over the estimated life of the reserves. The following reserve estimates should be read in conjunction with supplementary disclosure on our oil and gas development and producing activities and oil and gas reserve data included in the footnotes to our consolidated financial statements at the end of this report.
There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of an estimate may justify revision of the estimate. As a result, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.
Reserve Quantities. The following table summarizes the estimates by Wright & Co. of our net proved reserves as of December 31, 2005, 2004 and 2003. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage where the existence and recoverability of reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion.
At December 31, 2005, our proved undeveloped reserves represented 54.3% of our total estimated proved reserves (developed and undeveloped) on an energy equivalent basis, compared to 47.3% of total reserves at December 31, 2004. Estimates of our proved undeveloped reserves are highly dependent on our ability to continue raising the capital needed to sustain the pace of drilling activities at assumed rates. The estimates are therefore subject to considerable uncertainty in view of the historic volatility in domestic natural gas markets and the importance of market strength in attracting investment capital.
Reserve Values. The following table summarizes the estimates by Wright & Co. of future net cash flows from the production and sale of our estimated proved reserves and the present value of those estimated cash flows, discounted at 10% per year, as of December 31, 2005, 2004 and 2003. The estimated future net cash flows are computed after giving effect to estimated future development and production costs, based on year-end costs and assuming the continuation of existing economic conditions. The standardized measure of future net cash flows gives effect to future income taxes on discounted future cash flows based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits.
The prices used in the following estimates were based on prices we received for our oil and gas production at the end of each reported period, without escalation. The prices as of December 31, 2005 had a weighted average of $12.39 per Mcf of natural gas and $54.65 per barrel of crude oil, compared to $6.89 per Mcf and $43.23 per Bbl at December 31, 2004 and $5.34 per Mcf and $31.56 per Bbl at December 31, 2003. The estimates are highly dependent on the year-end prices used in their computation, which reflect unprecedented strength at December 31, 2005. In view of historic volatility in domestic natural gas and crude oil markets, those estimates are subject to considerable uncertainty.
In computing the present value of the estimated future net cash flows, a discount factor of 10% was used in accordance with SEC regulations to reflect the timing of net cash flows. Regardless of the discount rate used, present value is materially affected by assumptions on the timing of future production, which involve a number of uncertainties.
(In thousands)
We have not filed any estimates of our proved oil and gas reserves with any federal authority or agency during the past year other than estimates filed with the SEC in accordance with our reporting obligations under the Securities Exchange Act of 1934 (the “Exchange Act”).
Oil and Gas Properties
Oil and Gas Leases. As of December 31, 2005, we owned oil and gas rights under leases and farmouts covering 60,826 gross (22,171 net) developed acres and 255,789 gross (214,216 net) undeveloped acres, all located onshore within the continental United States. Our oil and gas leases and rights under farmout agreements are for varying primary terms and are generally subject to specified royalty or overriding royalty interests, development obligations and other commitments and restrictions, none of which is expected to materially interfere with our development or operation of these properties. The following table shows our ownership interests under oil and gas leases and farmout agreements, by state, as of December 31, 2005.
(1)
Acres spaced or assignable to productive wells.
(2)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether that acreage contains proved reserves.
Productive Wells. The following table shows, by state, our gross and net productive oil and gas wells as of December 31, 2005. The table does not include 164 gross (86.2320 net) wells that were drilled and successfully tested in at least one primary pay zone by year end but were awaiting installation of gathering lines prior to completion.
Significant Fields. Our producing properties and associated development prospects are concentrated in the southern portion of the Appalachian Basin, primarily in Kentucky. The following table shows estimated proved reserves from our interests in those fields as of December 31, 2005.
Additional information about our significant fields is summarized below. Unless otherwise indicated, well and reserve data is provided as of December 31, 2005.
Leatherwood Field. The Leatherwood Field covers approximately 70,000 acres, extending 41 miles through Letcher, Perry, Leslie and Harlan Counties in eastern Kentucky. Leatherwood is part of the Big Sandy Field, which has produced over 2.5 trillion cubic feet of natural gas since its discovery in 1921. Wells in the Leatherwood Field produce from the Maxon Sand, Big Lime and Devonian Shale formations. We acquired oil and gas drilling rights in this field during 2002 under a farmout agreement covering approximately 100,000 acres, most of which had no gathering line infrastructure at that time. During 2003, we formed a specialized program for drilling 25 exploratory wells to test five primary natural gas pay zones within the Leatherwood Field at depths between 3,500 and 5,300 feet. We retained a 66.67% interest in that program and achieved a 100% success rate. Through subsequent development drilling programs, we drilled an additional 82 wells in Leatherwood through the end of 2005. All of our Leatherwood wells have been completed as producers or successfully tested in at least one primary pay zone. Estimated proved reserves from our interests in this field are 24% proved developed.
The farmout for Leatherwood requires us to drill a total of 200 wells through 2007 and provides the leaseholder with participation rights for up to 50% of the working interest in new wells. During 2005, participation rights in a total of 60 Leatherwood wells were exercised for an average working interest of 28.75%, proportionately reducing our 30% drilling program interest in these wells. During the fourth quarter of 2005, we completed our 23-mile, eight-inch steel gathering line for connecting our wells in the Leatherwood Field. As of the date of this report, we have connected 78 wells in the field, with an additional 62 Leatherwood wells awaiting connection. We expect to bring most of those wells on line during the next several months.
Arkoma-CDX Field. The Arkoma-CDX Field is a coalbed methane project covering approximately 14,000 acres in the Arkoma Basin within Sebastian County, Arkansas and Leflore County, Oklahoma. Initial development of the project began in 2001 through a joint venture between CDX Gas, LLC, with a 75% stake, and Dart Energy Corporation, with a 25% interest. The joint venture drilled a total of 15 vertical and 33 horizontal CBM wells, with average daily gross production slightly over 7.0 Mmcf at November 1, 2005. Effective as of that date, we acquired Dart Energy’s 25% interest in the Arkoma-CDX Field, including its 25% interest in the gathering system for the project area. See “Business - Recent Initiatives - Properties Acquisition.” Earlier in the fourth quarter of 2005, we entered into a farmout agreement with CDX for 90% of its majority (75%) interest in 32 drilling locations on the Arkoma-CDX acreage, including 16 PUDs. Under the terms of the farmout agreement, we assumed 100% of future developments costs attributable to the CDX working interest and granted CDX 25% carried working interest, increasing to 50% after payout of project wells. Combined with our interests from the Dart Energy acquisition, our CDX farmout gives us an oveall position of approximately 73% in future development of the Arkoma-CDX Field. As of the date of this report, we have drilled horizontal wells on five of the PUD locations, all successfully, through a specialized drilling program and have identified an additional 19 PUD locations in this field. Estimated proved reserves from our interests in the Arkoma-CDX Field are 41% proved developed.
Amvest Field. The Amvest Field spans portions of Harlan County, Kentucky and Lee County, Virginia. We acquired our interests covering approximately 35,000 acres in the field from SME in October 2004. The Amvest Field produces from the Big Lime, Weir Sand and Devonian Shale formations at depths between 3,800 and 5,500 feet. Oil is also produced from the Weir Sand. We have interests in 58 wells in this field. We operate all the wells and produce all natural gas in the field through the Stone Mountain gathering system. Our interests in the field are subject to an ongoing 4-well annual drilling commitment. Estimated proved reserves from our interests in the Amvest Field are 67% proved developed.
Martin’s Fork Field. The Martin’s Fork Field covers approximately 40,000 acres in Harlan Counties, Kentucky. We acquired our interests in the field from SME in October 2004. The Martin’s Fork Field produces from the Big Lime, Devonian Shale and Clinton formations at depths between 3,200 and 6,500 feet. Oil is also produced from the Big Lime. We have interests in 72 wells in this field. We operate all the wells and produce all natural gas in the field through the Stone Mountain gathering system that we operate for Duke Energy. Two of the leases we acquired in the Martin’s Fork Field have ongoing 2-well annual drilling commitments. Estimated proved reserves from our interests in the Martin’s Fork Field are 60% proved developed.
Straight Creek Field. The Straight Creek Field is located adjacent to the Big Sandy Gas Field on the north side of the Pine Mountain Fault System in Bell and Harlan Counties, Kentucky. We have interests in a total of 22,500 acres in the Straight Creek Field. We have drilled 127 wells in this field, including 52 wells added in 2005, at depths between 3,200 and 4,700 feet, producing from the Maxon Sand, Big Lime, Devonian Shale, Corniferous and Big Six Sand formations. We operate all of the wells in this field. We also operate a 16-mile gathering system we completed in 2005 to enhance our Straight Creek wells through compression into the Stone Mountain system. Estimated proved reserves from our interests in the Straight Creek Field are 37% proved developed.
Kay Jay Field. The Kay Jay Field spans portions of Knox and Bell Counties in eastern Kentucky. Our interests in the field include drilling rights on approximately 11,000 acres acquired as a farmout in 1996, with an ongoing 4-well annual drilling commitment. We subsequently assembled oil and gas leases covering an additional 3,000 acres in this field. The Kay Jay Field produces natural gas from the Maxon Sand, Big Lime, Borden, Devonian Shale and Clinton formations at depths ranging from 2,200 to 3,200 feet. Oil is also produced from the Maxon Sand. We have drilled 150 natural gas wells in this field, including four wells added in 2005. We operate all those wells and own all of the gathering systems for their production. The gathering systems for our wells in the Kay Jay Field are connected to the Columbia Natural Resources (“CNR”) and Delta Natural Gas Company pipeline systems. Estimated proved reserves from our interests in the Kay Jay Field are 54% proved developed.
Fonde Field. The Fonde Field spans portions of Bell County, Kentucky and Claiborne County, Tennessee. We acquired part of our position in this field under a 10-year lease through 2010 covering 12,300 acres in the Tennessee portion of this field, which lies just northeast of the Days Chapel Field, formerly one of the most prolific oil fields in Tennessee. The Fonde Field produces natural gas from the Big Lime and Devonian Shale formations and crude oil from the Big Lime formation. We have drilled 31 natural gas wells in this field. We operate all those wells and own the gathering systems for their production. The gathering systems connect our wells in the Fonde Field to the CNR pipeline system. Estimated proved reserves from our interests in the Fonde Field are 88% proved developed.
Gold and Silver Properties
We own rights to gold and silver properties located on Unga Island, one of the Shumagin Islands on the easterly island group in the Aleutian Chain, 579 miles southwest of Anchorage, Alaska. The mining properties cover approximately 381 acres situated over ten miles by boat from the nearest commercial harbor. Our interests in these properties are comprised of various federal patented lode and mill site claims covering approximately 280 acres and several State of Alaska mining claims covering approximately 101 acres. There are no defined mineral reserves for either of these claims. Although we are required to expend funds to maintain our interests in these claims, we stopped all exploratory work on the properties in 1996 and elected to write off their remaining carrying value for accounting purposes in 2000.
We have no plans for developing our gold and silver properties internally. Any efforts to develop the properties would require substantial expenditures for surface and underground diamond drilling, rehabilitation and equipping of existing mine shafts and workings, level rehabilitation and geologic sampling and mapping. Our
objective is to monetize our interests in these properties by seeking a joint venture partner to either provide funds for developing the prospects or to acquire them from us. Our ability to implement this strategy will depend on price expectations for gold and silver as well as a variety of other geological and market factors beyond our control.
Office Facilities
We lease 9,127 square feet of commercial space for our principal and administrative offices in Lexington, Kentucky at monthly rents ranging from $13,509 to $13,909 through the end of the lease term in February 2008. This reflects an extension of the lease term and expansion of the leased space under a lease modification we implemented during the last two years.
Item 3.
Item 3. Legal Proceedings
We are involved in several legal proceedings incidental to our business, none of which is considered to be material to our consolidated financial position, results of operations or liquidity.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No proposals were submitted for approval by our shareholders during the fourth quarter of 2005.
Part II
Item 5.
Item 5. Market for Common Stock and Related Security Holder Matters
Trading Market
Since January 2006, our common stock has traded on the Nasdaq National Market in the United States under the symbol “NGAS.” Our common stock was previously traded on the Nasdaq SmallCap Market under the same symbol. There is no trading of the common stock in Canada. The following table sets forth, for the periods indicated, the range of high and low bid prices for the common stock and average daily trading volume as reported by Nasdaq. These quotations represent inter-dealer prices, without mark-ups or commissions, and they may not necessarily correspond to actual sales prices.
Security Holders
As of March 7, 2006, there were 2,909 holders of record of our common stock. We estimate there were approximately 7,500 beneficial owners of our common stock as of that date.
Dividend Policy
We have never paid cash dividends on our common stock. Our current policy is to retain any future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend on our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant.
Item 6.
Item 6. Selected Financial Data
The following table presents our summary selected consolidated financial data as of and for the five years ended December 31, 2005. The financial data is derived from our audited consolidated financial statements, which have been audited by Kraft, Berger, Grill, Schwartz, Cohen & March LLP, independent auditors. The summary selected consolidated financial data set forth below as of December 31, 2005 and 2004 and for the three years ended December 31, 2005 should be read in conjunction with our consolidated financial statements and related notes included at the end of this report and with the discussion following the table, which presents management’s analysis of events, factors and trends with an important effect or prospective impact on our financial condition and results of operations.
(In thousands, except per share data)
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an independent energy company focused on generating and developing natural gas prospects in Appalachia and other regional basins with similar geologic characteristics. Historically, we have conducted most of our drilling initiatives through sponsored drilling programs, maintaining interests as both general partner and investor that range from 20.8% to 30.7% in development programs and up to 66.67% in exploratory and other specialized programs. Through our operating subsidiaries, we also construct and maintain gas gathering systems for our wells and operate natural gas distribution facilities for two communities in Kentucky. All of our direct and indirect subsidiaries are wholly owned, and we account for our interests in drilling programs using the proportionate consolidation method, combining our share of program assets, liabilities, income and expenses with those of our separate operations.
Results of Operations - 2005 and 2004
Revenues. Total revenues for 2005 were $62,228,089, an increase of 30% from $47,980,285 in 2004. Our revenue mix for 2005 was 70% contract drilling, 26% oil and gas production and 4% natural gas transmission and compression. For 2004, our total revenues were derived 85% from contract drilling, 12% from oil and gas production and 3% from natural gas transmission and compression activities.
Contract drilling revenues were $43,787,075 for 2005, up 8% from $40,693,850 in 2004. This reflects both the size and the timing of drilling program financings, from which we derive most of our contract drilling revenues. Upon the closing of drilling program financings, we receive the proceeds as customers’ drilling deposits under turnkey drilling contracts with the programs. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. During 2005, we participated in 155 gross (44.3040 net) natural gas wells. Most of the wells were drilled under our turnkey contracts. All of the wells have been completed as producers or successfully tested in at least one primary pay zone.
Production revenues for 2005 were $16,317,144, an increase of 186% from $5,711,500 in 2004. This reflects an increase of 112% in our production volumes to 1,824 Mmcfe in 2005 from 860.7 Mmcfe in 2004. Part of our growth in production volumes resulted from our acquisitions of producing properties, primarily from SME in October 2004 and Dart Energy in the fourth quarter of 2005. It also reflects added production from new wells brought on line in 2005, including 51 wells connected in our Leatherwood Field during the year. In addition to higher volumes, the growth in production revenues reflects a 35% increase in our average sales price of natural gas (before certain transportation charges) to $9.02 per Mcf in 2005 from $6.70 per Mcf in 2004. Principal purchasers of our natural gas production are gas marketers and customers with transmission facilities near our producing properties. During 2005, approximately 30% of our natural gas production was sold under fixed-price contracts and the balance primarily at prices determined monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues increased 35% to $2,123,870 in 2005, compared to $1,574,935 in 2004. This reflects continued reliance by sponsored drilling programs on our gathering systems. During 2005, we extended our natural gas gathering systems for new wells by over 140 miles. Our gas transmission and compression revenues for also reflect a contribution of $323,159 from gas utility sales, compared to $320,162 in the prior period.
Expenses. Total direct expenses increased by 22% to $40,477,412 for in 2005, compared to $33,046,624 in 2004. Our direct expense mix for 2005 was 86% contract drilling, 10% oil and gas production and 4% natural gas transmission and compression. For 2004, our total direct expenses were incurred 90% in contract drilling, 7% in oil and gas production and 3% in natural gas transmission and compression.
Contract drilling expenses in 2005 were $34,731,234 or 79% of contract drilling revenues, compared to $29,620,335 or 73% of contract drilling revenues in 2004. This primarily reflects the substantial level and complexity of recent drilling activities under our turnkey drilling contracts with sponsored drilling programs. It also reflects substantial costs for downhole problems on several wells during 2005 and costs incurred to add lifting equipment and surface facilities for handling oil produced from a number of recently completed wells, primarily in our Straight Creek Field.
Production expenses were $4,157,356 in 2005, compared to $2,413,375 in 2004, reflecting our substantial growth in production volumes. In addition to lifting costs, production expenses include field operating and maintenance costs, related overhead, third-party transportation fees and lease operating expenses. As a percentage of oil and gas production revenues, production expenses decreased to 25% in 2005 from 42% in 2004.
Gas transmission and compression expenses in 2005 were $1,588,822, compared to $1,012,914 in 2004. Gas transmission and compression expenses do not reflect capitalized costs of $12,796,342 in 2005 for extensions of our gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.
Selling, general and administrative (“SG&A”) expenses were $11,251,759 in 2005, an increase of 14% from $9,848,139 in 2004. The increase in SG&A expenses primarily reflects the timing and extent of our selling and promotional costs for sponsored drilling programs. The higher SG&A expenses for 2005 also reflect costs for
supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased compensation and other employee related expenses. As a percentage of total revenues, SG&A expenses decreased to 18% in 2005 compared to 21% in the prior year.
Beginning in 2004, we adopted the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. In addition to accruals for deferred compensation costs of $467,633 in 2005 and $368,935 in 2004, we recognized non-cash charges of $806,423 in 2005 from fair value accounting for employee stock options, compared to $374,161 recognized in 2004.
Depreciation, depletion and amortization (“DD&A”) increased 152% to $4,750,134 in 2005, compared to $1,886,965 in 2004. The increase in DD&A reflects substantial additions to our oil and gas properties and gas gathering systems during 2005, as well as our SME acquisition in October 2004.
Interest expense for 2005 was $1,725,250, up 153% from $682,235 in 2004. This reflects increased overall debt to support ongoing drilling and gas gathering initiatives. We also had higher variable rates for our bank debt in 2005. See “Liquidity and Capital Resources” below.
Net income before income tax expense was $2,819,191 in 2005, compared to $3,505,456 in 2004. We recognized income tax expense of $1,866,435 in 2005, most of which was recorded as a future tax liability, reflecting application of a 15% allocation of intangible drilling costs (“IDC”) from our 2005 development drilling programs at the U.S. operating company level.
Net Income and EPS. We realized net income of $952,756 in 2005, compared to $1,611,701 in 2004, reflecting the foregoing factors. Basic earnings per share (“EPS”) was $0.05 based on 17,350,550 weighted average common shares outstanding in 2005, compared to $0.12 based on 13,994,283 weighted average common shares outstanding in 2004. On a fully diluted basis, EPS was $0.05 on 19,126,555 weighted average common shares outstanding in 2005, compared to $0.10 on 16,467,584 weighted average common shares outstanding in 2004.
2004 and 2003
Revenues. Total revenues for 2004 were $47,980,285, an increase of 75% from $27,444,433 in 2003. Our revenue mix for 2004 was 85% contract drilling, 12% oil and gas production and 3% natural gas transmission and compression. For 2003, our total revenues were derived 86% from contract drilling, 9% from oil and gas production and 5% from natural gas transmission and compression activities.
Contract drilling revenues were $40,693,850 for 2004, up 72% from $23,640,000 in 2003. This reflects both the size and the timing of drilling program financings. During 2004, we participated in 155 gross (49.7149 net) natural gas wells, including 148 gross (47.3953 net) wells drilled under our turnkey contracts, compared to 89 gross (26.7680 net) natural gas wells in 2003.
Production revenues were $5,711,500 in 2004, an increase of 124% from $2,550,040 in 2003. This reflects an increase of 77% in our production volumes to 860.7 Mmcfe in 2004 from 485.9 Mmcfe in 2003. It also reflects a 26% increase in our average sales price of natural gas (before certain transportation charges) to $6.70 per Mcf in 2004 from $5.31 per Mcf in 2003. During 2004, approximately 45% of our natural gas production was sold under fixed-price contracts and the balance primarily at prices determined monthly under formulas based on prevailing market indices.
Gas transmission and compression revenues were $1,574,935 in 2004, up 26% from $1,254,393 in 2003. This primarily reflects increased reliance on our own gathering systems for our new wells. During 2004, we extended our natural gas gathering systems for new wells by approximately 59 miles. Our gas transmission and compression revenues for 2004 also reflect a contribution of $320,162 from gas utility sales, up 12% from $285,741 in 2003.
Expenses. Total direct expenses increased by 140% to $33,046,624 in 2004 compared to $13,753,497 in 2003. Our direct expense mix for 2004 was 90% contract drilling, 7% oil and gas production and 3% natural gas transmission and compression. For 2003, our total direct expenses were incurred 89% in contract drilling, 7% in oil
and gas production and 4% in natural gas transmission and compression.
Contract drilling expenses were $29,620,335 in 2004, an increase of 143% from $12,207,772 in 2003. This primarily reflects the substantial level of drilling activities on behalf of our sponsored drilling programs, as well as an increase of approximately 600 feet in the average depth of our new wells. The greater depth of these wells adds incrementally to the variable costs paid to outside contractors and to well completion complexities and expenditures. The greater depth also adds to steel casing requirements, prices for which increased by over 60% in 2004.
Production expenses increased 152% to $2,413,375 in 2004, compared to $958,081 in 2003, reflecting our substantial growth in production volumes. As a percentage of oil and gas production revenues, production expenses increased to 42% in 2004 from 38% in 2003.
Gas transmission and compression expenses in 2004 were $1,012,914, an increase 72% from $587,644 in 2003. As a percentage of gas transmission and compression revenues, these expenses increased to 64% in the 2004 from 47% in 2003. Gas transmission and compression expenses do not reflect capitalized costs of $5,412,421 in 2004 for extensions of our gas gathering systems and compression capacity required to bring new wells on line.
SG&A expenses were $9,848,139 in 2004, an increase of 31% from $7,532,554 in 2003. The increase in SG&A expenses was mainly from the extent and timing of selling and promotional costs we incurred for the drilling program financings completed at the end of 2003 and in 2004. The higher SG&A expenses for 2004 also reflect costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure. With the expansion of our operations, we also achieved various economies of scale, reflected by a decrease in SG&A expenses as a percentage of total revenues to 21% in 2004 compared to 27% in 2003.
In 2004, we recognized $374,161 from fair value accounting for employee stock options, together with an accrual of $368,935 for deferred compensation costs. We also restated our results for 2003 to record compensation cost of $742,800, which included a previously reported compensation charge of $589,200 from the exercise of employee stock options with a stock-for-stock or “cashless” exercise feature and from the issuance of common stock purchase warrants for corporate consulting services.
DD&A increased 107% to $1,886,965 in 2004 from $911,089 in 2003. The increase in DD&A reflects additions to oil and gas properties, gas gathering systems and related equipment, as well as increased depletion from wells added in property acquisitions during 2004.
Interest expense for 2004 was $682,235, up 38% from $493,441 in 2003. This reflects higher total debt to support our SME acquisition in October 2004, when we added $14.7 million of bank debt and $6.1 million of convertible debt. See “Liquidity and Capital Resources” below.
In November 2004, we received $2.0 million from the sale of 75% of the royalty interests included in a property acquisition completed earlier in the year. In connection with the property acquisition, the parties had allocated $600,000 of the purchase price for the properties to the total royalty interests. As a result, we realized a pre-tax gain of $1.55 million in the fourth quarter of 2004 on the sale of the partial royalty interests.
We recognized income tax expense of $1,893,755 in 2004, of which $1,795,785 was recorded as a future tax liability. Our current income tax expense for 2004 was reduced to $97,970, primarily from our proportionate (66.7%) share of IDC from an exploratory drilling program for the Leatherwood Field and a 15% allocation of IDC from our 2004 development drilling programs. The 15% functional allocation of IDC from development drilling programs was initiated in 2004 to compensate for our full utilization of all loss carryforwards at the DPI level in 2003.
Net Income and EPS. We realized net income of $1,611,701 in 2004, compared to $3,660,140 in 2003, reflecting the foregoing factors. Basic EPS was $0.12 based on 13,994,283 weighted average common shares outstanding in 2004, compared to $0.46 per share based on 8,032,647 weighted average common shares outstanding in 2003. On a fully diluted basis, EPS was $0.10 on 16,467,584 weighted average common shares outstanding in 2004, compared to $0.33 on 11,711,399 weighted average common shares outstanding in 2003.
Liquidity and Capital Resources
Liquidity. Net cash provided by our operating activities in 2005 was $19,499,092. Our cash position during the year was decreased by the use of $43,318,271 in investing activities, reflecting net additions of $41,661,586 to our oil and gas properties. These investments were funded in part with net cash of $35,914,059 from financing activities, comprised primarily of proceeds from convertible note financings of $6,168,696 in the first quarter and $37,000,000 in the fourth quarter of 2005, as well as the exercise of outstanding warrants and options throughout the year. Financing activities also reflect the repayment of our credit facility during the fourth quarter of 2005. See “Capital Resources” below. As a result of these activities, net cash increased to $23,944,252 at December 31, 2005 from $11,849,372 at December 31, 2004.
Net cash provided by our operating activities in 2004 was $7,267,556. Our cash position during 2004 was decreased by the use of $52,691,249 in investing activities, reflecting net additions of $53,755,431 to our oil and gas properties. These investments were funded in part with proceeds from institutional private placements of our common stock and convertible notes and from bank borrowings. See “Capital Resources” below. As a result of these activities, net cash decreased from $22,594,993 at December 31, 2003 to $11,849,372 at December 31, 2004.
As of December 31, 2005, we had a working capital deficit of $863,932. This reflects wide fluctuations in our current assets and liabilities from the timing of customers’ deposits and expenditures under turnkey drilling contracts with our drilling programs. Since these fluctuations are normalized over relatively short time periods, we generally do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of 2005 is not expected to have an adverse effect on our financial condition or results of operations in future periods.
Capital Resources. Our business involves significant capital requirements. The rate of production from oil and gas properties generally declines as reserves are depleted. Without successful development activities, our proved reserves would decline as oil and gas is produced from our proved developed reserves. Our long term performance and profitability is dependent not only on developing existing oil and gas reserves, but also on our ability to find or acquire additional reserves on terms that are economically and operationally advantageous. To fund our ongoing reserve development and acquisition activities, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities, as well as participation by outside investors in our sponsored drilling programs.
We issued several series of convertible notes in private placements to finance a substantial part of our drilling and acquisition activities, including 7% convertible notes in the aggregate principal amounts of $6,168,696 in the first quarter of 2005 and $7,931,304 in 2004. The notes were convertible at the option of the holders into our common stock at $6.00 per share. During 2005, all the unconverted 7% notes and prior series of notes were converted by their holders, either voluntarily or in response to our redemption calls, resulting in the issuance of 3,439,478 common shares.
In December 2005, we completed an institutional private placement of our 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible at the option of the holders at a conversion price of $14.34 per share. As part of private placement, we also issued warrants entitling the holders to purchase up to 945,809 shares of our common stock prior to August 11, 2006 at an exercise price of $13.04 per share. At December 31, 2005, the notes were recorded at $34,605,087, reflecting an allocation of $2,394,913 based on equity components of their conversion features and the related warrants. The conversion price of the notes and exercise price of the warrants are subject to adjustments for certain dilutive issuances of common stock. The purchase agreement for the notes also provides the holders with certain participation rights in future financing transactions and provides for us to use our best efforts to obtain shareholder approval at the next annual meeting for the issuance of the notes, warrants and underlying common shares.
Under the terms of our 6% convertible notes, if a holder elects to convert a note before the second anniversary of the issuance date, unless the prevailing market price of the common stock exceeds 160% of the conversion price, the holder will be entitled to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, payable at our option in cash or in common shares. After that date, if the prevailing market price of the common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Any
notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.
We maintain a credit facility with KeyBank NA with a scheduled maturity date of July 31, 2007. The facility is secured by liens on all corporate assets, including a first mortgage on oil and gas interests and pipelines, as well as an assignment of major production and transportation contracts. The interest rate under the facility fluctuates at 1% above the bank’s prime rate, amounting to 8.25% at December 31, 2005. The maximum credit and borrowing base for the facility are determined periodically by the bank. At December 31, 2005, the maximum credit and borrowing base for the facility were $20 million and $15 million, respectively. Borrowings of $15 million outstanding at December 31, 2004 were repaid in the fourth quarter of 2005. The credit facility was amended in the first quarter of 2006 to increase the maximum credit and borrowing base to $75 million and $35 million, respectively. The amendment also provides for a reduction of the interest rate for borrowings under the facility to 0.875% above the bank’s prime rate.
Our ability to repay our bank debt and convertible notes will be subject to our future performance and prospects as well as market and general economic conditions. We may be dependent on additional financings to repay our outstanding long term debt at maturity.
Our future revenues, profitability and rate of growth will continue to be substantially dependent on the demand and market price for natural gas. Future market prices for natural gas will also have a significant impact on our ability to maintain or increase our borrowing capacity, to obtain additional capital on acceptable terms and to continue attracting investment capital to drilling programs. The market price for natural gas is subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control.
We expect our cash reserves and cash flow from operations to provide adequate working capital to meet our capital expenditure objectives through the middle of 2006, including our pending gathering system acquisition and anticipated contributions to drilling programs. See “Business - Recent Initiatives - Gathering System Acquisition” and “ - Drilling Programs.” To fully realize our financial goals for growth in revenues and reserves, we will continue to be dependent on the capital markets or other financing alternatives as well as continued participation by investors in future drilling programs.
Forward Looking Statements
Some statements made by us in this report are prospective and constitute forward-looking statements with in the meaning of Section 21E of the Exchange Act. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate (and other similar expressions) are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. Among other things, these include:
•
uncertainty about estimates of future natural gas production;
•
increases in the cost of drilling, completion and gas collection or other costs of developing our reserves;
•
unavailability of drilling rigs and services;
•
uncertainty of production costs and estimates of required capital expenditures;
•
drilling, operational and environmental risks;
•
commodity price fluctuations;
•
regulatory changes and litigation risks; and
•
uncertainties in estimating proved oil and gas reserves, projecting future rates of production and timing of development and remedial expenditures.
If the assumptions we use in making forward-looking statements prove incorrect or the risks described in this report occur, our actual results could differ materially from future results expressed or implied by the forward-looking statements.
Financial Market Risk
Interest Rate Risk. Our secured credit facility was amended in the first quarter of 2006 to increase the available borrowing base to $35 million and reduce the interest rate on borrowing under the facility to 0.875% above the bank’s prime rate. Accordingly, interest expense on future borrowings under the facility will be sensitive to changes in the general level of interest rates in the United States. Any substantial borrowings under the facility would expose us to this interest rate risk.
Foreign Market Risk. We sell our products and services exclusively in the United States and receive payment solely in United States dollars. As a result, our financial results are unlikely to be affected by factors such as changes in foreign currency exchange rates or weak economic conditions in foreign markets.
Contractual Obligations and Commercial Commitments
We are parties to leases for office facilities and various types of equipment. We are also obligated to make payments at specified times and amounts under instruments governing our long term debt and other commercial commitments. The following table lists our minimum annual commitments as of December 31, 2005 under these instruments.
(1)
Reflects obligations under a guaranty secured by a certificate of deposit provided for bank debt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held a minority interest.
(2)
Reflects commitments under a purchase contract for an airplane.
Related Party Transactions
Because we operate through subsidiaries and affiliated drilling programs, our holding company structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. It is our policy to structure any transactions with related parties only on terms that are no less favorable to the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions are summarized in Notes 4 and 14 of the footnotes to the consolidated financial statements and related disclosure included elsewhere in this report.
Critical Accounting Policies and Estimates
General. The preparation of financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, management evaluates its estimates, including evaluations of any allowance for doubtful accounts and impairment of long-lived assets. Management bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. The results of these evaluations form a basis for making judgments about the carrying value of assets and liabilities that are not
readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, management believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The following critical accounting policies relate to the more significant judgments and estimates used in the preparation of our consolidated financial statements.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts when deemed appropriate to reflect losses that could result from failures by customers or other parties to make payments on our trade receivables. The estimates of this allowance, when maintained, are based on a number of factors, including historical experience, aging of the trade accounts receivable, specific information obtained on the financial condition of customers and specific agreements or negotiated amounts with customers.
Impairment of Long-Lived Assets. Our long-lived assets include property and equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, while other long-lived assets are reviewed whenever events or changes in circumstances indicate that carrying values of these assets are not recoverable.
Item 7A.
Item 7A. Quantitative Disclosure About Market Risk
None
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Our management, with the participation or under the supervision of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the Company in accordance with the requirements of the Exchange Act. Our disclosure controls and procedures are intended to provide a framework for making sure that all information required to be disclosed in our current and periodic reports under the Exchange Act is processed and publicly reported by us within the prescribed time periods for our filing of those reports. Our internal controls over financial reporting are designed to ensure the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. They include policies and procedures for maintaining reasonably detailed records that accurately and fairly reflect all our business transactions and dispositions of assets, for ensuring that receipts and expenditures are made only in accordance with management authorizations and for preventing or timely detecting any unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of our disclosure controls and procedures and our internal control over financial reporting as of December 31, 2005. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective to ensure that material information about our business and operations is recorded, processed, summarized and publicly reported within the time period required under the Exchange Act. They have also concluded that our internal controls over financial reporting are effective to ensure the reliability of our financial reporting and the preparation of our publicly reported financial statements in accordance with generally accepted accounting principles. Our independent registered public accounting firm, Kraft, Berger, Grill, Schwartz, Cohen & March, LLP, has audited our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, as stated in their report appearing on page.
There were no changes in our controls or procedures during 2005 that have materially affected or are reasonably likely to materially affect our internal control of financial reporting.
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors and Executive Officers; Compliance with Section 16(a) of the Exchange Act
Executive Officers
Our executive officers are listed in the following table, together with their age and term of service with the Company or DPI.
A summary of the business experience and background of our directors and executive officers is set forth below.
William S. Daugherty has served as our President, Chief Executive Officer and member of our board of directors since September 1993, as well as our Chairman of the Board since 1995. He has also served as President of DPI between 1984 and 2005 and as Chairman of the Board of DPI since September 2005. Mr. Daugherty currently serves as the Governor of Kentucky’s Official Representative to the Interstate Oil and Gas Compact Commission and as a member of the Board of Directors of the Independent Petroleum Association of America. He is a past president of the Kentucky Oil and Gas Association (“KOGA”) and the Kentucky Independent Petroleum Producers Association. Mr. Daugherty holds a B.S. Degree from Berea College, Berea, Kentucky.
William G. Barr, III has served as a Vice President of the Company since 2004 and as a Vice President of DPI between 1993 and September 2005, when he was appointed as Chief Executive Officer of DPI. Mr. Barr has more than 30 years’ experience in the corporate and legal sectors of the oil and gas industry, having served in senior management positions in oil and gas exploration and production companies and as an attorney with a significant natural resource law practice. Mr. Barr currently serves as Governing Member Trustee for the Energy & Mineral Law Foundation. He also serves as President-Elect of KOGA and as a member of its Board of Directors and Chairman of its Legislative Committee, as well as Vice Chairman of the Kentucky Gas Pipeline Authority. Mr. Barr received his Juris Doctorate from the University of Kentucky.
D. Michael Wallen has served as a Vice President of the Company since 1997 and as a Vice President of DPI between 1995 and September 2005, when he was appointed as President of DPI. For six years before joining DPI, he served as the Director of the Kentucky Division of Oil and Gas. Mr. Wallen has more than 25 years’ experience as a drilling and completion engineer for various exploration and production companies. He recently served as President of KOGA and currently serves on its Board of Directors and Executive Committee. He has also served as President of the Eastern Kentucky Section of the Society of Petroleum Engineers and as the Governor’s Representative to the Interstate Oil & Gas Compact Commission. Mr. Wallen holds a B.S. Degree from Morehead State University, Morehead, Kentucky.
Michael P. Windisch has served as our Chief Financial Officer since September 2002. Prior to that time, Mr. Windisch was employed by PricewaterhouseCoopers LLP, participating for five years in the firm’s audit practice. He is a member of the American Institute of Certified Public Accountants and holds a B.S. Degree from Miami University, Oxford, Ohio.
Incorporation of Information by Reference
The balance of Part III to this report is incorporated by reference to the proxy statement for our 2006 annual meeting of shareholders to be filed with the Securities and Exchange Commission on or before May 1, 2006.
Item 15.
Item 15. Exhibits
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, NGAS Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 13, 2006.
NGAS RESOURCES, INC.
By:
/s/ William S. Daugherty
By:
Michael P. Windisch
William S. Daugherty,
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
(Principal executive officer)
(Principal financial and accounting officer)
In accordance with the Exchange Act, this report has been signed as of the date set forth below by the following persons in their capacity as directors of the NGAS Resources, Inc.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process defined by or under the supervision of the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. They include policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control - Integrated Framework. Based on our assessment, management has concluded that, as of December 31, 2005, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, Kraft, Berger, Grill, Schwartz, Cohen & March, LLP, has audited our assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, as stated in their report appearing on page.
/s/ William S. Daugherty
/s/ Michael P. Windisch
William S. Daugherty,
Michael P. Windisch,
President and Chief Executive Officer
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of
NGAS RESOURCES, INC.
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting that NGAS RESOURCES, INC. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. NGAS RESOURCES, INC.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements of external purposes in accordance with accounting principles generally accepted in Canada. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that NGAS RESOURCES, INC. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also in our opinion, NGAS RESOURCES, INC. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of operations, changes in shareholders’ equity and cash flows of NGAS RESOURCES, INC., and our report dated March 6, 2006 expressed an unqualified opinion.
KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
Chartered Accountants
Toronto, Ontario
March 6, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of
NGAS RESOURCES, INC.
We have audited the consolidated balance sheets of NGAS RESOURCES, INC. as at December 31, 2005 and 2004 and the consolidated statements of operations, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated 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 the standards of the Public Company Accounting Oversight Board (United States) and with generally accepted auditing standards in Canada. Those standards require that we plan and perform an audit to obtain reasonable assurance 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, these consolidated financial statements present fairly, in all material respects, the consolidated financial position of the company as at December 31, 2005 and 2004 and the results of its operations, changes in shareholders’ equity and its cash flows for each of the years in the three-year period ended December 31, 2005 in conformity with accounting principles generally accepted in Canada.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NGAS RESOURCES, INC.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2006 expressed an unqualified opinion thereon.
KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
Chartered Accountants
Toronto, Ontario
March 6, 2006
NGAS Resources, Inc.
CONSOLIDATED BALANCE SHEETS
(U.S. Funds)
See Notes to Consolidated Financial Statements.
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(U.S. Funds)
See Notes to Consolidated Financial Statements.
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(U.S. Funds)
See Notes to Consolidated Financial Statements
NGAS Resources, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(U.S. Funds)
See Notes to Consolidated Financial Statements.
NGAS Resources, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2005, 2004 and 2003
Note 1. Summary of Significant Accounting Policies
(a) General. The accompanying consolidated financial statements of NGAS Resources, Inc., a British Columbia corporation (the “Company”), have been prepared in accordance with accounting principles generally accepted in Canada. See Note 17 - United States Accounting Principles. All funds are stated in U.S. dollars.
(b) Basis of Consolidation. The consolidated financial statements include the accounts of the Company, its wholly owned subsidiary, Daugherty Petroleum, Inc. (“DPI”), a Kentucky corporation, and DPI’s wholly owned subsidiaries, Sentra Corporation (“Sentra”), NGAS Securities, Inc. (“NGAS Securities”) and NGAS Gathering, LLC (“NGAS Gathering”). DPI conducts all of the Company’s oil and gas drilling and production operations. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky. NGAS Securities provides marketing support services for private placement financings by the Company and DPI. NGAS Gathering operates gas gathering systems. The consolidated financial statements also reflect DPI’s interests in a total of 30 drilling programs that it has sponsored to conduct drilling operations on its prospects (the “Drilling Programs”). DPI maintains a combined interest as both general partner and an investor in each Drilling Program ranging from 20.8% to 66.67%, subject to specified increases after certain distribution thresholds are reached. The Company accounts for those interests using the proportionate consolidation method, combining DPI’s share of assets, liabilities, income and expenses of the Drilling Programs with those of its separate operations. All material inter-company accounts and transactions for the years presented in the consolidated financial statements have been eliminated on consolidation.
(c) Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in Canada requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the balance sheet date and the reported amounts of revenues and expenses during the years presented in the consolidated financial statements. Actual results could differ from those estimates.
(d) Oil and Gas Properties.
(i) Accounting Treatment for Costs Incurred. The Company follows the successful efforts method of accounting for its oil and gas activities. Accordingly, property acquisition costs, development costs and the cost of support equipment and facilities are capitalized. Drilling costs for exploratory wells are also capitalized pending determination of proved reserves, but must be charged to expense if no proved reserves are found within one year after completion of drilling. The Company has found proved reserves for all exploratory wells drilled during the years presented in the consolidated financial statements within one year after completion of drilling and therefore has not expensed any explanatory drilling costs for those wells. Other exploration costs, including geological and geophysical expenses, leasehold expiration costs and delay rentals, are charged to expense as incurred.
(ii) Depletion. Depletion on developed properties is computed using the units-of-production method, using only the reserves underlying the proved developed oil and gas properties. Estimates of proved oil and gas reserve volumes and values are the primary factors in determining the amount of depletion expense. These estimates involve significant uncertainties.
(iii) 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 the Company’s financial position and results of operations would not be significantly affected from use of the percentage-of-completion method. A contract is considered complete when all remaining costs and risks are relatively insignificant. Oil and gas production revenue is recognized as production is extracted and sold. Other revenue is recognized at the time it is earned and the Company has a contractual right to receive the revenue.
(iv) Regulated Operations of Sentra. Regulated operations of Sentra are subject to the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires regulated entities to record regulatory assets and liabilities resulting from actions of regulators. Kentucky’s Public Service Commission regulates Sentra’s billing rates for natural gas distribution sales. These billing rates are based on the Commission’s evaluation of Sentra’s recovery of its purchased gas costs. For the years ended December 31, 2005 and 2004, gas transmission and compression revenue includes gas utility sales from Sentra’s regulated operations aggregating $323,159 and $320,162, respectively. As of December 31, 2005, Sentra did not have any unrecovered purchased gas costs. If the Company were to discontinue the application of SFAS No. 71 to Sentra’s regulated operations, it would be required to write off its regulatory assets and adjust the carrying amount of any other assets, including property and equipment, used in those operations that would be deemed unrecoverable.
(v) Regulated Operations of NGAS Securities. NGAS Securities is a registered broker-dealer and member of the National Association of Securities Dealers, Inc. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under of the Securities Exchange Act of 1934. Because it does not hold customer funds or securities or owe money or securities to customers, NGAS Securities is required to maintain minimum net capital equal to the greater of $5,000 or one-eighth of its aggregate indebtedness. At December 31, 2005, NGAS Securities had net capital of $110,301 and aggregate indebtedness of $74,627.
(vi) Wells and Related Equipment. Wells and related equipment are recorded at cost and are amortized under the units-of-production method, based on the estimated proved developed reserves of the underlying properties.
(e) Property and Equipment. Property and equipment are stated at cost, amortized on a straight-line basis over the useful life of the assets, ranging from 3 to 25 years. The Company follows Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3063, “Impairment of Long-Lived Assets,” which is the Canadian equivalent of SFAS No. 144 for accounting standards generally accepted in the United States of America. CICA Handbook Section 3063 requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment of a proved oil and gas property would be required to the extent its carrying amount exceeded the undiscounted future net cash flows from the Company’s interest in the property’s estimated proved reserves. Estimates of proved oil and gas reserve volumes and values involve significant uncertainties.
(f) Investments. Long term investments in which the Company does not have significant influence are accounted for using the cost method. In the event of a permanent decline in its value, an investment is written down to estimated realizable value, and any resulting loss is charged to earnings.
(g) Deferred Financing Costs. Financing costs for the Company’s convertible note private placements and secured bank loans are initially capitalized and amortized at rates based on the stated terms of the underlying debt instruments. Upon conversion of its convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs.
(h) Goodwill. Goodwill is tested for impairment at least annually and more frequently if indicated under CICA Handbook Section 3062, “Goodwill and Other Intangible Assets,” which is the Canadian equivalent of SFAS No. 142. See Note 8 - Goodwill. CICA Handbook Section 3062 requires that if the fair value of a reporting unit (including goodwill) is less than its carrying value, the implied fair value of the reporting unit must be compared with its carrying value to determine possible impairment.
(i) Customer Drilling Deposits. Net proceeds received by DPI under turnkey drilling contracts with sponsored Drilling Programs are recorded as customers’ drilling deposits at the time of receipt. The Company recognizes revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits represent unapplied turnkey payments for wells that were not yet drilled as of the balance sheet dates.
(j) Future Income Taxes. The Company provides for income taxes using the asset and liability method, as required by the CICA Handbook Section 3465. This method requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets or liabilities and their tax bases. Future income tax assets and liabilities are determined for each temporary difference based on the tax rates that are assumed to be in effect when the underlying items of income and expense are expected to be realized.
(k) Stock Option Plans. The Company maintains the stock option plans described in Note 10. Effective January 1, 2004, the Company adopted the fair value provisions of CICA Handbook Section 3870, “Stock-Based Compensation and Other Stock-Based Payments,” and related interpretations for the recognition and measurement of compensation costs associated with employee stock options. See Note 10 - Capital Stock.
(l) Deferred Compensation. The Company entered into long term incentive agreements with four executive officers in 2004 and an officer of a subsidiary in 2005. The agreements entitle the officers to incentive awards equal to one year’s compensation if they continue to serve as officers of the Company or its subsidiaries until February 25, 2009 or until their employment is terminated without cause or they resign for good reason following a change of control. Accruals for deferred compensation under these agreements are recorded ratably based on estimated future payments dates and forfeiture rate.
(m) Reclassifications and Adjustments. Certain amounts included in the 2004 consolidated financial statements have been reclassified to conform to the 2005 presentation.
Note 2. Oil and Gas Properties
(a) 2005 Acquisition. Effective November 1, 2005, DPI acquired the coalbed methane assets of Dart Energy Corporation covering approximately 14,000 gross (3,500 net) acres in the Arkoma Basin within Leflore County, Oklahoma and Sebastian County, Arkansas for $11.4 million. The acquired assets included a 25% interest in 48 producing wells. As part of the transaction, NGAS Gathering also acquired a 25% membership interest in a limited liability company that owns and operates the gathering system servicing the project area. The Company accounted for the acquisition under the purchase method.
(b) 2004 Acquisitions. In three separate transactions during 2004, DPI acquired oil and gas interests covering 89,738 acres in Bell, Harlan and Leslie Counties, Kentucky and Lee County, Virginia for a total of $34.8 million. As part of these transactions, DPI assumed future obligations of the sellers under oil and gas leases, farmout agreements and operating contracts. The Company accounted for these acquisitions under the purchase method, allocating the purchase price among the acquired assets as of the respective closing dates. In November 2004, DPI sold 75% of the royalty interests included in one of the acquisitions for $2.0 million. In connection with the property acquisition, the parties had allocated $600,000 of the purchase price for the properties to the total royalty interests. As a result, after accounting for selling costs, the Company realized a gain of $1.55 million in the fourth quarter of 2004 on the sale of the partial royalty interests.
(c) Capitalized Costs. Capitalized costs and accumulated depreciation, depletion and amortization (“ DD&A”) relating to the Company’s oil and gas producing activities, all of which are conducted within the continental United States, are summarized below.
Note 3. Property and Equipment
The following table presents the capitalized costs and accumulated depreciation for the Company’s property and equipment as of December 31, 2005 and 2004.
Note 4. Loans to Related Parties
Loans to related parties represent loans receivable from certain shareholders and officers of the Company. The loans are payable monthly from production revenues for periods ranging from five to ten years, with a balloon payment at maturity. The loans receivable from shareholders aggregated $119,183 at December 31, 2005 and $328,464 at December 31, 2004. They bear interest at 6% per annum and are collateralized by the related parties’ ownership interest in Drilling Programs. The loans receivable from officers totaled $171,429 at December 31, 2005 and 2004. These loans are non-interest bearing and unsecured.
Note 5. Investments
The Company has investments of $119,081 in three series of bonds issued by the City of Galax, Virginia Industrial Development Authority, bearing interest at rates ranging from 7% to 8.25% per annum and maturing through July 1, 2010. The Company recorded a write-down of $63,627 in the carrying value of the bonds to reflect a permanent decline in value during 2004 and an additional write-down of their remaining carrying value during 2005. See Note 17 - United States Accounting Principles.
Note 6. Deferred Financing Costs
The Company incurred financing costs for its convertible note private placements and secured bank loans aggregating $2,821,497 in 2005, $986,478 in 2004 and $601,886 in 2003. See Note 9 - Long Term Debt. These financing costs are initially capitalized and amortized at rates based on the stated terms of the underlying debt instruments. Upon conversion of its convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for convertible notes and bank loans aggregated $2,377,791 at December 31, 2005 and $1,024,810 at December 31, 2004, net of accumulated amortization totaling $378,736 and $116,386, respectively.
Note 7. Goodwill
In connection with the acquisition of DPI in 1993, the Company recorded goodwill of $1,789,564, which was amortized over ten years on a straight-line basis. Unamortized goodwill at December 31, 2001 was $313,177. At the beginning of 2002, the Company adopted CICA Handbook Section 3062, “Goodwill and Other Intangible Assets,” which is the Canadian equivalent of SFAS No. 142 for accounting standards generally accepted in the United States. Under the adopted standard, goodwill is no longer amortized but is instead tested annually for impairment. The Company’s analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of December 31, 2005 and 2004.
Note 8. Customer Drilling Deposits
At the commencement of operations, each Drilling Program acquires drilling rights for specified wells from DPI and enters into a turnkey drilling contract with DPI for drilling and completing the wells at specified prices. Upon the closing of Drilling Program financings, DPI receives the net proceeds from the financings as customers’ drilling deposits under the turnkey drilling contracts. These payments totaled $43,050,000 in 2005 and $31,278,330 in 2004. The Company recognizes revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits of $23,627,975 at December 31, 2005 and $12,652,001 at December 31, 2004 represent unapplied turnkey payments for wells that were not yet drilled as of the balance sheet dates.
Note 9. Long Term Debt
(a) Convertible Notes. The Company has issued several series of convertible notes in private placements to finance a substantial part of its drilling and acquisition activities. One series of notes required the payment of interest in kind through September 30, 2004, resulting in the issuance of additional paid-in-kind notes aggregating $178,924. The notes of each series provided for conversion by the holders into the Company’s common stock at fixed rates (subject to anti-dilution adjustments) and for redemption by the Company generally at 100% of their principal amount plus accrued interest through the date of redemption. During 2005, the notes of all prior series were converted by their holders, either voluntarily or in response to redemption calls by the Company, resulting in the issuance of 3,439,478 common shares during the year. In December 2005, the Company completed an institutional private placement of a new series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million and related common stock purchase warrants. See Note 10 - Capital Stock. Part of the proceeds from the financing were used to acquire CBM assets in the fourth quarter of 2005. See Note 2 - Oil and Gas Properties.
The terms of the Company’s convertible notes outstanding at December 31, 2005 and 2004 are summarized below.
The conversion price of the Company’s notes outstanding at December 31, 2005 is subject to adjustment for certain dilutive issuances of common stock. The purchase agreement for the notes also provides holders with certain participation rights in future financing transactions and provides for the Company to use its best efforts to
obtain shareholder approval at the next annual meeting for issuance of the common shares underlying the notes and related warrants. If a holder elects to convert a note before the second anniversary of the issuance date, unless the prevailing market price of the common stock exceeds 160% of the conversion price, the holder will be entitled to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, payable at the Company’s option in cash or in common shares. After that date, if the prevailing market price of the common stock exceeds 160% of the conversion price, the Company may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.
(b) Credit Facility. The Company maintains a credit facility with KeyBank NA. The facility is secured by liens on all corporate assets, including a first mortgage on oil and gas interests and pipelines, as well as an assignment of major production and transportation contracts. The interest rate under the facility fluctuates at 1% above the bank’s prime rate, amounting to 8.25% at December 31, 2005. The maximum credit and borrowing base are determined periodically by the bank. At December 31, 2005, the maximum credit and borrowing base for the facility were $20 million and $15 million, respectively. Borrowings of $15 million outstanding at December 31, 2004 were repaid in the fourth quarter of 2005. After year end, the facility was amended in the ordinary course to extend the scheduled maturity date, increase the maximum credit and borrowing base and decrease the interest rate. See Note 20 - Subsequent Events.
(c) Acquisition Debt. The Company issued a note for $854,818 to finance its 1986 acquisition of mineral property on Unga Island, Alaska. The debt is repayable without interest in monthly installments of $2,000 and is secured by liens on the acquired property, buildings and equipment. Although the acquisition agreement provides for royalties at 4% of net smelter returns or other production revenues, the property has remained inactive. The remaining acquisition debt was $366,818 at December 31, 2005 and $390,818 at December 31, 2004.
(d) Miscellaneous Debt. The Company’s miscellaneous debt of $97,246 outstanding at December 31, 2004 was retired during 2005.
(e) Total Long Term Debt. The following table summarizes the Company’s total long term debt at December 31, 2005 and 2004.
(f) Maturities of Long Term Debt. The instruments covering the Company’s long term debt outstanding at December 31, 2005 provide for minimum annual principal payments of $24,000 in each year through 2009, with the balance of $37,270,818 scheduled to mature in 2010 and thereafter.
Note 10. Capital Stock
(a) Preferred and Common Shares. The Company’s authorized capital stock consists of 5,000,000 shares of preferred stock, none of which were outstanding at December 31, 2005 or 2004, and 100,000,000 shares of common stock. The following table reflects transactions involving the common stock during the reported periods.
(b) Stock Options and Awards. The Company maintains three stock plans for the benefit of its directors, officers, employees and, in the case of the second and third plans, its consultants and advisors. The first plan, adopted in 1997, provides for the grant of options to purchase up to 600,000 common shares at prevailing market prices, vesting over a period of up to five years and expiring no later than six years from the date of grant. The second plan, adopted in 2001, provides for the grant of options to purchase up to 3,000,000 common shares at prevailing market prices, expiring no later than ten years from the date of grant. The third plan, adopted in 2003,
provides for the grant of stock awards and stock options for an aggregate of up to 4,000,000 common shares. Option grants under all the plans must be exercisable at prevailing market prices and may be subject to vesting requirements over a period of up to ten years from the date of grant. Stock awards under the third plan may be subject to vesting conditions and trading restrictions specified at the time of grant. During 2005 and 2004, stock awards and option grants were made under the third plan for a total of 834,415 shares and 166,489 shares, respectively.
The following table reflects transactions involving the Company’s stock options during 2005 and 2004.
At December 31, 2005, the exercise prices of options outstanding under the Company’s stock option plans ranged from $1.02 to $7.04 per share, and their weighted average remaining contractual life was 3.87 years. The following table provides additional information on the terms of the Company’s stock options outstanding at December 31, 2005.
In accounting for stock options, the Company follows the retroactive method under CICA Handbook Section 3870. The statement requires the fair value method of accounting for stock options, consistent with the recognition and measurement provisions of SFAS Nos. 123 and 148, “Accounting for Stock-Based Compensation.” Under the fair value method, employee stock options are valued at grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. For the periods presented in the consolidated financial statements, the fair value estimates for each option grant assumed a risk free interest rate ranging from 4.5% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to five years based on the option’s vesting provisions. This resulted in non-cash charges for options and warrants of $806,423 in 2005 and $374,161 in 2004, based on weighted average fair values of $2.00 and $0.63, respectively.
(c) Common Stock Purchase Warrants. The Company has issued common stock purchase warrants in various financing transactions. The exercise prices of warrants outstanding at December 31, 2005 ranged from $1.75 to $13.04 per share, and their weighted average remaining contractual life was 0.68 years. The following table reflects transactions involving the Company’s common stock purchase warrants during 2005 and 2004.
Note 11. Income Taxes
The following table sets forth the components of income tax expense for each of the years presented in the consolidated financial statements.
The following table sets forth a reconciliation between prescribed tax rates and the effective tax rate for the Company’s total income tax expense in each of the years presented in the consolidated financial statements.
The following table sets forth the components of the Company’s future income tax liabilities as of the end of each of the years presented in the consolidated financial statements.
As of December 31, 2005, the Company had net operating losses of $11,854,000 at the holding company level. Since no revenues are generated at that level for utilization of the related net operating loss carryforwards, the Company has provided a valuation allowance in the full amount of the net operating losses. The following table summarizes those net operating loss carryforwards by year of expiry.
Note 12. Income Per Share
The Company follows CICA Handbook Section 3500, “Earnings per Share,” using the “treasury stock” method for stock options and warrants and the “if converted” method for convertible instruments in computing both basic and diluted earnings per share (“EPS”). For both 2004 and 2003, the assumed exercise of outstanding stock options and warrants and the assumed conversion of outstanding convertible notes and, for 2003, outstanding preferred stock, would have a dilutive effect on EPS because their exercise or conversion prices were below the average market price of the common stock during the year. For 2005, the assumed exercise of outstanding stock options and warrants would be dilutive for the same reason, but the assumed conversion of outstanding convertible notes would be anti-dilutive because interest per share on the common shares issuable on conversion of the notes exceeded EPS for the year. The following table sets forth the computation of dilutive EPS for each of the years presented.
Note 13. Employee Benefit Plan
On October 1, 2003, the Company established a salary deferral plan under section 401(k) of the Internal Revenue Code. The plan allows all eligible employees to defer up to 15% of their annual compensation through contributions to the plan, with matching contributions by the Company up to 3% of the participating employees’ compensation, plus half of their plan contributions between 3% and 5% of annual compensation. The deferrals accumulate on a tax deferred basis until a participating employee withdraws the funds allowable based on a vesting schedule. The Company’s matching contributions to the plan aggregated $61,765 in 2005, $61,407 in 2004 and $13,232 in 2003.
Note 14. Related Party Transactions
(a) General. Because the Company operates through its subsidiaries and affiliated Drilling Programs, its holding company structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. It is the Company’s policy to structure any transactions with related parties only on terms that are no less favorable to the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions not disclosed elsewhere in these notes are summarized below.
(b) Drilling Programs. DPI invests in sponsored Drilling Programs on substantially the same terms as unaffiliated investors, contributing capital in proportion to its initial partnership interest. DPI also maintains a 1% interest as general partner in each Drilling Program, resulting in a combined interest ranging from 20.8% to 30.7% in its larger Drilling Programs and up to 66.67% in exploratory and other specialized Drilling Programs. The agreements for both types of Drilling Programs generally provide for specified increases in DPI’s program interests, up to 15% of the total program interests, after program distributions reach “payout,” which ranges from 100% to 110% of partners’ investment. The partnership agreements also provide for each Drilling Program to enter into turnkey drilling contracts with DPI for all wells to be drilled by that Drilling Program. The portion of the profit on drilling contracts attributable to DPI’s ownership interest in the Drilling Programs has been eliminated on consolidation for the years presented in the Company’s consolidated financial statements. The following table sets forth the total revenues recognized from the performance of turnkey drilling contracts with sponsored Drilling Programs for each of those years.
Note 15. Financial Instruments
(a) Credit Risk. The Company grants credit to its customers, primarily located in the northeastern and central United States, during the normal course of business. The Company performs ongoing credit evaluations of its customers’ financial condition and generally requires no collateral. At times throughout the year, the Company may maintain certain bank accounts in excess of FDIC insured limits.
(b) Fair Value of Financial Instruments. The carrying values of cash, accounts receivable, other receivables, accounts payable, accrued liabilities and customer drilling deposits approximate fair value due to their short-term maturity. Bonds and deposits, loans receivable and payable and other long term debt payable approximate fair value since they bear interest at variable rates. The following table sets forth the financial instruments with a carrying value at December 31, 2005 different from their estimated fair value, based upon discounted future cash flows using discount rates reflecting market conditions for similar instruments.
Note 16. Segment Information
The Company has two reportable segments based on management responsibility and key business operations. The summary of significant accounting policies in Note 1 applies to both reported segments. The following table presents summarized financial information for the Company’s business segments during each of the years presented in the consolidated financial statements.
Note 17. United States Accounting Principles
(a) Differences Reflected in Consolidated Financial Statements. The Company follows accounting principles generally accepted in Canada (“Canadian GAAP”), which are different in some respects than accounting principles generally accepted in the United States of America (“U.S. GAAP”). The only differences that would affect the accompanying consolidated financial statements involve the reporting of comprehensive income and the accounting treatment of the Company’s investment in municipal bonds described in Note 5, which would be reportable at fair value under U.S. GAAP. This would have no effect on the Company’s consolidated statements of cash flows for the years reported but would affect shareholders’ equity and net income, as reported under Canadian GAAP. The effects of differences in these accounting principles are reflected in the following reconciliation:
Comprehensive income under U.S. GAAP would be as follows:
(b) Recent Accounting Pronouncements - Canadian GAAP. Recent accounting pronouncements affecting the Company’s financial reporting under Canadian GAAP are summarized below.
(i) Financial Instruments. In January 2005, the CICA issued Handbook Section 3855, “Financial Instruments - Recognition and Measurement.” It prescribes when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet and at what amount, requiring fair value or cost-based measures under different circumstances. It also specifies how financial instrument gains and losses are to be presented. It applies to interim and annual financial statements for fiscal periods beginning after October 1, 2006 and will be adopted by the Company on or before January 1, 2007. Transitional provisions are complex and vary based on the type of financial instruments under consideration. The effect on the Company’s consolidated financial statements is not expected to be material.
(ii) Comprehensive Income. CICA Handbook Section 1530, “Comprehensive Income,” was issued in January 2005 to introduce new standards for reporting and presenting comprehensive income. Comprehensive income is the change in equity (net assets) of a company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except for changes resulting from investments by owners and distributions to owners. It applies to interim and annual financial statements for fiscal periods beginning after October 1, 2006 and will be adopted by the Company on or before January 1, 2007. Financial statements for prior periods will be required to be restated for certain comprehensive income items. The effect on the Company’s consolidated financial statements is not expected to be material.
(iii) Equity. In January 2005, the CICA issued Handbook Section 3251, “Equity,” which replaces Section 3250, “Surplus.” It establishes standards for the presentation of equity and changes in equity during reporting periods beginning after October 1, 2006. Financial statements of prior periods are required to be restated for certain specified adjustments. For other adjustments, the adjusted amount must be presented in the opening balance of accumulated other comprehensive income. The Company plans to adopt this Section on January 1, 2007. The effect on the Company’s consolidated financial statements is not expected to be material.
(iv) Hedges. CICA Handbook Section 3865, “Hedges,” was issued in January 2005 to clarify requirements for determining hedging relationships and applying hedge accounting. The Company plans to adopt this Section on January 1, 2007 and does not expect the adoption to have a material effect on its consolidated financial statements.
(c) Recent Accounting Pronouncements - U.S. GAAP. Recent accounting pronouncements affecting the Company’s financial reporting under U.S. GAAP are summarized below.
(i) SFAS No. 123R. SFAS No. 123R, “Share Based Payment,” was issued in December 2004 to require recognition of compensation expense for the fair value of stock options and other equity-based compensation at the date of grant. In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 107, “Share-Based Payment,” clarifying the interaction between SFAS No. 123R and certain SEC reporting requirements. The Company adopted these requirements on January 1, 2004 in accordance with CICA Handbook Section 3870. See Note 10 - Capital Stock.
(ii) SFAS No. 153. SFAS No. 153, “Exchanges of Nonmonetary Assets,” was issued in December 2004 to amend APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to fair value accounting for nonmonetary exchanges of similar productive assets and replacing it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance it future cash flows are expected to change significantly as a result of the exchange. SFAS No. 153 applies to periods beginning after June 15, 2005 and is not expected to have a material effect on the Company’s consolidated financial statements.
(iii) FIN No. 47. The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is the equivalent of CICA Handbook Section 3110. See Note 19 - Asset Retirement Obligations. In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” to clarify when sufficient information would be available to reasonably estimate the timing and cost of performing a conditional asset retirement obligation. FIN No. 47 applies to fiscal years ending after December 15, 2005 and has not had a material effect on the Company’s consolidated financial statements.
(iii) SFAS No. 19 and FSP No. 19-1. In April 2005, FASB Staff Position (“FSP”) No. 19.1 was issued to amend the guidance for suspended well costs in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The FSP addresses circumstances that permit continued capitalization of exploratory drilling costs beyond one year. In general, the one-year limitation may be exceeded for an exploratory well only if sufficient reserves have been found to justify its completion and sufficient progress has been made in assessing the reserves as well as the economic and operating viability of the project. The FSP is effective for the first reporting period beginning after April 4, 2005. The Company has found proved reserves for all exploratory wells drilled during the periods presented in the condensed consolidated financial statements within one year after completion of drilling and therefore has not expensed any exploratory drilling costs for those wells.
(iv) SFAS No. 154. SFAS No. 154, “Accounting Changes and Error Corrections,” was issued in June 2005 to replace SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and APB Opinion No. 20, “Accounting Changes.” SFAS No. 154 generally requires retrospective application for voluntary changes in accounting principles as well as changes required by accounting pronouncements. SFAS No. 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on January 1, 2005. In August 2005, the Company amended its Annual Report on Form 10-KSB for the year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 to reflect two adjustments to the consolidated financial statements included in the reports. In the consolidated statements of operations, the Company eliminated the line item for gross profit, and in the consolidated statements of cash flows, reported changes in subscriptions receivable during 2004 and 2003 were eliminated from operating activities and added to financing activities as proceeds from issuance of common stock during those years in proportion to the subscription amounts received at the beginning of 2004 and the end of 2003, respectively. The annual consolidated financial statements were also expanded to add consolidated statements of changes in shareholders’ equity for each of the years in the three-year period ended December 31, 2004.
(v) EITF No. 04-10. In June 2005, the FASB ratified Emerging Issues Task Force (“EITF”) Issue No. 04-10, “Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds.” The consensus is effective for fiscal years ending after September 15, 2005 and has not had a material effect on the Company’s presentation of its reportable operating segments.
(vi) EITF No. 05-2. In June 2005, the FASB ratified EITF Issue No. 05-2, “The Meaning of Conventional Convertible Debt Instrument.” The consensus is to be applied prospectively for new instruments entered into or modified in periods beginning after June 29, 2005. The Company has one series of convertible notes issued after that date and has recorded the notes as conventional convertible debt under this EITF. If the Company were to modify these notes, an evaluation of the terms of the instruments would be required after the modification to determine if they would remain conventional convertible debt instruments.
(vii) FERC Pronouncement. In June 2005, the Federal Energy Regulatory Commission (“FERC”) issued an order, “Accounting for Pipeline Assessment Cost,” to be effective January 1, 2006. The order requires companies to expense certain assessment costs, even if they were historically capitalized. The effect of this order on the Company’s consolidated financial statements is not expected to be material.
(viii) EITF No. 05-8. In September 2005, the FASB ratified EITF Issue No. 05-8, “Income Tax Consequences of Issuing Convertible Debt with a Beneficial Conversion Feature.” The consensus requires a portion of convertible debt proceeds reflecting the intrinsic value of the beneficial conversion feature to be allocated to equity and recognized as a discount on the debt. The debt discount is accreted from the issuance date to the scheduled maturity date. The consensus is to be applied retrospectively to instruments with a beneficial conversion feature for periods beginning after December 15, 2005. The Company has applied this EITF in accounting for its 6% convertible notes issued in December 2005. See Note 9 - Long Term Debt.
Note 18. Commitments
As of December 31, 2005, the Company has contractual obligations for periodic future payments under leases for field equipment and instruments governing its other commercial commitments in the amounts listed below. The Company incurred lease rental expenses of $704,597 in 2005, $475,060 in 2004 and $330,758 in 2003.
(1)
Reflects obligations under a guaranty secured by a certificate of deposit provided for bank debt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held a minority interest.
(2)
Reflects commitments under a purchase contract for an airplane.
Note 19. Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which is the equivalent of CICA Handbook Section 3110. This statement requires the fair value of an asset retirement obligation to be recognized in the period when it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Previous accounting standards used the units-of-production method to match estimated future retirement costs with the revenues generated from the producing asset. In contrast, SFAS No. 143 and CICA Handbook Section 3110 require depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis over the life of the asset, while the accretion to be recognized will escalate over the life of the asset, typically as production declines. The Company’s asset retirement obligations primarily relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, recoverable quantities of oil and gas, inflation rates and credit-adjusted risk-free interest rates. The following table shows the changes in asset retirement obligations during the years presented.
(1)
Reflects estimated increase in estimated future retirement obligations relating to abandonment of oil and gas wells.
Note 20. Subsequent Events
(a) Gathering System Acquisition. In January 2006, NGAS Gathering entered into an agreement with Duke Energy Gas Services, LLC (“Duke Energy”) to purchase a 116-mile gas gathering system that spans parts of southeastern Kentucky and southwestern Virginia, and ties into Duke Energy’s East Tennessee pipeline system. The purchase price for the assets covered by the acquisition agreement is $18 million. Performance of the agreement is guaranteed by DPI. Funding for the acquisition is expected to be provided from part of the proceeds from the
Company’s institutional private placement of 6% convertible notes in December 2005. See Note 9 - Long Term Debt. The Company expects to account for the transaction under the purchase method. As part of the transaction, NGAS Gathering will assume future obligations of the seller under various contracts and has committed to relocate one of the acquired compression stations and liquids extraction plant. Closing of the transaction is subject to customary conditions, including approval by FERC of a prior notice filing by an affiliate of Duke relating to part of the gathering system not included in the acquisition.
(b) Credit Facility Amendment. In the first quarter of 2006, the Company’s credit facility with KeyBank NA was amended to extend the scheduled maturity date to July 31, 2007, increase the maximum credit and borrowing base to $75 million and $35 million, respectively, and reduce the interest rate for borrowings under the facility to 0.875% above the bank’s prime rate.
Note 21. Supplementary Information on Oil and Gas Development and Producing Activities
(a) General. This Note provides audited information on the Company’s oil and gas development and producing activities in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities.”
(b) Results of Operations from Oil and Gas Producing Activities. The following table shows the results of operations from the Company’s oil and gas producing activities during the years presented in the consolidated financial statements. Results of operations from these activities are determined using historical revenues, production costs (including production related taxes) and depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense are excluded from this determination.
(c) Capitalized Costs for Oil and Gas Producing Activities. For each of the years presented in the consolidated financial statements, the following table sets forth the components of capitalized costs for the Company’s oil and gas producing activities, all of which are conducted within the continental United States.
(d) Costs Incurred in Oil and Gas Acquisition and Development Activities. The following table lists the costs incurred in the Company’s oil and gas acquisition and development activities for the years presented in the consolidated financial statements.
Note 22. Supplementary Oil and Gas Reserve Information - Unaudited
(a) General. The Company’s estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves are summarized below. The reserve information is unaudited. The reserves were estimated by Wright & Company, Inc., independent petroleum engineers, in accordance with regulations of the Securities and Exchange Commission, using market or contract prices at the end of each of the years presented in the consolidated financial statements. These prices were held constant over the estimated life of the reserves. There are numerous uncertainties inherent in estimating quantities and values of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures, including factors involving reservoir engineering, pricing and both operating and regulatory constraints. All reserve estimates are to some degree speculative, and various classifications of reserves only constitute attempts to define the degree of speculation involved. Accordingly, oil and gas reserve information represents estimates only and should not be construed as being exact.
(b) Estimated Oil and Gas Reserve Quantities. For each of the years presented in the consolidated financial statements, the Company’s ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below.
(c) Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows from the Company’s estimated proved oil and gas reserves is provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry and may not represent the fair market value of the Company’s oil and gas reserves or the present value of future cash flows of equivalent reserves due to various uncertainties inherent in making these estimates. Those factors include changes in oil and gas prices from year-end prices used in the estimates, unanticipated changes in future production and development costs and other uncertainties in estimating quantities and present values of oil and gas reserves.
The following table presents the standardized measure of discounted future net cash flows from the Company’s ownership interests in proved oil and gas reserves as of the end of each of the years presented in the consolidated financial statements. The standardized measure of future net cash flows as of December 31, 2005, 2004 and 2003 are calculated using weighted average prices in effect as of those dates. Those prices were $12.39, $6.89 and $5.34, respectively, per Mcf of natural gas and $54.65, $43.23 and $31.56, respectively, per barrel of oil. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the estimated proved reserves based on year-end cost levels. Future income taxes are based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits. The future net cash flows are reduced to present value by applying a 10% discount rate. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and gas properties.
(In thousands)
(d) Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of the Company’s proved oil and gas reserves after income taxes for each of the years presented in the consolidated financial statements. Sales of oil and gas, net of production costs, are based on historical pre-tax results. Extensions and discoveries, purchases of reserves in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented after tax.
(In thousands)
Supplementary Selected Quarterly Financial Data - Unaudited
The following table provides unaudited supplementary financial information on the Company’s results of operations for each quarter in the two-year period ended December 31, 2005.
(In thousands, except per share amounts)