Ngas Resources (NGAS) 10-K 2007 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

þ ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

For the Year Ended December 31, 2007

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

Commission File No. 0-12185

NGAS Resources, Inc.

(Exact name of registrant as specified in its charter)

Province of British Columbia (State or other jurisdiction of incorporation)	Not Applicable (I.R.S. Employer Identification No.)
120 Prosperous Place, Suite 201
Lexington, Kentucky	40509-1844
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (859) 263-3948

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: Common Stock

     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yeso Noþ

     Indicate by check mark if the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Act during the past 12 months and (2) has been subject to those filing requirements for the past 90 days. Yesþ Noo

     Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in the definitive proxy statement incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero  Accelerated filerþ  Non-accelerated filer  o
(Do not check if a smaller reporting company) Smaller Reporting Companyo 

     Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2). Yeso Noþ

     The aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the last sale price of the common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $174,391,848.

     As of March 5, 2008, there were 26,236,064 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
Certain portions of the proxy statement for the 2008 annual meeting of shareholders are incorporated by reference
into Part III of this report.

Table of Contents

	Page
Part I:
Item 1. Business		1
Item 1A. Risk Factors		8
Item 1B. Unresolved Staff Comments		10
Item 2. Properties		10
Item 3. Legal Proceedings		15
Item 4. Submission of Matters to Security Holders		15
Part II:
Item 5. Market for Common Equity and Related Matters		16
Item 6. Selected Financial Data		17
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 7A. Quantitative Disclosure About Market Risk		26
Item 8. Index to Financial Statements and Supplementary Data		26
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		26
Item 9A. Controls and Procedures		26
Item 9B. Other Information		27
Part III:
Item 10. Directors, Executive Officers and Corporate Governance		27
Part IV:
Item 15. Exhibits, Financial Statement Schedules		28
Management’s Report on Internal Control over Financial Reporting		F-1
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated Financial Statements		F-5
Notes to Consolidated Financial Statements		F-9
EX-23.1
EX-23.2
EX-23.3
EX-24.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Forward-Looking Statements

     Some matters discussed in this report are prospective and constitute forward-looking statements within the meaning of the Private Litigation Reform Act of 1995 that involve risks and uncertainties. Other than statements of historical fact, all statements that address our future activities, events, outcomes and other matters we plan, expect, budget, intend or estimate (and other similar expressions) are forward-looking statements. While we believe these forward-looking statements are based on reasonable assumptions, they involve known and unknown risks, uncertainties and other factors that may cause future results to differ materially from those discussed or implied in this report. Additional information about issues that could cause actual results to differ from our forward-looking statements is provided in this report under the captionsRisk FactorsandManagement’s Discussion and Analysis of Financial Condition and Results of Operations - Forward looking Statements.

Additional Information

     We file annual, quarterly and other reports and information with the Securities Exchange Commission. Promptly after their filing, we provide access to these reports without charge on our website at www.ngas.com.

Part I

Item 1. Business

General

     We are an independent exploration and production company focused on unconventional natural gas basins in the eastern United States that provide us with repeatable drilling opportunities, principally 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 also control the gas gathering facilities for our core Appalachian properties, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets. We believe our extensive geological, geophysical, engineering and operating experience in this region, coupled with our midstream assets, gas gathering infrastructure and relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to achieve annual volumetric growth and strong financial returns on a long term basis.

     Our principal and administrative offices are located in Lexington, Kentucky. Our common stock is traded on the Nasdaq Global Select Market under the symbolNGAS. Unless otherwise indicated, references in this report towe,ourorusinclude NGAS Resources, Inc., our direct and indirect wholly owned subsidiaries and our interests in sponsored drilling programs. As used in this report,Dthmeans decatherm,Mcfmeans thousand cubic feet,Bcfmeans billion cubic feet andMcfe means thousand cubic feet of natural gas equivalents.

Strategy

     Our business is structured to achieve capital appreciation through growth in our natural gas production and reserves. During 2007, we achieved record production of 3.3 Bcfe, up 15% from the prior year, contributing to 16.2% growth in our production revenues to $28.1 million. We also increased our estimated proved reserves at the end of 2007 by 4% to 105.2 Bcfe, of which 46% were proved developed. Our undeveloped acreage position provides us with a multi-year inventory of drilling locations for future growth, which may be accelerated by emerging horizontal shale plays in our operating areas. Our strategy for capitalizing on these opportunities emphasizes several components.

• Organic Growth through Drilling. Development drilling is our mainstay for production and reserve growth. During 2007, we drilled 217 gross (82.2 net) wells, compared to 226 gross (65.5 net) wells during 2006, representing an increase of 26% in our net well position. This reflects the evolution of our business model for accelerating organic growth by retaining all of our available working interest in wells drilled on key operated properties. We implemented this shift in our development strategy late in 2007, and most of our higher net interest wells were awaiting connection at year end. We anticipate significant upside as we bring our backlog of unconnected wells on line. Our growth strategy during 2008 will be focused on that task, as well as increasing our acreage position and taking advantage of horizontal drilling opportunities on core properties. We have a drilling budget of $44 million for 2008, including our horizontal drilling initiatives, plus $6 million in related infrastructure build-outs.

• Investment in Midstream Assets. We own and operate a strategically located open-access gas gathering system spanning 116 miles in southeastern Kentucky and southwestern Virginia. We acquired these midstream assets in March 2006 through our NGAS Gathering subsidiary and augmented the system through two high-pressure lateral upgrades for connections to our field-wide gathering facilities, plus a recently completed processing plant for liquids extraction. On a combined basis, our field-wide and midstream facilities spanned a total of 593 miles at the end of 2007. We currently deliver production from our Leatherwood, Straight Creek and SME fields to the interstate pipeline network through the NGAS Gathering system, with daily gross throughput of over 17,000 Dth at year end, including third-party deliveries. In addition to generating gas transmission revenues from third-party throughput and cost savings for our own Appalachian production, ownership of these midstream assets gives us control over gas flow from our connected fields and enhances our competitive position in the region.

• Enhancement of Field-Wide Infrastructure. We construct and operate field-wide gas gathering facilities to provide compression, connection and local distribution capabilities for most of our Appalachian production. Because we control third-party access to our field-wide systems, they provide us with competitive advantages in acquiring and developing nearby acreage. We continually

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	upgrade these facilities to keep pace with our expanding production base. During 2007, we installed 63 miles of gathering lines, including facilities for our New Albany shale project in western Kentucky, known as Haley’s Mill, and a 14-mile, six-inch steel line to provide deliverability from our Fonde field for compression into the NGAS Gathering system. Production in Fonde has historically been limited by pipeline capacity constraints, and our new system has positioned us to begin connecting a backlog of wells drilled in Fonde over the last several years and open nearly 50,000 acres for future development in this field. Our capital expenditure program for 2008 includes $6 million for ongoing infrastructure extensions and upgrades.
•	Development of Additional Drilling Prospects. We follow a disciplined capital allocation process in selecting opportunities to expand our substantial inventory of drilling prospects that meet our criteria for predictable, long-lived reserves. Our goal is to consolidate our position in the Appalachian Basin, while diversifying our asset base with similar unconventional plays outside the basin. As part of this strategy, we are aggressively developing our New Albany shale play in the Haley’s Mill field, which is situated within the southcentral portion of the Illinois Basin in western Kentucky. We have also acquired exclusive development rights and a 50% interest in currently constrained gathering infrastructure for a project spanning approximately 63,000 acres across six counties in eastern Kentucky, known as Licking River, where we are conducting a geological evaluation of data from existing wells. We plan to continue capitalizing on opportunities to assemble or participate in developing large tracts with significant reserve potential.
•	Purchase of Producing Properties. The purchase of third-party production offers a means in addition to drilling for capitalizing on our operating experience and accelerating our growth. 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. Based on our current evaluations, we believe our mature drilling programs present attractive acquisition candidates, providing opportunities to increase our interest in producing properties meeting all these criteria. We plan to begin purchasing the assets of targeted programs based on independent reserve valuations that will give effect to our working interests and reversionary interests in these programs. The consolidation of these assets is expected to increase our reserves and cash flows, while also generating administrative efficiencies and simplifying our capital structure.

Regional Advantages

     Geographic. Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian Basin. Although mineral development in Appalachia has historically been dominated by coal mining interests, it is also one of the oldest and most prolific natural gas producing areas in the United States. The proximity of this region to major east coast gas markets generates realization premiums above Henry Hub spot prices, contributing to long term returns on investment. Our Appalachian gas production also has the advantage of a high energy content (Dth), ranging from 1.1 to 1.3 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1 Dth per Mcf, this resulted in realized premiums averaging 17% over normal pipeline quality gas. During 2007, in response to a developing trend limiting the upward range of pipeline throughput to 1.1 Dth per Mcf, we constructed a processing plant in Rogersville, Tennessee for liquids extraction from our Appalachian production delivered through the NGAS Gathering system. The plant was brought on line in January 2008, ensuring our compliance with the new energy content standard. See “Gas Gathering Operations.” We expect our sales of extracted liquids to offset the reduction in energy-related yields from our Appalachian gas production.

     Geological. Most of our Appalachian wells are drilled to relatively shallow total depths up to 5,000 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout this region is the Devonian shale formation. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance natural fracturing in these reservoirs. Typically, vertical gas wells in this part of Appalachia recover between 100 to 500 Mmcf of reserves per drilling unit. While these unconventional shale plays are characterized by modest initial volumes and pressures, their geological features also account for the low annual decline rates demonstrated by vertical wells in the region, many of which are expected to produce for 25 years or more.

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Horizontal Drilling Initiatives

     The value proposition for many of our Appalachian properties may be enhanced by the use of horizontal drilling, which has been found to provide advantages in extracting natural gas in various environments, including shale and other tight reservoirs that are challenging to produce efficiently. In general, horizontal wells use directional drilling to create one or more lateral legs designed to allow the well bore to stay in contact with the reservoir longer and to intersect more vertical fractures in the formation than conventional methods. While substantially more expensive, horizontal drilling may improve overall returns on investment by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells.

     We began participating in horizontal drilling initiatives during 2005 through non-operated projects, the first in the Arkoma Basin for coalbed methane (CBM) recovery and the second in West Virginia. Since that time, we have evaluated opportunities to optimize the application of these techniques in our operating environments. We plan to concentrate those initiatives during 2008 in our Leatherwood field, where we anticipate drilling between ten to twenty horizontal wells by year end. The initial three wells in this project are scheduled for completion and flow testing by the end of the second quarter.

Drilling Operations

     General. At the end of 2007, we had interests in a total of 1,231 wells, concentrated on Appalachian properties that we operate and control through our gas gathering infrastructure. We believe our long and successful operating history in Appalachia and proven ability to drill a large number of wells year after year have positioned us as a leading player in this region. Historically, we conducted most of our drilling operations through sponsored drilling programs. Our combined interest as both general partner and an investor in these programs ranges from 12.5% to 75%, with additional reversionary interests after distribution thresholds are reached. Beginning in the second half of 2007, we changed our business model to accelerate organic growth by limiting our use of future drilling programs to participation in our non-operated initiatives, retaining all of our available working interest in new wells drilled on operated properties.

     Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during the last three years. During the fourth quarter of 2007, we participated in 48 gross (21.89 net) wells. Drilling results shown in the table for 2007 include 89 gross (39.54 net) wells that were drilled by year end but were awaiting installation of gathering lines or extensions prior to completion. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may subsequently earn in wells drilled through our drilling programs.

	Development Wells						Exploratory Wells
Year Ended	Productive				Dry		Productive				Dry
December 31,	Gross		Net		Gross		Gross		Net		Gross
2007		211		76.1508		—		6		6.0000		—
2006		193		56.3007		—		4		3.1250		29
2005		151		43.1590		—		3		0.9370		1
Total		555		175.6105		—		13		10.0620		30

     The wells reflected in the table as dry exploratory wells were initially classified as productive pending determination of proved reserves within one year after completion of drilling. These wells were drilled as part of a 30-well project to test the shallow New Albany shale formation on the eastern rim of the Illinois Basin in western Kentucky. We were not encouraged by the test results, and we expensed the suspended well costs for three of the wells during 2006 and the remaining 27 wells in the second quarter of 2007. Late in 2006, we began a second phase of this exploratory project to test the New Albany shale at greater depths in the southcentral portion of the Illinois Basin on our acquired Haley’s Mill acreage. Results for fifteen wells drilled in Haley’s Mill through the end of 2007 have been promising, and we are continuing to aggressively develop this play, including additions to our lease position and infrastructure. See “Properties - Oil and Gas Properties — Significant Fields.”

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     Participation Rights. The interests in some of our operated properties in the Appalachian Basin, primarily our Leatherwood field, are subject to participation rights retained by the mineral interest owners for up to 50% of the working interest in wells drilled on the covered acreage. We had third-party participation in our Leatherwood wells for average working interests of 14.6% during 2007 and 25.4% during 2006. We anticipate substantially higher levels of third-party participation in our horizontal drilling initiatives planned for Leatherwood during 2008, based on elections for 37.5% participation in the initial wells in this project.

     Drilling Operations. We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. The geological characteristics of our Appalachian properties enable us to drill most of our vertical wells in seven to ten days, although we usually defer completion operations until gathering lines are in place. We perform regular inspection, testing and monitoring functions on our operated wells and gathering systems with our own personnel.

Drilling Programs

     Drilling Program Capital. During the last two years, we raised over $63 million from outside investors for participation in our drilling initiatives through private placements of interests in sponsored drilling programs. Net proceeds from these private placements are used to fund the investors’ share of drilling and completion costs under our drilling contracts with the programs. These payments are recorded as customer drilling deposits at the time of receipt. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits reflected as current liabilities in our consolidated financial statements represent unapplied program payments for wells that were not yet drilled as of the balance sheet dates. Our financing activities through private placements of interests in sponsored drilling programs during the last two years are summarized in the following table.

			Drilling Program Capital
	Total Wells		Outside		Our		Total
Drilling Programs:	Contracted		Contributions		Contributions		Capital
2007		140	$	29,829,219	$	13,939,508	$	43,768,727
2006		175		33,271,236		24,179,168		57,450,404
Total		315	$	63,100,455	$	38,118,676	$	101,219,131

     Conversion Rights of Program Participants. The partnership agreements for most of our drilling programs organized between 2000 and 2005 provide program participants with the right to tender requests for us to purchase their program interests in exchange for our common shares. These rights are exercisable for 90 days at the end of the fifth through ninth years following the program’s organization. Any program interests covered by these rights are 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 the estimated reserves, which may not necessarily correspond to the fair value of those interests. Any common shares issued in consideration for tendered interests are valued at prevailing market prices. The conversion rights are subject to various conditions and are limited in any year to 19% of our common shares then outstanding. Less than 1% of our program participants have exercised their conversion rights, and we do not consider these rights to affect the way we account for our interests in sponsored programs.

Producing Activities

     Production Profile. Most of our Appalachian wells share a relatively predictable production profile, producing high quality natural gas at low pressures from several pay zones. 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. As of December 31, 2007, the reserve life index of our estimated proved reserves, representing the ratio of reserves to annual production, was 28.8 years overall and approximately 13.1 years for our proved developed producing reserves, based on annualized fourth quarter production, which is consistent with the average production levels and decline rates used in estimating our year-end reserves. Approximately 54% of our total estimated proved reserves at December 31, 2007 were

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undeveloped, providing us with a multi-year inventory of drilling locations for future development. Based on prevailing economic and operating conditions, we expect to begin recovery of all proved undeveloped reserves through our drilling initiatives over the next three years.

     Production Volumes. We increased our production volumes in 2007 by 15% over 2006 levels to a record 3.3 Bcfe. Our production in the fourth quarter of 2007 was 0.92 Bcfe, reflecting volumetric growth of 18% on a period-over-period basis and 11% compared to our production volumes for the third quarter of 2007. The following table shows our total net oil and gas production volumes during the last three years.

	Year Ended December 31,
Production:	2007		2006		2005
Natural gas (Mcf)		2,950,690		2,622,474		1,583,922
Oil (Bbl)		57,738		40,938		39,959
Total natural gas equivalents (Mcfe)		3,297,120		2,868,102		1,823,673

     Production Prices and Costs. Our production revenues and estimated oil and gas reserves are substantially dependent on prevailing market prices for natural gas, which comprised 97% of our proved reserves on an energy equivalent basis at the end of 2007. The following table shows the average sales prices for our oil and gas production during the last three years, along with our average lifting costs and transmission and compression costs in each of the reported periods.

	Year Ended December 31,
Average Sales Prices and Production Costs:	2007		2006		2005
Average sales price:
Natural gas (per Mcf)	$	8.19	$	8.23	$	9.02
Oil (per Bbl)		64.97		59.60		48.36
Lifting costs (per Mcfe)		1.05		1.05		1.10
Transmission and compression costs		1.01		0.84		0.70

Gas Gathering Operations

     Midstream System. We own and operate a midstream gas gathering system spanning 116 miles in southeastern Kentucky and southwestern Virginia. We acquired the system for $18 million through our NGAS Gathering subsidiary in March 2006. We operated this system since October 2004 and augmented it after the acquisition through two high-pressure lateral upgrades. Unlike our field-wide gathering facilities, the NGAS Gathering system is open access, and our acquisition included existing contracts for delivering third-party gas. In addition to generating substantial revenues from third-party throughput, ownership of this system has enhanced our deliverability and our competitive position in the region. Most of our Appalachian production is now delivered directly from the wellhead to the interstate pipeline network through the NGAS Gathering system, resulting in cost savings by eliminating transportation fees for our share of production from connected fields. As of December 31, 2007, our midstream system had daily gross throughput of over 17,000 Dth, including third-party deliveries.

     Field-Wide Systems. Our field-wide gas gathering facilities spanned 477 miles as of December 31, 2007, including 63 miles of gathering and production lines added during the year. Our infrastructure build-outs during 2007 included an upgrade of our main suction line to the compressors in our Leatherwood field, which we designed to address constrained gas flows from a pressure backup at the end of the system. We also began construction of a gathering system for our Haley’s Mill field in western Kentucky and completed installation of a 14-mile, six-inch steel line to provide deliverability from our Fonde field for compression into the NGAS Gathering system.

     Gas Processing and Treatment Facilities. During 2007, we enhanced our Appalachian infrastructure with the construction of a natural gas processing plant in Rogersville, Tennessee, with a connection to a pipeline network operated by East Tennessee Natural Gas, LLC. Brought on line in January 2008, the plant extracts natural gas liquids from local production serviced by the NGAS Gathering system and flows dry pipeline quality natural gas into the interstate network. The plant is currently configured for throughput at rates up to 25,000 Mcf per day, which can be increased to accommodate forecasted production growth and relief of constrained regional supplies.

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During 2007, we also began construction of a nitrogen rejection facility for Haley’s Mill field. Both the processing plant and treatment facility were developed with a joint venture partner, Seminole Gas Company, and are co-owned by Seminole.

     Gas Gathering and Compression Fees. We receive fees up to $0.50 per Mcf for gathering third-party production through our field-wide facilities, along with gas compression and dehydration fees up to $0.15 per Mcf. Most of our Appalachian production is now delivered from our field-wide facilities through the NGAS Gathering system in southeastern Kentucky and southwestern Virginia. We receive fees for transporting third-party production through this open-access section of our gas gathering network at a current rate of $0.64 per Mcf.

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 coordinate gas transportation arrangements and perform revenue receipt and related services. Our customers also include pipelines and transmission companies. During 2007, approximately 40% of our natural gas production was sold under fixed-price contracts at rates ranging from $6.77 to $9.85 per Dth. 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 our Sentra subsidiary, 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, 2007, Sentra had over 200 customers, many of which are commercial and agri-business accounts. Demand for these services has benefited from increasing 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. Strength in domestic natural gas prices over the last few years has 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 properties. To compete effectively, we have structured our business to capitalize on our experience and strengths. We maintain a disciplined approach to drilling and a commitment to infrastructure control, with a view to consolidating our position as a niche developer and building our track record as an established 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 that administer these laws have issued extensive regulations that are 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 overview of oil and gas industry regulation is summary in nature and is not intended to cover all regulatory matters that could affect our operations.

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     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 requirements on the ratability of production. 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 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 domestic 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 regulations or permits can result in substantial liabilities, penalties and injunctive restraints.

     We conduct our drilling and production activities to comply with all applicable environmental regulations, permits and lease conditions, and we monitor subcontractors under our 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 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.

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Employees

     As of December 31, 2007, we had 117 full-time employees. Our staff includes professionals experienced in geology, petroleum engineering, land acquisition, finance, accounting and law. 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. 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:

• 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, storage levels, comparative prices 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;

• future market, economic and regulatory factors that may materially affect our sales of gas production; and

• 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. Although the production history for most of our Appalachian wells is substantially less than the average reserve life for mature wells in the region, estimates of our proved producing reserves as of December 31, 2007 were based on historical production profiles for the region. This resulted in a projected decline rate of approximately 19.7% for 2008, decreasing hyberbolically to 5.4% in 2022. The actual performance of our wells could differ materially from these estimates. The depletion of our reserves, whether at anticipated rates or otherwise, will reduce cash flow for future growth as well as the assets available to secure financing for the development and replacement of our existing reserves.

Uncertainties in Estimating Reserves

     There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. 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 our drilling, testing and production after the date of our estimates may require future revisions of the estimates. As a result, our reserve estimates may differ materially from the quantities of oil and gas that are ultimately recovered.

Uncertainties in Recovering Undeveloped Reserves

     As of December 31, 2007, approximately 54% of our estimated proved reserves were undeveloped, and 68% of our reserves in Leatherwood, our largest field based on year-end reserve estimates, were undeveloped. The ultimate recovery of our undeveloped reserves is uncertain. Recovering these reserves will require significant capital expenditures and successful drilling operations. Our reserve estimates assume that we will be able to make the capital expenditures needed to develop these reserves, and we may not have the capital or financing we need for their development. These estimates also assume the continuation of existing economic conditions, including the costs associated with reserve development, which may not be accurate over time. In addition, our development of

8

these reserves may not occur as scheduled. Any of these factors could cause our actual results from future development initiatives to vary significantly from the anticipated results reflected in our reserve estimates.

Uncertainties in Timing and Cost for Implementing Drilling Schedule

     Based on prevailing economic and operating conditions, we expect to begin recovery of the proved undeveloped reserves included in our reserve estimates at the end of 2007 through our drilling initiatives over the next three years. The implementation of our development schedule for recovering these reserves is the most important component of our growth strategy. Our ability to execute this strategy is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, commodity prices, development costs and drilling results. Due to heightened industry demand, well service providers and equipment are in short supply. This has resulted in escalating prices for these resources. The supply imbalance may also cause delays in drilling operations and the possibility of poor services, with the potential for damage to downhole reservoirs and accidents from the overuse of equipment and the inexperience of field personnel. Because of these uncertainties, we may be unable to drill and produce our identified drilling locations or alternative prospects on schedule or on budget, and our actual results from these initiatives may differ materially from our expectations, which could adversely affect all aspects of our business.

Operating Hazards

     Our drilling, production and gas gathering operations involve many operating hazards and a high degree of risk. They include the risk of fire, explosions, blowouts, craterings, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as gas leaks, ruptures and release of contaminated water. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties.

Dependence on Capital Markets

     Our business involves significant ongoing capital requirements. The rate of production from oil and gas properties 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 have $37 million outstanding principal amount of convertible notes that 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 our oil and gas properties. The facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $65 million at December 31, 2007. 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.

9

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, 2007, there were 26,136,064 shares of our common stock issued and outstanding. If all our convertible notes and stock options outstanding at year end are converted or exercised, there will be an additional 5,540,601 shares of our common stock outstanding. All of these shares 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 Global Select 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.

Unprofitability of Gold and Silver Properties

     We have gold and silver properties in Alaska that 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. Unresolved Staff Comments

     None.

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, 2007, 2006 and 2005. The reserves were estimated Wright & Company, Inc., independent petroleum engineers (Wright & Co.), in accordance with regulations of the Securities and Exchange Commission (SEC). Under those regulations, proved reserves are limited to estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, using prices and costs as of the date the estimate is made. These prices and costs are held constant over the estimated life of the reserves. Our reserve estimates should be read in conjunction with the 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.

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     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 proved reserves as of December 31, 2007, 2006 and 2005. 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.

     Our proved undeveloped reserves represented 54% of our total estimated proved reserves (developed and undeveloped) on an energy equivalent basis as of December 31, 2007, compared to 58% of total reserves at the end of 2006. 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.

	As of December 31,
Estimated Proved Reserves:	2007		2006		2005
Natural gas (Mcf)
Proved developed		45,012,226		39,349,733		32,606,391
Proved undeveloped		57,152,907		58,855,060		40,647,601
Total natural gas (Mcf)		102,165,133		98,204,793		73,253,992
Crude oil (Bbl)
Proved developed		499,548		438,754		299,741
Proved undeveloped		—		13,815		28,955
Total crude oil (Bbl)		499,548		452,569		328,696
Total gas equivalents (Mcfe)		105,162,421		100,920,207		75,226,168

     Reserve Values.The following table summarizes the estimates by Wright & Co. of future net cash flows from the production and sale of our proved reserves as of December 31, 2007, 2006 and 2005 and the present value of those cash flows, discounted at 10% per year in accordance with SEC regulations to reflect the timing of net cash flows. The future net cash flows were computed after giving effect to estimated future development and production costs, based on year-end costs and assuming the continuation of economic conditions at the time of the estimates. 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, 2007 had a weighted average of $7.39 per Mcf of natural gas and $87.98 per barrel of crude oil, compared to $6.15 per Mcf and $56.88 per Bbl at December 31, 2006 and $12.39 per Mcf and $54.65 per Bbl at December 31, 2005. The estimates are highly dependent on the year-end prices used in their computation. In view of historic volatility in domestic natural gas and crude oil markets, those estimates are subject to considerable uncertainty.

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(In thousands)

Estimated Future Net Cash Flows	Year Ended December 31,
From Proved Reserves:	2007			2006			2005
Undiscounted future net cash flows	$	317,356		$	261,146		$	505,288
10% annual discount for estimated timing of cash flows		(214,574	)		(179,813	)		(297,640	)
Standardized measure of discounted future net cash flows	$	102,782		$	81,333		$	207,648

     We have not filed any estimates of our proved reserves with any federal authority or agency during the past year other than estimates filed with the SEC under the Securities Exchange Act of 1934 (Exchange Act).

Oil and Gas Properties

     Oil and Gas Interests.The following table shows our ownership interests under oil and gas leases and farmout agreements, by state, as of December 31, 2007. The table does not include any acreage covered by development rights under our participation agreements with joint venture partners who control the acreage. Our leases and farmouts 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.

	Developed(1)				Undeveloped(2)
Property Location:	Gross Acres		Net Acres		Gross Acres		Net Acres
Kentucky		72,854		26,812		227,948		193,756
Tennessee		1,458		396		38,729		32,920
Virginia		2,749		2,362		11,833		10,058
Arkansas		8,913		2,179		2,960		2,235
Oklahoma		2,127		426		—		—
Total		88,101		32,175		278,510		238,969

(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, 2007. The table does not include a substantial backlog of wells that were drilled by year end but were awaiting installation of gathering lines or extensions prior to completion.

	Gas Wells				Oil Wells				Total
Well Location:	Gross		Net		Gross		Net		Gross		Net
Kentucky		848		385.3114		13		9.1865		861		394.4979
Virginia		32		28.6780		—		—		32		28.6780
Arkansas		54		13.1400		—		—		54		13.1400
West Virginia		80		8.8976		—		—		80		8.8976
Oklahoma		13		3.7407		—		—		13		3.7407
Tennessee		2		0.5086		—		—		2		0.5086
Louisiana		—		—		3		0.3425		3		0.3425
Total		1,029		440.2763		16		9.5290		1,045		449.8053

     Significant Fields.Our producing properties and development prospects are concentrated in the southern portion of the Appalachian Basin. The following table shows estimated proved reserves from our interests in our key fields as of December 31, 2007. These include fields where our interests and development rights are held under participation agreements with joint venture partners who control the acreage.

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	Proved Reserves at December 31, 2007
	Developed				Undeveloped
Field:	Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		%
Leatherwood		9,984,499		15,455		21,153,016		68	%
Arkoma — CDX		8,141,818		—		3,359,596		29
SME — Amvest		5,365,517		255,219		4,877,294		41
SME — Martin’s Fork		4,610,510		21,919		4,573,317		49
Straight Creek		4,224,570		43,296		8,921,920		67
Kay Jay		2,985,560		2,476		3,123,749		51
Fonde		2,484,049		2,907		5,524,321		69
Haley’s Mill		2,059,386		—		2,606,921		56
HRE		2,771,165		1,722		1,002,308		26
All other fields		2,385,152		156,554		2,010,465		38
Total		45,012,226		499,548		57,152,907		54	%

     Additional information about our significant fields is summarized below. Unless otherwise indicated, well counts, production volumes and reserve data are provided as of December 31, 2007.

     Leatherwood. The Leatherwood field covers approximately 59,000 acres, extending 41 miles through Letcher, Perry, Leslie and Harlan Counties in eastern Kentucky. We acquired most of our interests in this field at the end of 2002 under a farmout agreement with the mineral interest owners, Equitable Production Company and KRCC Oil & Gas, LLC. During 2003, we formed a specialized drilling program for 25 exploratory wells to test five natural gas pay zones within this field at depths between 3,500 and 5,300 feet. These wells were all successful, producing from the Maxon sand, Big Lime and Devonian shale formations. Since that time, we have drilled an additional 230 development wells in Leatherwood, primarily through sponsored drilling programs. As of year end, we had 262 wells on line in Leatherwood, including several wells acquired with additional leased acreage at the perimeter of the field, with total daily gross and net production of 5,546 Mcf and 2,074 Mcf, respectively. We operate all the wells in Leatherwood and produce all the connected wells to sales through the NGAS Gathering system. Estimated proved reserves from our interests in Leatherwood are 32% proved developed.

     At the time we acquired our farmout for Leatherwood, there was no gas gathering infrastructure in the region, which has a history as an active coal producing district. We completed the construction of a 23-mile gathering system for our Leatherwood wells and a 16-mile line that connects them to the NGAS Gathering system late in 2005, enabling us to bring a backlog of unconnected wells on line sequentially. After exceeding available compression capacity for Leatherwood production, we installed additional compressors. While this gave us the necessary compression capacity, a pressure backup at the end of the system required us to add an upgrade to the main suction line during 2007. With new wells brought on line during the year, the upgrade did not lower line pressure as planned. Because we were not able to lower field operating pressures, our actual production from Leatherwood wells on line at year end did not measure up to projected production rates from our 2006 year-end reserve estimates for the field. Consequently, our reserve estimates for Leatherwood were lowered by approximately 5 Bcf at the end of 2007.

     Our farmout for Leatherwood had an initial 200-well drilling commitment, which we satisfied ahead of schedule in 2006. We have an ongoing annual drilling commitment for 25 wells in Leatherwood. The farmout provides the mineral interest owners with participation rights for up to 50% of the working interest in new wells, which were exercised for average total working interests of 14.6% during 2007 and 25.4% during 2006. We anticipate higher participation levels by the mineral interest owners in our horizontal wells planned for Leatherwood during 2008.

     Arkoma-CDX. 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 through November 1, 2005. Effective as of that date, we acquired Dart Energy’s position in the Arkoma-CDX field, including its 25% interest in the gathering system for the field. We also entered into a farmout agreement with CDX for 90% of its majority (75%) interest in a minimum of 32 drilling locations on the Arkoma-CDX acreage. Under

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the terms of the farmout, 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 gave us an overall position of approximately 73% in future development of the Arkoma-CDX field.

     We participated in 15 horizontal wells under our Arkoma-CDX farmout, which we elected to terminate during 2007. The farmout termination resulted in a downward reserve revision of approximately 5 Bcf for our interests in this field. After terminating the farmout, we participated in an additional four CBM wells during the balance of 2007 through our interests from the Dart Energy acquisition. At year end, we had interests in a total of 66 wells producing to sales in this field, with daily gross and net CBM production of 11,594 Mcf and 2,478 Mcf, respectively. Estimated proved reserves from our interests in the Arkoma-CDX field are 71% are proved developed..

     SME. We acquired our interests in the SME fields, including existing wells and infrastructure, during the fourth quarter of 2004. These fields are divided between Martin’s Fork, covering approximately 48,000 acres in Harlan County, Kentucky, and Amvest, spanning approximately 42,000 acres in Harlan County, Kentucky and Lee County, Virginia. Martin’s Fork produces from the Big Lime, Devonian shale and Clinton formations at depths between 3,200 and 6,500 feet. Amvest 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 Big Lime in Martin’s Fork and from the Big Lime and Weir sand in Amvest. Our interests in the SME fields are subject to annual drilling commitments for two wells in Martin’s Fork and four wells in Amvest. Since acquiring our interests in SME, we have drilled a total of 48 wells on this acreage, primarily through sponsored drilling programs. At year end, we had a total of 66 wells in Martin’s Fork and 69 wells in Amvest producing to sales, with daily gross and net production aggregating 3,651 Mcfe and 1,938 Mcfe, respectively. We operate all the wells and produce all natural gas in these fields through the NGAS Gathering system. Estimated proved reserves from our interests in the SME fields are 59% proved developed in Amvest and 51% proved developed in Martin’s Fork.

     Straight Creek. 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 approximately 27,000 acres in this field. In addition to several wells we acquired in the field during 2004, we have drilled 178 wells in Straight Creek, which produce from the Maxon sand, the Big Lime, Devonian shale, Corniferous and Big Six sand formations at depths between 3,200 and 4,700 feet. We operate all of the wells and a 16-mile gathering system we completed in 2005 to enhance our Straight Creek production through compression into the NGAS Gathering system. At the end of 2007, a total of 183 wells were producing to sales in Straight Creek, with daily gross and net production of 2,231 Mcf and 636 Mcf, respectively. Estimated proved reserves from our interests in the Straight Creek field are 33% proved developed.

     Kay Jay. The Kay Jay field spans portions of Knox and Bell Counties in eastern Kentucky. Our interests in the field include drilling rights on approximately 11,500 acres acquired under a farmout in 1996, with an ongoing annual drilling commitment for four wells, and an additional 15,500 acres subsequently assembled under a leasing program for this field. We have drilled 157 wells in Kay Jay, which produce natural gas from the Maxon sand, Big Lime, Borden, Devonian shale and Clinton formations at depths ranging from 2,200 to 3,300 feet. Oil is also produced from the Maxon sand. We operate all of our Kay Jay wells and own all of the field-wide gathering facilities for their production. Our gathering facilities are currently connected to third-party pipeline systems. We had a total of 143 wells in Kay Jay producing to sales at year end, with daily gross and net gas production of 2,340 Mcfe and 638 Mcfe, respectively. Estimated proved reserves from our interests in the Kay Jay field are 49% proved developed.

     Fonde. The Fonde field spans portions of Bell County, Kentucky and Claiborne County, Tennessee, located northeast of the Days Chapel field, formerly one of the most prolific oil fields in the region. We acquired our initial position on approximately 3,900 acres in this field during 1998. Since that time, we have assembled approximately 44,000 additional acres in Fonde under a series of farmouts and leases. The Fonde field produces natural gas from the Big Lime and Devonian shale formations at depths up to 4,500 feet and crude oil from the Big Lime. We have drilled a total of 65 wells in Fonde, primarily through sponsored programs, including 12 wells in 2007. Estimated proved reserves from our interests in Fonde are 31% proved developed. Our production from Fonde has historically been curtailed by pipeline capacity constraints, which limited our daily gross and net production to 513 Mcf and 165 Mcf, respectively, at year end. During the first quarter of 2008, we completed

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construction of a 14-mile, six-inch steel line to provide deliverability for our Fonde production into the NGAS Gathering system. The addition of these facilities has positioned us to begin connecting a backlog of wells drilled in Fonde over the last several years and open nearly 50,000 acres for future development in this field.

     Haley’s Mill. The Haley’s Mill field covers approximately 5,000 acres within Christian and Hopkins Counties, Kentucky. It is situated in the southcentral portion of the Illinois Basin, which has similar geologic characteristics to the Devonian shale in the Appalachian Basin. We assembled our lease position in this field during 2006 and initiated a project late in the year to test the New Albany shale formation at depths ranging from 2,500 to 2,800 feet. Encouraged by our initial results, we drilled 15 wells in the field through the end of 2007. Estimated proved reserves from our interests in the Haley’s Mill field are 44% proved developed. We have dedicated two drilling rigs for ongoing development of this project and have completed the construction of a gathering system for the initial wells. During the first quarter of 2008, our anticipated deliverability under pending gas marketing arrangements for Haley’s Mill was substantially reduced based on third-party pipeline capacity constraints. We are evaluating alternative transportation and gas marketing arrangements that are expected to require additional infrastructure before we can begin field-wide production.

     HRE. We participate in development of the HRE fields with a joint venture partner, Hard Rock Exploration, Inc. (Hard Rock), under its leases and farmouts for approximately 79,000 acres in Boone, Cabell, Jackson and Roane Counties, West Virginia and 7,500 acres in Buchanan County, Virginia. Since the beginning of 2006, we have participated in a total of 119 wells drilled by Hard Rock on its acreage, including 15 deviated wells and 12 horizontal wells. Most of the HRE wells target primarily the Lower Huron interval of the Devonian shale formation at total depths up to 5,000 feet. Some of the wells also produce from the Berea sand formation at depths ranging from 2,600 to 2,700 feet. Hard Rock operates all of the wells in the HRE fields and controls all of the field-wide gathering facilities for their production. As of year end, we had interests in a total of 80 wells producing to sales in these fields, with daily gross and net production of 3,039 Mcfe and 270 Mcfe, respectively. Proved reserves from our interests in the HRE fields are 74% proved developed. During 2008, we have participation rights for 90% of the working interest available to Hard Rock in the next 150 wells drilled in these fields, which we plan to implement through a sponsored drilling program.

Gold and Silver Properties

     We own rights to gold and silver properties spanning 381 acres on Unga Island in the Aleutian Chain, approximately 579 miles southwest of Anchorage, Alaska. The property interests are comprised of various federal patented lode and mill site claims and several state mining claims. There are inferred but no defined mineral reserves for either of these claims. While we continue to expend required funds for maintaining 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 these properties internally, which 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 either through a joint venture arrangement or sale. Implementing 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 13,852 square feet of commercial space for our principal and administrative offices in Lexington, Kentucky at monthly rents ranging from $20,398 to $21,355 through the end of the lease term in January 2013. This reflects expansion of our offices under lease modifications and renewals we implemented during the last several years.

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.

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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 2007.

Part II

Item 5. Market for Common Stock and Related Security Holder Matters

Trading Market

     Our common stock has traded on the Nasdaq Global Select Market under the symbol NGAS. The following table shows the range of high and low bid prices for our common stock for the periods indicated, together with the 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.

		Bid Prices				Average Daily
		High		Low		Volume
2006	First quarter	$	12.35	$	7.16		921,868
	Second quarter		9.40		6.86		467,321
	Third quarter		9.95		6.54		613,799
	Fourth quarter		8.25		6.38		348,581
2007	First quarter	$	7.25	$	6.02		248,497
	Second quarter		8.89		6.70		298,121
	Third quarter		8.33		6.50		187,654
	Fourth quarter		7.59		5.50		185,058
2008	First quarter (through March 5th)	$	6.39		4.89		235,427

Security Holders

     As of March 5, 2008, there were 601 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.

Common Shares Issuable under Equity Compensation Plans

     The following table shows the amount of our common stock issuable as of December 31, 2007 under our equity compensation plans. For purposes of this table, equity compensation plans are broadly defined to include stock award and option plans, individual compensation arrangements and obligations under warrants or options issued in financing transactions and property acquisitions.

	[a]
	Shares Issuable		Weighted Average		Shares Remaining
	Upon Exercise of		Exercise Price of		Available for Future
	Outstanding		Outstanding		Issuance under Equity
	Options and Warrants		Options, Warrants		Compensation Plans
Plan Category	and Rights		and Rights		(excluding column [a])
Plans approved by shareholders		2,681,250	$	4.75		2,611,188
Plans not approved by shareholders		—		—		—
Total		2,681,250	$	4.75		2,611,188

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Performance Graph

     The following graph presents a comparison of annual percentage changes in the cumulative total return on our common stock over the last five years with the total return on the Nasdaq Market Index and the Dow Jones U.S. Exploration and Production Index over the same period, assuming the investment of $100 in our common stock and each index, with reinvestment of any dividends. The performance graph is being furnished, not filed, for purposes of the Securities Exchange Act of 1934 and is not incorporated by reference in any registration statement under the Securities Act of 1933.

Stock Performance Graph

	2002		2003		2004		2005		2006		2007
NGAS	$	100	$	512	$	448	$	1,028	$	625	$	552
Dow Jones US E&P		100		131		186		307		324		465
S&P 500		100		129		143		150		173		183

Item 6. Selected Financial Data

     Our consolidated financial statements included in this report have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). All of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are in U.S. dollars. We are organized at the parent company level under the laws of British Columbia, and we previously prepared our consolidated financial statements in accordance with accounting principles generally accepted in Canada (Canadian GAAP). The laws of British Columbia were changed in 2005 to permit publicly held U.S. reporting companies organized in that jurisdiction to elect U.S. GAAP and engage U.S. auditors. We made this election at the beginning of 2006. Our adoption of U.S. GAAP did not have a material effect on our reported financial condition or results for prior periods and did not require us to restate any previously issued financial statements, which included reconciliations between items with different treatment under Canadian and U.S. GAAP.

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     The following table presents our summary selected consolidated financial data as of and for each of the five years ended December 31, 2007. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP for 2007 and 2006 under U.S. GAAP and by Kraft Berger LLP for prior years under Canadian GAAP. The summary selected consolidated financial data as of December 31, 2007 and 2006 and for the three years ended December 31, 2007 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)

	Year Ended December 31,
Statement of Operations Data:	2007			2006		2005		2004		2003
Total revenues	$	70,203		$	79,820	$	62,228	$	47,980	$	27,444
Direct expenses		39,044			49,361		40,477		33,047		13,753
Net income (loss)		(817	)		1,992		953		1,612		3,660
Net income (loss) per common share (basic)		(0.04	)		0.09		0.05		0.12		0.46
Weighted average common shares outstanding		22,240			21,511		17,351		13,994		8,033

	As of December 31,
Balance Sheet Data:	2007			2006			2005			2004			2003
Current assets	$	11,240		$	24,656		$	34,016		$	16,426		$	26,347
Current liabilities		13,552			25,484			34,880			19,693			15,015
Working capital (deficit)		(2,312	)		(828	)		(864	)		(3,267	)		11,332
Total assets		204,801			178,219			146,774			89,127			46,068
Total liabilities		104,892			101,862			74,546			47,985			20,012
Shareholders’ equity		99,909			76,357			72,227			41,142			26,056

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 unconventional basins with similar geologic characteristics. We also control the midstream and field-wide gas gathering facilities for our core Appalachian properties, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets, and we operate natural gas distribution facilities for two communities in Kentucky. Historically, we developed most of our prospects through sponsored drilling programs, maintaining combined interests as both general partner and an investor ranging from 12.5% to 75%, with additional reversionary interests after specified distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. Beginning in the second half of 2007, we changed our business model to accelerate organic growth by limiting our use of future drilling programs to participation in our non-operated initiatives, retaining all of our available working interest in new wells drilled on operated properties.

Results of Operations — 2007 and 2006

     Revenues. The following table shows the components of our revenues for 2007 and 2006, together with their percentages of total revenue in 2007 and percentage change on a year-over-year basis.

	Year Ended December 31,
			% of					%
Revenue:	2007		Revenue			2006		Change
Contract drilling	$	34,334,829		49	%	$	50,108,545		(31	)%
Oil and gas production		28,148,689		40			24,233,102		16
Gas transmission and compression		7,719,308		11			5,478,642		41
Total	$	70,202,826		100	%	$	79,820,289		(12	)%

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     Our revenue mix for 2007 reflects our ongoing strategy for transitioning to a production based business, with oil and gas sales accounting for 40% of total revenues, compared to 30% of total revenues in 2006. We expect this trend to continue as we execute our initiatives for long term production growth by expanding our infrastructure, acreage position and working interest in new wells on operated properties, including our horizontal drilling projects planned for 2008.

     Contract drilling revenues reflect the size and timing of our drilling program initiatives, as well as our percentage interest in sponsored programs. Although we receive the proceeds from program financings as customer drilling deposits under our drilling contracts with sponsored programs, we recognize revenues from the interests of outside investors in our drilling programs on the completed contract method as the wells are drilled, rather than when funds are received. The contraction in contract drilling revenues reflects the completion of program initiatives on operated properties and a reduction in our reliance on program financings for other drilling initiatives during 2007.

     The growth in our production revenues in of 2007 reflects a 15% increase in production output to 3,297 Mmcfe, compared to 2,868 Mmcfe in 2006. Our average gas sales prices were marginally lower on a year-over-year basis, amounting to $8.19 per Mcf in 2007. We anticipate ongoing production gains as we continue to expand our infrastructure and bring wells on stream in our operated fields. Principal purchasers of our production are gas marketers and customers with transmission facilities near our producing properties. Approximately 40% of our natural gas production in 2007 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 driven by fees totaling $3,812,116 for delivering third-party gas through our NGAS Gathering system. This component of revenues also reflects gathering and compression fees for our drilling program investors’ share of throughput from our field-wide facilities, together with contributions of $365,951 from gas utility sales and $354,449 from our interest in a limited liability company that owns and operates the gathering system servicing the Arkoma-CDX field.

     Expenses. The following table shows the components of our direct and other expenses in 2007 and 2006. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

	Year Ended December 31,
Direct Expenses:	2007		Margin			2006		Margin
Contract drilling	$	26,773,028		22	%	$	39,231,521		22	%
Oil and gas production		7,648,558		73			6,687,874		72
Gas transmission and compression		3,657,977		53			3,094,504		44
Impairment of oil and gas assets		964,000		N/A			346,718		N/A
Total direct expenses		39,043,563		44	%		49,360,617		38	%

Other Expenses (Income):			% Revenue						% Revenue
Selling, general and administrative		12,920,591		18	%		13,201,107			17	%
Options, warrants and deferred compensation		1,069,306		2			1,558,676			2
Depreciation, depletion and amortization		10,416,696		15			8,266,056			10
Bad debt expense		215,000		—			—			N/A
Interest expense, net of interest income		6,007,105		9			3,965,513			5
Loss (gain) on sale of assets		54,304		—			(3,197,834	)		N/A
Other, net		53,434		—			519,692			1
Total other expenses	$	30,736,436				$	24,313,210

     Contract drilling expenses reflect both the level and complexity of drilling initiatives conducted through our sponsored programs. These expenses decreased by 32% on a year-over-year basis but represented 78% of contract drilling revenues in both 2007 and 2006. The contraction in this part of our business reflects a planned phase-out in our use of drilling programs to participate in developing our operated properties in the Appalachian Basin, and our margins reflect the stabilizing effect of our transition from turnkey to cost-plus pricing, which we implemented in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

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     Production expenses in 2007 were consistent with our volumetric growth. In addition to lifting costs, production expenses include field operating and maintenance costs, related overhead, severance and other production taxes, third-party transportation fees and lease operating expenses. Our margins in both periods reflect cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees for our share of Leatherwood, Straight Creek and SME production delivered through the system.

     Gas transmission and compression expenses in 2007 were 47% of associated revenues, compared to 56% in 2006. The margins for this part of our business have benefited from third-party fees generated by the NGAS Gathering system. The improvement in margins for 2007 reflect our first full year of owning these midstream assets, which we acquired in March 2006 for $18 million. Our gas transmission and compression expenses do not reflect those acquisition costs or capitalized costs of approximately $7.2 million in 2007 for extensions of our field-wide gas gathering systems, additions to dehydration and compression capacity or build-outs of gas processing and treatment facilities.

     We expensed the suspended exploratory well costs during 2007 for 27 wells in a 30-well program we began late in 2005 to test the shallow New Albany shale formation on the eastern rim of the Illinois Basin in western Kentucky. This resulted in an impairment charge of $964,000 in the carrying value of our oil and gas assets during 2007, in addition to a charge of $178,700 recognized for the first three wells in that program during 2006.

     Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling programs and overhead costs for supporting our expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses over the last several years.

     Non-cash charges for options, warrants and deferred compensation reflect 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. We also recognized accruals of $540,244 in 2007 and $583,208 in 2006 for deferred compensation costs.

     Depreciation, depletion and amortization (DD&A) is recognized under the units-of-production method, based on the estimated proved developed reserves of the underlying oil and gas properties, and on a straight-line basis over the useful life of other property and equipment. The increase in DD&A charges on a year-over-year basis reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment.

     We recognized a bad debt expense of $215,000 in the third quarter of 2007 to reflect a reserve against past due accounts receivable from oil sales to a regional refinery. See “Critical Accounting Policies and Estimates — Allowance for Doubtful Accounts.” We also recognized a loss of $54,304 from the sale of fixed assets in 2007, compared to gains aggregating $3,197,834 from asset sales in 2006.

     Interest expense for 2007 increased from higher overall bank borrowings. Draws under our credit facility during 2007 were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.

     Deferred income tax expense represents future tax liability at the operating company level. Although we have no current tax liability due to the utilization of intangible drilling costs, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level.

     Net Income and EPS. We recognized a net loss of $816,597 in 2007, compared to net income of $1,992,438 in 2006, reflecting the foregoing factors. Basic earnings (loss) per share (EPS) was $(0.04) based on 22,240,429 weighted average common shares outstanding in 2007, compared to EPS of $0.09 based on 21,510,594 weighted average common shares outstanding in 2006.

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Results of Operations — 2006 and 2005

     Revenues. The following table shows the components of our revenues for 2006 and 2005, together with their percentages of total revenue in 2006 and percentage change on a year-over-year basis.

								��
	Year Ended December 31,
			% of						%
	2006		Revenue			2005			Change
Contract drilling	$	50,108,545		63	%	$	43,787,075			14	%
Oil and gas production		24,233,102		30			16,317,144			49
Gas transmission and compression		5,478,642		7			2,123,870			158
Total	$	79,820,289		100	%	$	62,228,089			28	%

     Contract drilling revenues reflect both the size and the timing of our drilling program initiatives. We participated in 226 gross (65.4577 net) wells during 2006, primarily through our drilling programs. For our 2006 programs, we implemented a cost-plus structure as part of our strategy for reducing exposure to price volatility in drilling services and supplies. This contributed to more stable margins from our operation of sponsored programs.

     Our growth in production revenues reflects an increase of 57% in production volumes to 2,868 Mmcfe in 2006, with a 9% decline in our average sales price of natural gas to $8.23 per Mcf. Our volumetric growth reflects added production from our interests in Arkoma-CDX wells acquired late in 2005 and from wells brought on line during 2006 throughout our operating areas, including 144 wells connected in our Leatherwood field during the year. Approximately 35% of our natural gas production in 2006 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 driven by fees totaling $2,754,498 for third-party deliveries through our NGAS Gathering system, which we acquired in March 2006. This component of revenues also reflects additional gas gathering and compression fees for moving third-party Leatherwood production through field-wide facilities we completed late in 2005, together with contributions of $273,180 in 2006 from gas utility sales and $311,127 from our interest in a limited liability company that owns and operates the gathering system servicing the Arkoma-CDX field.

     Expenses. The following table shows the components of our direct and other expenses in 2006 and 2005. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

	Year Ended December 31,
Direct Expenses	2006		Margin			2005		Margin
Contract drilling	$	39,231,521		22	%	$	34,731,234		21	%
Oil and gas production		6,687,874		72			4,157,356		75
Gas transmission and compression		3,094,504		44			1,588,822		25
Impairment of oil and gas assets		346,718		N/A			—		N/A
Total direct expenses	$	49,360,617		38	%	$	40,477,412		35	%

Other Expenses (Income)				% Revenue						% Revenue
Selling, general and administrative	$	13,201,107			17	%	$	11,251,759			18	%
Options, warrants and deferred compensation		1,558,676			2			1,274,056			2
Depreciation, depletion and amortization		8,266,056			10			4,750,134			8
Interest expense, net of interest income		3,965,513			5			1,454,868			2
Gain on sale of assets		(3,197,834	)		N/A			(21,367	)		N/A
Other, net		519,692			1			222,036			—
Total other expenses	$	24,313,210					$	18,931,486

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     Contract drilling expenses in 2006 were 78% of contract drilling revenues, compared to 79% in 2005. The margins for this sector reflect our transition from turnkey to cost-plus pricing for sponsored drilling programs, which we implemented in 2006 with a view to reducing our exposure to price volatility for drilling services, equipment and steel casing requirements.

     Production expenses in 2006 were driven by our substantial growth in production volumes. The increase in our production expenses was significantly offset by cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees during the balance of the year for our share of Leatherwood, Straight Creek and SME production delivered through the system. As a percentage of oil and gas production revenues, our production expenses increased to 28% in 2006 from 25% in the prior year, primarily reflecting lower margins for non-operated properties, lower gas sales prices and higher filed service costs.

     Gas transmission and compression expenses in 2006 were 56% of associated revenues, compared to 75% in 2005. The improvement in margins for this part of our business reflects substantial revenue growth from third-party fees generated by the NGAS Gathering system acquired in March 2006. Our gas transmission and compression expenses do not reflect our acquisition costs for that system or capitalized costs for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

     In the fourth quarter of 2006, we expensed part of our capitalized exploratory well costs for a project we began late in 2005 to test the shallow New Albany shale formation on acquired tracts in western Kentucky, with an impairment charge of $178,700 in the carrying value of our position. We also recognized a fourth quarter writedown of $168,018 for impairment of non-operated properties in Polk County, Texas.

     SG&A expenses primarily reflect the timing and extent of our selling and promotional costs for sponsored drilling programs. On a year-over-year basis, SG&A expenses also reflect higher costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses.

     Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options, which we adopted in 2004. 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. We also recognized an accrual of $583,208 for deferred compensation cost.

     The increase in DD&A charges reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment, including our acquisition of the NGAS Gathering transmission system for $18 million in March 2006. It also reflects a fourth quarter adjustment of $636,000 from an increase in our depletion rate for 2006 due to an unanticipated decline natural gas prices at year end, which reduced our proved developed reserves for purposes of determining our depletion rate.

     Interest expense in 2006 increased from the addition of $37 million in convertible debt at the end of 2005 and higher overall bank borrowings, used primarily for our acquisition costs of $11.4 million for CBM assets in the Arkoma Basin at the end of 2005, $18 million for the purchase of our NGAS Gathering system early in 2006 and capitalized costs of approximately $6.5 million for extensions and enhancements of our field-wide gas gathering systems throughout the year.

     We realized a gain of $3,197,834 on the sale of assets in 2006 primarily from two strategic transactions. The first involved a sale of our overriding royalty interests under a farmout for properties we operate in Harlan County, Kentucky and Lee County, Virginia. We had acquired these interests, together with related participation and pipeline capacity rights, for $1.5 million earlier in the year, and received $2.0 million for the sale of the royalty interests. In the second transaction, completed in the fourth quarter, we sold our oil and gas lease position in the Williston Basin for $4.8 million, resulting in a gain of approximately $2.7 million. We had assembled the position under a leasing program we initiated in 2005. At the time of the sale, our Williston position aggregated 18,411 gross (14,864 net) areas.

     Income tax expense in 2006 represents future tax liability at the operating company level. We have no current tax liability due to the utilization of intangible drilling costs allocated from our active drilling programs.

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     Net Income and EPS. We realized net income of $1,992,438 in 2006, compared to $952,756 in the prior year, reflecting the foregoing factors. Basic EPS was $0.09 based on 21,510,594 weighted average common shares outstanding in 2006, compared to $0.05 in 2005 based on 17,350,550 weighted average common shares outstanding. On a fully diluted basis, EPS for 2006 was $0.09 on 22,922,615 weighted average common shares.

Liquidity and Capital Resources

     Liquidity. Net cash of $1,828,345 was provided in operating activities in 2007. During the year, we used $50,832,815 in investing activities, most of which reflects net additions to our oil and gas properties and gathering systems. These investments were funded in part with net cash of $37,389,171 from financing activities. As a result of these activities, net cash decreased from $14,431,977 at December 31, 2006 to $2,816,678 at the end of 2007.

     Net cash of $2,256,429 was provided by operating activities in 2006. During the year, we used $43,812,946 in investing activities, primarily for additions to our oil and gas properties and gathering systems, including our $18 million acquisition of NGAS Gathering system in March 2006. These investments were funded in part with net cash of $32,044,242 from financing activities. Net cash decreased from $23,944,252 at December 31, 2005 to $14,431,977 at the end of 2006.

     As of December 31, 2007, we had a working capital deficit of $2,312,102. This reflects wide fluctuations in our current assets and liabilities from the timing of customer deposits and expenditures under drilling contracts with our sponsored programs. Since these fluctuations are normalized over relatively short time periods, we do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of 2007 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 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 and the infrastructure to support their development on terms that are economically and operationally advantageous. Historically, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities to fund our ongoing reserve and infrastructure development and acquisition activities, as well as participation in our drilling initiatives by outside investors in our sponsored programs. With the evolution of our business model during 2007 for accelerating organic growth by retaining all of our available working interest in wells drilled on operated properties, we have limited our use of future drilling programs to participation in our non-operated initiatives. This may increase our dependence on the credit and capital markets to meet our ongoing development objectives.

     In November 2007, we completed a registered direct placement of 4.2 million common shares under our existing shelf registration at $6.00 per share. Net proceeds of approximately $23.7 million from the offering are being used to fund part of our capital expenditure program. Pending application, the net proceeds were applied to reduce outstanding borrowings under our credit facility.

     We maintain a secured credit facility with KeyBank National Association, as agent and primary lender. The facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $65 million as of December 31, 2007. The facility is secured by liens on our oil and gas properties. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from 1.5% to 2.5% above quoted LIBOR rates, depending on the amount of borrowing base utilization. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, 2007, our outstanding borrowings under the facility aggregated $42.3 million, and the interest rate amounted to 7.5%.

     We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment based on the pricing of our registered direct equity placement in November 2007. We will be entitled to redeem the notes at their face amount plus accrued and unpaid interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. In the event of default under the notes or any change of control, the holders may require us to redeem the notes at a default rate equal to

23

125% of their principal amount or a change of control rate equal to the greater of 110% of their principal amount or the consideration that would be received by the holders for the underlying shares in the change of control transaction. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares, valued for that purpose at 92.5% of their prevailing market price.

     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 will likely 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 attract drilling program capital for participation in our non-operated initiatives. 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, cash flows from operations and anticipated borrowing base availability under our credit facility to provide adequate working capital to meet our short-term capital expenditure objectives. 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 Private Litigation Reform Act of 1995. 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, gas gathering 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. Borrowing under our secured credit facility bear interest at fluctuating market-based rates. Accordingly, our interest expenses are sensitive to market changes, which exposes us to interest rate risk on current and future borrowing under the facility.

     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

24

commitments. The following table lists our minimum annual commitments as of December 31, 2007 under these instruments.

	Operating Leases						Other		Long Term
Year	Equipment		Premises		Total		Commitments(1)		Debt
2008	$	1,971,732	$	245,383	$	2,217,115	$	340,000	$	388,856
2009		1,848,198		246,864		2,095,062		2,045,000		419,139
2010		1,779,118		247,815		2,026,933		—		36,408,714	(2)
2011		1,567,866		252,389		1,820,255		—		42,747,454
2012 and thereafter		435,685		277,329		713,014		—		585,608
Total	$	7,602,599	$	1,269,780	$	8,872,379	$	2,385,000	$	80,549,771

(1)	Reflects (i) obligations of $240,000 under a guaranty secured by a certificate of deposit provided for bank debt of a limited liability company in which we previously held an interest and (ii) commitments under a purchase contract for an airplane.
(2)	Excludes an allocation of $1,043,222 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features.

Related Party Transactions

     Because we operate through subsidiaries and affiliated drilling programs, our corporate structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. 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 13 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. During 2007, we recognized an impartment charge of $964,000 for exploratory well costs that had been capitalized for less than one year pending our assessment of reserves for the project.

Item 7A. Quantitative Disclosure About Market Risk

     None

25

Item 8. Financial Statements and Supplementary Data

	Page
Management’s Report on Internal Controls over Financial Reporting		F-1
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated Balance Sheets — December 31, 2007 and 2006		F-5
Consolidated Statements of Operations — For the years ended December 31, 2007, 2006 and 2005		F-6
Consolidated Statements of Changes in Shareholders’ Equity — For the years ended December 31, 2007, 2006 and 2005		F-7
Consolidated Statements of Cash Flows — For the years ended December 31, 2007, 2006 and 2005		F-8
Notes to Consolidated Financial Statements		F-9
Supplementary Oil and Gas Reserve Information — Unaudited		F-25
Supplementary Selected Quarterly Financial Data — Unaudited		F-27

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     None

Item 9A. Controls and Procedures

Management’s Responsibility for Financial Statements

     Our management is responsible for the integrity and objectivity of all information presented in this report. The consolidated financial statements included in this report have been prepared in accordance with U.S. GAAP and reflect management’s judgments and estimates on the effect of the reported events and transactions.

Disclosure Controls and Procedures

     Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on management’s evaluation as of December 31, 2007, our chief executive officer and chief financial officer 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 periods required under the Exchange Act, and that this information is accumulated and communicated to our management to allow timely decisions about required disclosures.

Management’s Report on Internal Control over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007 using the criteria established underInternal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management concluded that our internal control over financial reporting was effective based on those criteria as of December 31, 2007. Management reviewed the results of their assessment with the audit committee of our board of directors. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Hall, Kistler & Company LLP, our independent registered public accounting firm, as stated in their report appearing on page F-2 of this report.

Changes in Internal Control over Financial Reporting

     We regularly review our system of internal control over financial reporting to ensure the maintenance of an effective internal control environment. There were no changes in our internal control over financial reporting during the period covered by this report that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B. Other Information

     None.

26

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers

     Our executive officers are listed in the following table, together with their age and term of service with the Company.

				Officer
Name	Age		Position	Since
William S. Daugherty		53	Chairman of the Board, President and Chief Executive Officer		1993
William G. Barr III		58	Vice President		1993
D. Michael Wallen		53	Vice President		1995
Michael P. Windisch		33	Chief Financial Officer		2002

     A summary of the business experience and background of our directors and executive officers is set forth below.

     William S. Daughertyhas 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 Daugherty Petroleum, Inc., our direct operating subsidiary (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 and the Unconventional Resources Technology Advisory Committee for the Department of Energy. 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 IIIhas 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 of KOGA and as a member of its Board of Directors, as well as Vice Chairman of the Kentucky Gas Pipeline Authority. Mr. Barr received his Juris Doctorate from the University of Kentucky, Lexington, Kentucky.

     D. Michael Wallenhas 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, as well as the Board of Directors of the Research Partnership to Secure Energy for America. 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. Windischhas 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, where he now serves on the Finance Advisory Board.

27

Incorporation of Information by Reference

     The balance of Part III to this report is incorporated by reference to the proxy statement for our 2008 annual meeting of shareholders to be filed with the Securities and Exchange Commission on or before April 29, 2008.

Part IV

Item��15. Exhibits, Financial Statement Schedules

Exhibit
Number	Description of Exhibit
3.1	Notice of Articles, certified on June 3, 2004 by the Registrar of Corporations under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
3.2	Alteration to Notice of Articles, certified on June 25, 2004 by the Registrar of Corporations under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
3.3	Articles dated June 25, 2004, as amended and restated for corporate transition under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.3 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
10.1	1997 Stock Option Plan (incorporated by reference to Exhibit 10[a] to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2002).
10.2	2001 Stock Option Plan (incorporated by reference to Exhibit 10[b] to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2002).
10.3	2003 Incentive Stock and Stock Option Plan (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.4	Asset Purchase and Sale Agreement dated as of January 17, 2006 among Duke Energy Gas Services, LLC, NGAS Gathering, LLC and Daugherty Resources, Inc. (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated January 19, 2006).
10.5	Securities Purchase Agreement dated as of December 13, 2005 among NGAS Resources, Inc. and the investors named therein (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated December 14, 2005).
10.6	Form of 6% convertible notes issued pursuant to the Securities Purchase Agreement dated as of December 13, 2005 among NGAS Resources, Inc. and the investors named therein (incorporated by reference to Exhibit 10.2 to current report on Form 8-K [File No. 0-12185] dated December 14, 2005).
10.7	Credit Agreement dated as of September 8, 2006 among NGAS Resources, Inc., Daugherty Petroleum, Inc. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated September 8, 2006).
10.8	Form of Change of Control Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.9 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.9	Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).

28

Exhibit
Number	Description of Exhibit
10.10	Form of Long Term Incentive Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.11 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.11	Form of general partnership agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.11 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.12	Form of limited partnership agreement with sponsored investment partnerships (incorporated by reference to Exhibit 10.12 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.13	Form of assignment of drilling rights with sponsored drilling programs (incorporated by reference to Exhibit 10.13 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.14	Form of drilling and operating agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.14 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
11.1	Computation of Earnings Per Share (included in Note 10 to the accompanying consolidated financial statements)
21.0	Subsidiaries (incorporated by reference to Exhibit 21.1 to annual report on Form 10-K [File No. 0-12185] for the year ended December 31, 2006).
23.1	Consent of Hall, Kistler & Company LLP.
23.2	Consent of Kraft, Berger, Grill, Schwartz, Cohen & March, LLP.
23.3	Consent of Wright & Company, Inc., independent petroleum engineers.
24.1	Power of Attorney.
31.1	Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 202.
32.2	Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

29

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 11, 2008.

NGAS RESOURCES, INC.

By:	/s/ William S. DaughertyWilliam S. Daugherty,	By:	/s/ Michael P. WindischMichael 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.

Name		Date
William S. Daugherty James K. Klyman* Thomas F. Miller*
By:	/s/ William S. DaughertyWilliam S. Daugherty,	March 11, 2008
	Individually and *as attorney-in-fact

30

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, 2007. In making this assessment, management used the criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that, as of December 31, 2007, the Company’s internal control over financial reporting is effective based on those criteria.

     The Company’s independent registered public accounting firm, Hall, Kistler & Company LLP, has audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, as stated in their report appearing on page F-2.

/s/ William S. Daugherty	/s/ Michael P. Windisch
William S. Daugherty,	Michael P. Windisch,
President and Chief Executive Officer	Chief Financial Officer
March 7, 2008	March 7, 2008

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.

We have audited the internal control over financial reporting of NGAS Resources, Inc. as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management of NGAS Resources, Inc. is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on 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 the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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 for external purposes in accordance with generally accepted accounting principles. 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, NGAS Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets and the related consolidated statements of operations, shareholders’ equity and cash flows of NGAS Resources, Inc. and subsidiaries, and our report dated March 7, 2008 expressed an unqualified opinion thereon.

/s/ Hall, Kistler & Company LLP
Hall, Kistler & Company LLP

Canton, Ohio
March 7, 2008

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.

We have audited the accompanying consolidated balance sheets of NGAS Resources, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the years then ended. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of NGAS Resources, Inc. and subsidiaries as of December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

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, 2007, 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 7, 2008 expressed an unqualified opinion thereon.

/s/ Hall, Kistler & Company LLP
Hall, Kistler & Company LLP

Canton, Ohio
March 7, 2008

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of
NGAS RESOURCES, INC.

We have audited the consolidated statements of operations, changes in shareholders’ equity and cash flows of NGAS RESOURCES, INC for the year 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 audit 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 audit provides a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the results of the company’s operations, changes in shareholders’ equity and its cash flows for the year 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 LLP
Chartered Accountants
(Formerly Kraft, Berger, Grill, Schwartz, Cohen & March LLP)

Toronto, Ontario
March 7, 2008

F-4

NGAS Resources, Inc.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007			2006
ASSETS
Current assets:
Cash	$	2,816,678		$	14,431,977
Accounts receivable		7,909,943			9,108,574
Prepaid expenses and other current assets		505,778			1,108,734
Loans to related parties		7,654			7,147
Total current assets		11,240,053			24,656,432
Bonds and deposits		535,445			533,695
Oil and gas properties		183,823,702			144,217,532
Property and equipment		3,689,636			3,342,571
Loans to related parties		249,410			257,430
Deferred financing costs		1,706,852			2,264,022
Other non-current assets		3,242,790			2,634,271
Goodwill		313,177			313,177
Total assets	$	204,801,065		$	178,219,130
LIABILITIES
Current liabilities:
Accounts payable	$	6,649,809		$	9,286,849
Accrued liabilities		3,655,684			3,998,978
Customer drilling deposits		2,857,806			12,173,905
Long term debt, current portion		388,856			24,000
Total current liabilities		13,552,155			25,483,732
Deferred income taxes		9,218,770			8,035,779
Long term debt		80,160,915			66,922,744
Deferred compensation		1,960,020			1,419,776
Total liabilities		104,891,860			101,862,031
SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
26,136,064 Common shares (2006 – 21,788,551)		108,842,526			84,531,832
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital – options and warrants		3,484,148			3,073,287
Contributed surplus		1,043,222			1,396,074
To be issued:
9,185 Common shares (2006 – 9,185)		45,925			45,925
		113,392,191			89,023,488
Deficit		(13,482,986	)		(12,666,389	)
Total shareholders’ equity		99,909,205			76,357,099
Total liabilities and shareholders’ equity	$	204,801,065		$	178,219,130

See accompanying notes.

F-5

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2007			2006			2005
REVENUE
Contract drilling	$	34,334,829		$	50,108,545		$	43,787,075
Oil and gas production		28,148,689			24,233,102			16,317,144
Gas transmission and compression		7,719,308			5,478,642			2,123,870
Total revenue		70,202,826			79,820,289			62,228,089
DIRECT EXPENSES
Contract drilling		26,773,028			39,231,521			34,731,234
Oil and gas production		7,648,558			6,687,874			4,157,356
Gas transmission and compression		3,657,977			3,094,504			1,588,822
Impairment of oil and gas assets		964,000			346,718			—
Total direct expenses		39,043,563			49,360,617			40,477,412
OTHER EXPENSES (INCOME)
Selling, general and administrative		12,920,591			13,201,107			11,251,759
Options, warrants and deferred compensation		1,069,306			1,558,676			1,274,056
Depreciation, depletion and amortization		10,416,696			8,266,056			4,750,134
Bad debt expense		215,000			—			—
Interest expense		6,330,760			4,321,815			1,725,250
Interest income		(323,655	)		(356,302	)		(270,382	)
Gain on sale of assets		54,304			(3,197,834	)		(21,367	)
Other, net		53,434			519,692			222,036
Total other expenses		30,736,436			24,313,210			18,931,486
INCOME BEFORE INCOME TAXES		422,827			6,146,462			2,819,191
INCOME TAX EXPENSE		1,239,424			4,154,024			1,866,435
NET INCOME (LOSS)	$	(816,597	)	$	1,992,438		$	952,756
NET INCOME (LOSS) PER SHARE
Basic	$	(0.04	)	$	0.09		$	0.05
Diluted	$	(0.04	)	$	0.09		$	0.05
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		22,240,429			21,510,594			17,350,550
Diluted		22,240,429			22,922,615			19,126,555

See accompanying notes.

F-6

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

	Years Ended December 31,
	2007						2006						2005
	Shares			Amount			Shares			Amount			Shares			Amount
COMMON STOCK
Beginning balance		21,788,551		$	84,531,832			21,357,628		$	82,371,189			15,605,208		$	54,929,887
Issued in registered direct placement		4,200,000			23,687,955			—			—			—			—
Issued as bonus under incentive plan		10,430			61,010			65,945			468,612			154,415			900,856
Issued upon exercise of options and warrants		137,083			561,729			336,106			1,472,026			2,143,527			10,983,938
Issued upon conversion of convertible notes		—			—			—			—			3,439,478			15,466,208
Issued for contract settlement		—			—			28,872			220,005			15,000			90,300
Ending balance		26,136,064			108,842,526			21,788,551			84,531,832			21,357,628			82,371,189
Treasury stock		(21,000	)		(23,630	)		(21,100	)		(23,630	)		(21,100	)		(23,630	)
Paid-in-capital – options and warrants					3,484,148						3,073,287						2,743,806
Contributed surplus					1,043,222						1,396,074						1,748,926
To be issued		9,185			45,925			9,185			45,925			9,185			45,925
DEFICIT
Beginning balance					(12,666,389	)					(14,658,827	)					(15,611,583	)
Net income (loss)					(816,597	)					1,992,438						952,756
Ending balance					(13,482,986	)					(12,666,389	)					(14,658,827	)
TOTAL SHAREHOLDERS’ EQUITY				$	99,909,205					$	76,357,099					$	72,227,389

See accompanying notes.

F-7

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2007			2006			2005
OPERATING ACTIVITIES
Net income (loss)	$	(816,597	)	$	1,992,438		$	952,756
Adjustments to reconcile net income to net cash provided by operating activities:
Incentive bonus paid in common shares		61,010			468,612			900,856
Options, warrants and deferred compensation		1,069,306			1,558,676			1,274,056
Contract settlement paid in common shares		—			220,005			85,875
Depreciation, depletion and amortization		10,416,696			8,266,056			4,750,134
Impairment of oil and gas assets		964,000			346,718
Write-down of investments		—			—			55,454
Bad debt expense		215,000			—			—
Loss (gain) on sale of assets		54,304			(3,197,834	)		(21,367	)
Deferred income taxes		1,182,991			4,154,024			1,828,323
Changes in assets and liabilities:
Accounts receivable		983,631			(2,224,874	)		(4,601,985	)
Prepaid expenses and other current assets		602,956			2,053,113			(1,009,673	)
Other non-current assets		(608,519	)		(1,984,271	)		—
Accounts payable		(2,637,040	)		3,847,412			2,057,711
Accrued liabilities		(343,294	)		(1,789,576	)		2,250,978
Customer drilling deposits		(9,316,099	)		(11,454,070	)		10,975,974
Net cash provided by operating activities		1,828,345			2,256,429			19,499,092
Proceeds from sale of assets		394,720			6,841,368			375,519
Purchase of property and equipment		(1,571,772	)		(1,026,778	)		(1,724,159	)
Increase in bonds and deposits		(1,750	)		(101,000	)		(308,045	)
Additions to oil and gas properties		(49,654,013	)		(49,526,536	)		(41,661,586	)
Net cash used in investing activities		(50,832,815	)		(43,812,946	)		(43,318,271	)
FINANCING ACTIVITIES
Decrease in loans to related parties		7,513			26,035			209,281
Proceeds from issuance of common shares		24,131,483			1,472,026			10,478,830
Payments of deferred financing costs		—			(429,819	)		(2,821,496	)
Proceeds from issuance of long term debt		13,360,000			31,000,000			43,168,690
Payments of long term debt		(109,825	)		(24,000	)		(15,121,246	)
Net cash provided by financing activities		37,389,171			32,044,242			35,914,059
Change in cash		(11,615,299	)		(9,512,275	)		12,094,880
Cash, beginning of year		14,431,977			23,944,252			11,849,372
Cash, end of year	$	2,816,678		$	14,431,977		$	23,944,252
SUPPLEMENTAL DISCLOSURE
Interest paid	$	6,343,734		$	4,411,157		$	1,658,730
Income taxes paid		—			—			210,000
SUPPLEMENTAL SCHEDULE OF NON-CASH FINANCING ACTIVITIES
Common shares issued upon conversion of notes		—			—			15,466,208

See accompanying notes.

F-8

NGAS Resources, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

     (a) General. The accompanying consolidated financial statements of NGAS Resources, Inc. (NGAS) for the years ended December 31, 2007 and 2006 have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). All of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are stated in U.S. dollars. NGAS is organized under the laws of British Columbia, and we previously prepared our financial statements, including the accompany consolidated financial statements for the year ended December 31, 2005, in accordance with accounting principles generally accepted in Canada (Canadian GAAP). The laws of British Columbia were changed during 2005 to permit publicly held U.S. reporting companies organized in that jurisdiction to elect U.S. GAAP and engage U.S. auditors. We made this election at the beginning of 2006. Our adoption of U.S. GAAP did not have a material effect on our reported financial condition or results for prior periods and did not require us to restate any previously issued financial statements, which included reconciliations between items with different treatment under Canadian and U.S. GAAP.

     (b) Basis of Consolidation. The consolidated financial statements include the accounts of NGAS, our wholly owned subsidiary, Daugherty Petroleum, Inc. (DPI), a Kentucky corporation, and DPI’s wholly owned subsidiaries, NGAS Gathering, LLC (NGAS Gathering), Sentra Corporation (Sentra) and NGAS Securities, Inc. (NGAS Securities). DPI conducts all oil and gas drilling and production operations, including construction of field-wide gathering systems. NGAS Gathering owns and operates the open-access section of our gathering system acquired in 2006. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky. NGAS Securities provides marketing support services for private placement financings. The consolidated financial statements also reflect our interests in a total of 37 drilling programs sponsored by DPI to participate in many of our drilling initiatives. DPI maintains a combined interest as both general partner and an investor in the drilling program ranging from 12.5% to 75%, subject to specified increases after certain distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References in the consolidated financial statements to the Company, we, our or us include DPI, its subsidiaries and interests in sponsored drilling programs.

     (c) Estimates. The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates used in impairment tests of goodwill and other long-lived assets, estimates of future development, dismantlement and abandonment costs and estimates relating to future oil and gas revenues and expenses. The evaluations required for these estimates involve significant uncertainties, and actual results could differ from the estimates.

     (d) Oil and Gas Properties.

          (i)Proved. We follow the successful efforts method of accounting for oil and gas producing activities. Under this method, exploratory well costs are initially capitalized but charged to expense if and when the well is determined to be unsuccessful. Costs resulting from exploratory discoveries and development costs for proved properties, whether or not successful, are capitalized and amortized on a unit-of-production basis method over the remaining life of the proved developed reserves estimated for the underlying properties. Development costs include leasehold acquisition costs for proved properties and the cost of support equipment and facilities. We evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. We follow Statement of Financial Accounting Standards (SFAS) No. 144,Impairment of Long-Lived Assets, for these evaluations. Unamortized capital costs are reduced to fair value if the undiscounted future net cash flows from our interest in the property’s estimated proved reserves are less than the asset’s net book value.

F-9

          (ii)Unproved. Unproved properties consist of costs incurred to acquire unproved leases and unproved reserves. Unproved lease acquisition costs are capitalized and amortized based on a composite of factors, including past success, experience and average lease-term lives. Unamortized lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.

          (iii)Exploratory Wells. Under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies, drilling costs for exploratory wells are initially capitalized but generally must be charged to expense unless the wells are determined to be successful within one year after completion of drilling. Circumstances that permit continued capitalization of exploratory drilling costs are addressed by the Financial Accounting Standards Board (FASB) under Staff Position (FSP) No. 19-1,Accounting for Suspended Well Costs. 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 and the economic and operating viability of the project. If the exploratory well does not meet both criteria, its capitalized costs are expensed, net of any salvage value. Annual disclosures are required under FSP No. 19-1 to provide information about management’s evaluation of capitalized exploratory well costs, including disclosure of (i) net changes from period to period in the costs for wells that are pending the determination of proved reserves, (ii) the amount of any exploratory well costs that have been capitalized for more than one-year after the completion of drilling and (iii) an aging of suspended exploratory well costs and the number of wells affected. See Note 2 – Oil and Gas Properties.

          (iv)Other Properties and Equipment. Other properties and equipment include well equipment, gathering and transmission facilities, office equipment and other fixed assets. These items are recorded at cost and depreciated using either the straight-line method based on expected life of the assets, ranging from 3 to 25 years, or the unit-of-production method over the estimated reserve life of the underlying properties.

     (e) Revenue Recognition. We recognize 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 our 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 we have a contractual right to receive the revenue.

     (f) Regulated Activities.

          (i)Sentra. Regulated operations of Sentra, our gas utility subsidiary, are subject to the provisions of 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 evaluation of Sentra’s recovery of its purchased gas costs. For the years ended December 31, 2007, 2006 and 2005, gas transmission and compression revenue includes gas utility sales from Sentra’s regulated operations aggregating $365,951, $273,180 and $323,159, respectively.

          (ii)NGAS Securities. NGAS Securities is a registered broker-dealer and member of the Financial Industry Regulatory Authority. 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 12.5% of its aggregate indebtedness. At December 31, 2007, NGAS Securities had net capital of $69,547 and aggregate indebtedness of $50,180.

     (g) Investments. Long term investments in which we do not have significant influence are accounted for using the cost method. In the event of a permanent decline in value, an investment is written down to estimated realizable value, and any resulting loss is charged to earnings.

F-10

     (h) Deferred Financing Costs. Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs.

     (i) Goodwill. Goodwill is tested for impairment at least annually and more frequently if indicated under SFAS No. 142,Goodwill and Other Intangible Assets. See Note 6 – Goodwill. Under these procedures, the fair value of goodwill or other reporting unit is compared with its carrying amount. If the carrying amount exceeds its fair value, an impairment test must be performed to compare the implied fair value of the reporting unit goodwill with its carrying amount to determine any impairment loss.

     (j) Customer Drilling Deposits. Net proceeds received under DPI’s drilling contracts with sponsored drilling programs are recorded as customer drilling deposits at the time of receipt. We recognize 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 payments for wells that were not yet drilled as of the balance sheet dates. See Note 7 – Customer Drilling Deposits.

     (k) Deferred Income Taxes. We provide for income taxes using the asset and liability method. This 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. Deferred 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.

     (l) Stock Options. We account for stock options under the fair value recognition and compensation measurement provisions of SFAS No. 123(R),Share-Based Payment, which we adopted retroactively under its Canadian GAAP equivalent at the beginning of 2004. See Note 9 – Capital Stock.

     (m) Deferred Compensation. We have long term incentive agreements with four of our executive officers and one key employee, providing for incentive awards based on their annual base salary if they continue to serve in their positions until February 25, 2009 or until their employment is terminated prior to that date 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 rates.

     (n) Reclassifications and Adjustments. Certain amounts included in the 2006 and 2005 consolidated financial statements have been reclassified to conform to the 2007 presentation.

     (o) Comprehensive Income and Loss. The accompanying consolidated financial statements do not include statements of comprehensive income (loss) since we had no items of comprehensive income or loss for the periods reported.

Note 2. Oil and Gas Properties

     (a) Property Acquisitions and Divestitures.

          (i)Acquisition of Transmission System. In March 2006, our NGAS Gathering subsidiary acquired an open-access gas transmission system spanning 116 miles in southeastern Kentucky and southwestern Virginia for $18 million. We operated this system since October 2004 and augmented it after the acquisition through two high-pressure lateral upgrades. Most of our Appalachian production is delivered through this system, which had daily throughput of over 17,000 Dth of controlled and third-party gas as of December 31, 2007.

          (ii)Purchase and Sale of Royalty Interests. In August 2006, we acquired overriding royalty interests averaging 2.25%, together with related participation and pipeline capacity rights, for properties we operate under a farmout in Harlan County, Kentucky and Lee County, Virginia. The purchase price for the acquired assets was $1.5 million. We retained the participation and pipeline capacity rights and sold the overriding royalty interests to a third party, effective September 1, 2006, for $2.0 million.

F-11

          (iii)Purchase and Sale of Lease Position. In November 2006, we completed the sale of our oil and gas lease position in the Williston Basin for $4.8 million. We retained an overriding royalty interest of 1.35% in the lease position. The position was assembled under a leasing program initiated in 2005 and covered 18,411 gross (14,864 net) acres in the southwestern portion of Dunn County, North Dakota. The sale resulted in an after-tax gain of approximately $1.6 million.

     (b) Capitalized Costs and DD&A. The following table presents the capitalized costs and accumulated depreciation, depletion and amortization (DD&A) for our oil and gas properties, gathering facilities and well equipment as of December 31, 2007 and 2006.

	As of December 31,
	2007			2006
Proved oil and gas properties	$	148,981,923		$	110,169,303
Unproved oil and gas properties		3,876,721			3,000,465
Gathering facilities and well equipment		55,370,995			46,369,858
		208,229,639			159,539,626
Accumulated DD&A		(24,405,937	)		(15,322,094	)
Net oil and gas properties and equipment	$	183,823,702		$	144,217,532

          (c)Suspended Well Costs. We adopted FSP No. 19-1,Accounting for Suspended Well Costs, effective January 1, 2005. Based on our evaluation at the time of adoption, we had found proved reserves for all our exploratory wells within one year after completion of drilling. We added suspended well costs late in 2005 and during 2006 for an exploratory program to test the shallow New Albany shale formation in western Kentucky. Based on the criteria of FSP No. 19-1, we expensed suspended well costs for the first three wells in that program during 2006 and for the remaining 27 wells in the program during the second quarter of 2007. The following table reflects the net changes in capitalized exploratory well costs during each of the years presented:

	2007			2006			2005
Beginning balance at January 1	$	964,000		$	43,700		$	—
Additions pending determination of proved reserves		—			1,099,000			43,700
Reclassifications to proved reserves		—			—			—
Charged to expense		(964,000	)		(178,700	)		—
Ending balance at December 31	$	—		$	964,000		$	43,700

     The following table provides an aging of capitalized exploratory well costs at December 31, 2007, 2006 and 2005, based on the dates that drilling was completed. As of those dates, we had no wells for which exploratory wells costs had been capitalized for more than one year after completion of drilling.

	As of December 31,
	2007		2006		2005
Exploratory well costs capitalized for one year or less	$	—	$	964,000	$	43,700
Exploratory well costs capitalized for more than one year		—		—		—
Balance at December 31	$	—	$	964,000	$	43,700

Note 3. Property and Equipment

     The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of December 31, 2007 and 2006.

F-12

	As of December 31,
	2007			2006
Land	$	12,908		$	12,908
Building improvements		58,051			48,350
Machinery and equipment		3,170,601			2,680,174
Office furniture and fixtures		168,217			129,031
Computer and office equipment		578,317			569,877
Vehicles		1,869,551			1,607,554
		5,857,645			5,047,894
Accumulated depreciation		(2,168,009	)		(1,705,323	)
Net other property and equipment	$	3,689,636		$	3,342,571

Note 4. Loans to Related Parties

     We extended loans to several of our shareholders and officers prior to 2003. The loans to shareholders are collateralized by their ownership interests in our drilling programs and are repayable from their share of program production revenues for periods ranging from five to ten years, with a balloon payment at maturity. These loans aggregated $85,635 at December 31, 2007 and $93,148 at December 31, 2006. They bear interest at 6% per annum. The loans receivable from officers totaled $171,429 at December 31, 2007 and 2006. These loans are non-interest bearing and unsecured.

Note 5. Deferred Financing Costs

     Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 8 – Long Term Debt. Upon conversion of 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 our outstanding notes and credit facility aggregated $1,706,852 at December 31, 2007 and $2,264,022 at December 31, 2006, net of accumulated amortization totaling $1,479,494 and $922,324, respectively.

Note 6. Goodwill

     Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and was amortized over ten years on a straight-line basis until 2002, when we adopted the Canadian equivalent of SFAS No. 142,Goodwill and Other Intangible Assets. Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment at least annually. Our annual analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of December 31, 2007 and 2006, with unamortized goodwill of $313,177.

Note 7. Customer Drilling Deposits

     Net proceeds received under drilling contracts with sponsored programs are recorded as customer drilling deposits at the time of receipt. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits aggregating $2,857,806 at December 31, 2007 and $12,173,905 at December 31, 2006 represent unapplied drilling contract payments for wells that were not yet drilled as of the balance sheet dates.

Note 8. Long Term Debt

     (a) Convertible Notes. We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment from the issuance of 4.2 million shares of our common stock in November 2007, based on our net proceeds of approximately $23.7 million. See Note 9 – Capital Stock. We will be entitled to redeem the notes at 100% of their principal amount plus accrued and unpaid interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. Upon any event of default under the notes or any change of control, we may be required to redeem the notes at a default rate equal to

F-13

125% of their principal amount or at a change of control rate equal to the greater of 110% of their principal amount or the consideration that would be received by the holders for the underlying shares in the change of control transaction. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares, valued for that purpose at 92.5% of their prevailing market price.

     (b) Credit Facility. We have a senior secured revolving credit facility maintained by DPI with KeyBank National Association, as agent and primary lender. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $65 million at December 31, 2007. Outstanding borrowings under the facility have a five-year maturity and bear interest at fluctuating rates ranging from 1.5% to 2.5% above quoted LIBOR rates, depending on our borrowing base utilization. The credit agreement for the facility also provides for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, 2007, outstanding borrowings under the facility aggregated $42.3 million, with $2 million in letters of credit. The facility is secured by liens on our oil and gas properties. Obligations under the facility are guaranteed by NGAS.

     (c) Equipment Loan. In September 2007, we obtained a $2.1 million loan from Central Bank & Trust Co. to finance two drilling rigs and related equipment previously purchased by DPI and leased to one of our drilling contractors. The loan is secured by the leased equipment and is guaranteed by NGAS. It bears interest at 8% per annum and is repayable in monthly installments over a five-year term, with $2,014,175 outstanding at December 31, 2007.

     (d) Acquisition Debt. We issued a note for $854,818 to finance our 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 production revenues, the property has remained inactive. The outstanding acquisition debt was $318,818 at December 31, 2007 and $342,818 at December 31, 2006.

     (e) Total Long Term Debt and Maturities. The following tables summarize our total long term debt at December 31, 2007 and 2006 and the principal payments due each year through 2012 and thereafter.

	Principal Amount Outstanding at
	December 31,
	2007			2006
Total long term debt (including current portion)(1)	$	80,549,771		$	66,946,744
Less current portion		388,856			24,000
Total long term debt(1)	$	80,160,915		$	66,922,744
Maturities of Debt
2008	$	388,856
2009		419,139
2010		36,408,714	(1)
2011		42,747,454
2012 and thereafter		585,608

(1) Reflects allocations of $1,043,222 at December 31, 2007 and $1,396,074 at December 31, 2006 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features and related warrants, which expired unexercised in August 2006.

Note 9. Capital Stock

     (a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at December 31, 2007 or 2006.

     (b) Common Shares. In November 2007, we completed a registered direct placement of 4.2 million common shares under our existing shelf registration statement at $6.00 per share. The following table reflects the direct placement and other transactions involving our common stock during the reported periods.

F-14

	Number of
Common Shares Issued	Shares		Amount
Balance, December 31, 2005		21,357,628	$	82,371,189
Issued to employees as incentive bonus		65,945		468,612
Issued upon exercise of stock options and warrants		336,106		1,472,026
Issued for contract settlement		28,872		220,005
Balance, December 31, 2006		21,788,551		84,531,832
Issued in registered direct placement		4,200,000		23,687,955
Issued as stock awards under incentive plan		10,430		61,010
Issued upon exercise of stock options and warrants		137,083		561,729
Balance, December 31, 2007		26,136,064	$	108,842,526
Paid In Capital – Options and Warrants
Balance, December 31, 2005			$	2,743,806
Recognized				975,468
Expired				(565,946	)
Accreted(1)				(80,041	)
Balance, December 31, 2006				3,073,287
Recognized				529,062
Exercised				(118,201	)
Balance, December 31, 2007			$	3,484,148
Contributed Surplus
Balance, December 31, 2005				1,748,926
Accreted(1)				(352,852	)
Balance, December 31, 2006				1,396,074
Accreted(1)				(352,852	)
Balance, December 31, 2007			$	1,043,222
Common Shares to be Issued
Balance, December 31, 2007, 2006 and 2005		9,185	$	45,925

(1) Reflects accretion of the equity components allocated to our 6% convertible notes and related warrants issued in 2005.

     (c) Stock Options and Awards. We maintain three stock plans for the benefit of our directors, officers, employees and certain consultants or advisors. The plans provide for the grant of options to purchase up to 3,600,000 common shares and, in the case of our most recent plan, either stock awards or options for an aggregate of up to 4,000,000 common shares. Option grants under all the plans must be 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 2007 and 2006, stock awards and option grants were made under the third plan for a total of 10,430 shares and 65,945 shares, respectively. The following table shows transactions in stock options during 2007 and 2006.

							Weighted Average
	Issued			Exercisable			Exercise Price
Balance, December 31, 2005		2,985,000			571,250		$	4.67
Vested		—			509,583			4.26
Exercised		(135,000	)		(135,000	)		4.05
Forfeited		(35,000	)		—			6.02
Balance, December 31, 2006		2,815,000			945,833			4.68
Vested		—			920,833			6.03
Exercised		(127,083	)		(127,083	)		3.17
Forfeited		(6,667	)		—			6.02
Balance, December 31, 2007		2,681,250			1,739,583			4.75

F-15

     At December 31, 2007, the exercise prices of options outstanding under our stock option plans ranged from $1.02 to $7.04 per share, and their weighted average remaining contractual life was 1.94 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2007.

Options Outstanding					Options Exercisable
			Weighted	Weighted		Weighted
Exercise			Average	Average		Average
Price			Remaining	Exercise		Exercise
or Range		Number	Life (years)	Price	Number	Price
$         1.02		100,000	0.01	$1.02	100,000	$1.02
4.03	4.09	1,776,250	1.77	4.05	976,250	4.06
6.02	7.04	805,000	2.55	6.75	663,333	6.91
		2,681,250			1,739,583

     In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R),Share-Based Payment, which we adopted retroactively under its Canadian GAAP equivalent in 2004. We use the Black-Scholes pricing model to determine the fair value of each stock option at the grant date, and we recognize the compensation cost ratably over the vesting period. For the periods presented in the interim 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 $529,062 in 2007 and $975,468 in 2006.

     (d) Common Stock Purchase Warrants. We have issued common stock purchase warrants in various financing transactions. The following table shows transactions in purchase warrants during 2007 and 2006.

	Warrants			Warrants		Weighted Average
	Issued			Exercisable		Exercise Price
Balance, December 31, 2005		1,314,383			1,314,383	$	10.46
Exercised		(201,106	)				4.60
Expired		(1,103,277	)				11.59
Balance, December  31, 2006		10,000			10,000		4.03
Exercised		(10,000	)				4.03
Balance, December 31 2007		—			—		N/A

Note 10. Income Taxes

     The following table sets forth the components of income tax expense for each of the years presented in the consolidated financial statements.

	Year Ended December 31,
	2007		2006		2005
Current	$	—	$	—	$	38,113
Deferred		1,239,424		4,154,024		1,828,322
Total income tax expense	$	1,239,424	$	4,154,024	$	1,866,435

     The following table sets forth a reconciliation between prescribed tax rates and the effective tax rate for our income tax expense in each of the years presented in the consolidated financial statements.

F-16

	Year Ended December 31,
	2007		2006		2005
Income tax computed at statutory combined basic income tax rates	$	169,131	$	2,458,585	$	1,004,196
Increase (decrease) in income tax resulting from:
Non-recognition of tax benefit from parent company net losses		1,031,288		1,670,217		629,546
Non-deductible expenses		18,286		25,222		17,891
Difference in tax rates between Canada and the United States		20,719		—		214,802
Total income tax expense	$	1,239,424	$	4,154,024	$	1,866,435

     The following table sets forth the components of our deferred income tax liabilities as of the end of each of the years presented in the consolidated financial statements.

	As of December 31,
	2007			2006			2005
Net operating loss carryforward and investment tax credit	$	6,390,068		$	5,303,421		$	4,359,412
Gold and silver properties		2,522,094			2,522,094			2,522,094
Oil and gas properties		(15,654,201	)		(10,661,622	)		(5,984,315	)
Property and equipment		(634,988	)		(605,960	)		(542,681	)
Less valuation allowance		(1,841,743	)		(4,593,712	)		(4,236,265	)
Deferred tax liabilities	$	(9,218,770	)	$	(8,035,779	)	$	(3,881,755	)

     As of December 31, 2007, we had net operating losses of $18,024,420 at the parent company level. Since no revenues are generated at that level for utilization of the related net operating loss carryforwards, we have 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.

Year of Expiry
2008	$	1,455,936
2009		903,491
2010		922,437
2014		1,313,828
2015		4,288,214
2026		5,306,344
2027		3,834,120
Total net operating loss carryforwards	$	18,024,420

Note 11. Income (Loss) Per Share

     The following table shows the computation of basic and diluted earnings per share (EPS) for each of the years presented.

	Year Ended December 31,
Numerator:	2007			2006		2005
Net income (loss) as reported for basic EPS	$	(816,597	)	$	1,992,438	$	952,756
Adjustments for diluted EPS		—			—		—
Net income (loss) for diluted EPS	$	(816,597	)	$	1,992,438	$	952,756

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	Year Ended December 31,
Denominator:	2007			2006		2005
Weighted average shares for basic EPS		22,240,429			21,510,594		17,350,550
Effect of dilutive securities:
Stock options		—			1,289,382		1,162,823
Warrants		—			122,639		613,182
Adjusted weighted average shares and assumed conversions for dilutive EPS		22,240,429			22,922,615		19,126,555
Basic EPS	$	(0.04	)	$	0.09	$	0.05
Diluted EPS	$	(0.04	)	$	0.09	$	0.05

Note 12. Employee Benefit Plan

     We maintain 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. Our matching contributions to the plan aggregated $172,075 in 2007, $123,596 in 2006 and $61,765 in 2005.

Note 13. Related Party Transactions

     (a) General. Because we operate through our subsidiaries and affiliated drilling programs, our corporate 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 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 program interest. DPI has interests in these programs ranging from 12.5% to 75%, subject to specified increases after certain distribution thresholds are reached. Each program enters into drilling and operating contracts with DPI or any third-party operator for all wells to be drilled by that program. The portion of the profit on drilling contracts attributable to DPI’s ownership interest in each of these programs is eliminated on consolidation. The following table lists the total revenues recognized from the performance of these contracts with sponsored drilling programs for each of the years presented.

Year	Contract Drilling Revenues
2007	$	34,334,829
2006		50,108,545
2005		43,787,075

     (c) Office Lease. The building in Lexington, Kentucky that houses our principal and administrative offices was acquired during 2006 by a company formed for that purpose by our four senior executive officers and a key employee. At the time of the sale, our lease covered 12,109 square feet at a monthly rent of $18,389 through expiration in February 2008. Following the sale of the building, we entered into a lease modification for an additional 1,743 square feet at a monthly rent of $2,542. In November 2007, we entered into lease renewals for a five-year term at monthly rents totaling $20,398, subject to annual escalations on the same terms as our prior lease. The terms of the initial lease modification and subsequent lease renewals were negotiated on our behalf by one of our independent directors appointed for that purpose by our board. The negotiations were conducted at arms’ length with the management company for the building, and the terms reflect prevailing rental rates with other tenants in our building and comparable office buildings in our locale.

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Note 14. Financial Instruments

     (a) Credit Risk. We grant credit to our customers, primarily located in the northeastern and central United States, in the normal course of business. We perform ongoing credit evaluations of customers’ financial condition and generally require no collateral. At times throughout the year, we 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, 2007 different from their estimated fair value, based upon discounted future cash flows using discount rates reflecting market conditions for similar instruments.

	Carrying		Fair
Financial Instrument:	Value		Value
Non-interest bearing long term debt	$	318,818	$	175,856
Loans to related parties		257,064		207,635

Note 15. Segment Information

     We have a single reportable operating segment for our oil and gas business based on the integrated way we are organized by management in making operating decisions and assessing performance. Although our financial reporting reflects our separate revenue streams from drilling, production and transmission activities and the direct expenses for each component, we do not consider the components as discreet operating segments under SFAS No. 131,Disclosure about Segments of an Enterprise and Related Information.

Note 16. Commitments

     We incurred operating lease expenses of $2,317,526 in 2007, $1,727,982 in 2006 and $704,597 in 2005. As of December 31, 2007, we had future obligations under operating leases and other commercial commitments in the amounts listed below.

	Operating		Other
Year	Leases		Commitments(1)		Total
2008	$	2,217,115	$	340,000	$	2,557,115
2009		2,095,062		2,045,000		4,140,062
2010		2,026,933		—		2,026,933
2011		1,820,255		—		1,820,255
2012 and thereafter		713,014		—		713,014
Total	$	8,872,379	$	2,385,000	$	11,257,379

(1) Reflects (i) obligations of $240,000 under a guaranty secured by a certificate of deposit provided for bank debt of a limited liability company in which DPI previously held an interest and (ii) commitments under a purchase contract for an airplane.

Note 17. Asset Retirement Obligations

     We have asset retirement obligations primarily for the future abandonment of oil and gas wells, and we maintain reserve accounts for part of these obligations under our drilling and operating agreements with sponsored programs. We account for these obligations under SFAS No. 143,Accounting for Asset Retirement Obligations, which 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 underlying long-lived asset. SFAS No. 143 also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation is generally determined on a units-of-production basis over the life of the asset, while the accretion escalates over the

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life of the asset, typically as production declines. The amounts recognized are based on numerous estimates and assumptions, including recoverable quantities of oil and gas, future retirement and site reclamation costs, inflation rates and credit-adjusted risk-free interest rates. The following table shows the changes in our asset retirement obligations during the years presented.

	Year Ended December 31,
	2007			2006			2005
Asset retirement obligations, beginning of the year	$	493,028		$	424,470		$	153,400
Liabilities incurred during the year		148,513			240,753			257,870
Liabilities settled during the year		(90,803	)		(206,323	)		—
Accretion expense recognized during the year		39,712			34,128			13,200
Asset retirement obligations, end of the year	$	590,450		$	493,028		$	424,470

Note 18. Recent Accounting Standards

     SFAS No. 160. In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements, which establishes accounting and reporting standards for noncontrolling or minority interests in a subsidiary, including changes in a parent’s ownership interest in a subsidiary. Under the new standard, noncontrolling interests in subsidiaries must be classified as a separate component of equity, and net income for both the parent and the noncontrolling interest must be disclosed on the consolidated statement of operations. SFAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008, and its disclosure requirements will then apply retrospectively for all prior periods presented. We are assessing the affect its adoption may have on our consolidated financial statements.

     SFAS No. 141(R). In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement provides revised guidance for recognizing and measuring assets acquired and liabilities assumed in a business combination. It also requires transactions costs for a business combination to be expensed as incurred. SFAS No. 141(R) will impact our accounting for any business acquisition we complete after 2008.

     EITF 07-1. In December 2007, the FASB ratified the consensus reached by the Emerging Issues Task Force (EITF) in EITF Issue No. 07-1,Accounting for Collaborative Arrangements. The consensus requires costs incurred and revenues generated from transactions with third parties in collaborative arrangements to be reported on separate line items in the income statement pursuant to EITF Issue No. 99-19,Reporting Revenue Gross as a Principal Versus Net as an Agent. The consensus also provides that income statement characterization of payments between the participants in a collaborative arrangement should be based on existing authoritative pronouncements or a reasonable, rational and consistently applied accounting policy election. EITF Issue No. 07-1 is effective for fiscal years beginning after December 15, 2008 and must be applied retrospectively for collaborative arrangements existing on the date of adoption. We are currently evaluating the affect of this consensus but do not anticipate any material impact on our consolidated results of operations or financial condition.

     EITF 6-11. In June 2007, the FASB ratified the consensus reached in ETIF Issue No. 6-11,Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. Under this consensus, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees under certain equity-based benefit plans should be recognized as an increase in additional paid-in capital. The consensus is effective in fiscal years beginning after December 15, 2007. The adoption of EITF 6-11 is not expected to have a material impact on our consolidated financial statements.

     FSP No. FIN 48–1. In May 2007, the FASB issued FSP No. FIN 48–1,Definition of Settlement in FASB Interpretation No. 48, which amends FIN 48 and provides guidance on determining whether a tax position is “effectively” settled, rather than the previously required “ultimately” settled, for the purpose of recognizing previously unrecognized tax benefits. The guidance must be retroactively applied for all periods in 2007. This has not required any retroactive adjustments to our consolidated financial statements.

     EITF 6-10. In March 2007, the FASB ratified the consensus reached by the EITF in Issue No. 6-10,Accounting for the Deferred Compensation and Post Retirement Benefit Aspects of Collateral Assignment Split-Dollar Life Insurance Arrangements. Under this consensus, an employer should recognize a liability for any

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postretirement benefit related to a collateral assignment split-dollar life insurance arrangement and should recognize and measure the underlying asset based on the substance of the arrangement. The consensus is effective for fiscal years beginning after December 15, 2007 and is not expected to have a material impact on our consolidated financial position or results of operations.

     SFAS No. 159. In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits fair value accounting for many financial instruments and related items that are not currently required to be measured at fair value. The objective is to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Our adoption of SFAS No. 159 at the beginning of 2008 is not expected to have a material impact on our consolidated financial condition or results of operations.

Note 19. Supplementary Information on Oil and Gas Development and Producing Activities

     (a) General. This Note provides audited information on our 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 our 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.

	Year Ended December 31,
	2007			2006			2005
Revenues	$	28,148,689		$	24,233,102		$	16,317,144
Production costs		(7,648,558	)		(6,687,874	)		(4,157,356	)
DD&A		(7,676,617	)		(6,501,001	)		(4,033,036	)
Income taxes (allocated on percentage of gross profits)		(815,435	)		(2,392,780	)		(1,043,591	)
Results of operations for producing activities	$	12,008,079		$	8,651,447		$	7,083,161

     (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 our oil and gas producing activities, all of which are conducted within the continental United States.

	Year Ended December 31,
	2007			2006			2005
Proved properties	$	148,981,923		$	110,169,303		$	90,859,568
Unproved properties		3,876,721			3,000,465			2,434,814
Gathering facilities and well equipment		55,370,995			46,369,858			20,703,321
		208,229,639			159,539,626			113,997,703
Accumulated DD&A		(24,405,937	)		(15,322,094	)		(8,212,363	)
Total	$	183,823,702		$	144,217,532		$	105,785,340

     (d) Costs Incurred in Oil and Gas Acquisition and Development Activities. The following table lists the costs we incurred in oil and gas acquisition and development activities for the years presented in the consolidated financial statements.

	Year Ended December 31,
Property acquisition costs:	2007		2006		2005
Unproved properties	$	1,405,603	$	1,928,556	$	1,833,077
Proved properties		35,185,951		21,714,182		27,732,167
Development costs		13,062,459		25,883,798		12,096,342
Total	$	49,654,013	$	49,526,536	$	41,661,586

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Note 20. Supplementary Oil and Gas Reserve Information – Unaudited

     (a) General. Our 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, our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves are summarized below. The reserve additions for each of the years presented in the table reflect results from our drilling initiatives, both development and exploratory, and revisions to previous estimates reflect new information derived from those initiatives. Revisions at the end of 2005 primarily reflect the relinquishment of several farmouts with previously recorded reserves and our limited production history in Leatherwood, where additions to our infrastructure enabled us to bring a backlog of unconnected wells on line sequentially during 2006, accounting for most of the upward revision at year end. During 2007, we elected to terminate a farmout covering all but 25% of our interest in the CDX–Arkoma field, resulting in a downward reserve revision of approximately 5 Bcf for our interests in this field. Our reserve estimates were further reduced by approximately 5 Bcf for our Leatherwood field based on lower production rates at the end of 2007 than projected production rates from our 2006 year-end reserve estimates for Leatherwood. While an upgrade to the main suction line for the field was installed during 2007 to alleviate higher line pressures and allow production at previously projected rates, we were not able to lower field operating pressures to match projected production rates as new wells were turned on line during the year.

										Crude Oil, Condensate
	Natural Gas									and Natural Gas Liquids
	(Mmcf)									(Mbbls)
	2007			2006			2005			2007			2006			2005
Proved developed and undeveloped reserves:
Beginning of year		98,205			73,254			64,298			453			329			296
Purchase of reserves in place		82			—			12,265			—			—			8
Extensions, discoveries and other additions		23,290			28,086			21,660			14			2			18
Transfers/sales of reserves in place		(3,801	)		(6,243	)		(3,082	)		—			—			—
Revision to previous estimates		(12,660	)		5,730			(20,303	)		91			163			47
Production		(2,951	)		(2,622	)		(1,584	)		(58	)		(41	)		(40	)
End of year		102,165			98,205			73,254			500			453			329
Proved developed reserves at end of year		45,012			39,350			32,606			500			439			300

     (c) Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows from our 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 our 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 our 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, 2007, 2006 and 2005

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are calculated using weighted average prices in effect as of those dates. Those prices were $7.39, $6.15 and $12.39, respectively, per Mcf of natural gas and $87.98, $56.88 and $54.65, 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 our oil and gas properties.

	Year Ended December 31,
(In thousands)	2007			2006			2005
Future cash inflows	$	798,769		$	629,909		$	925,705
Future development costs		(165,984	)		(136,850	)		(86,250	)
Future production costs		(197,730	)		(170,401	)		(122,916	)
Future income tax expenses		(117,700	)		(61,512	)		(211,251	)
Undiscounted future net cash flows		317,356			261,146			505,288
10% annual discount for estimated timing of cash flows		(214,574	)		(179,813	)		(297,640	)
Standardized measure of discounted future net cash flows	$	102,782		$	81,333		$	207,648

     (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 our 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.

	Year Ended December 31,
(In thousands)	2007			2006			2005
Balance, beginning of year	$	81,333		$	207,648		$	92,367
Increase (decrease) due to current year operations:
Sales and transfers of oil and gas, net of related costs		(20,500	)		(17,545	)		(12,160	)
Extensions, discoveries and improved recovery, less related costs		64,083			9,828			88,709
Purchase of reserves in place		98			—			49,153
Increase (decrease) due to changes in standardized variables:
Net changes in prices and production costs		38,984			(161,610	)		74,548
Revisions of previous quantity estimates		(17,138	)		(13,227	)		(58,713	)
Accretion of discount		8,133			20,765			9,237
Net change in future income taxes		(55,005	)		31,347			(45,411	)
Production rates (timing) and other		2,794			4,127			9,918
Net increase (decrease)		21,449			(126,315	)		115,281
Balance, end of year	$	102,782		$	81,333		$	207,648

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Supplementary Selected Quarterly Financial Data – Unaudited

     The following table provides unaudited supplementary financial information on our results of operations for each quarter in the two-year period ended December 31, 2007.

(In thousands, except per share amounts)

	Year Ended December 31,
	2007											2006
	4th		3rd			2nd			1st			4th		3rd		2nd		1st
Revenues	$	20,964	$	15,216		$	16,078		$	17,945		$	19,310	$	14,851	$	18,340	$	27,319
Income (loss) before income taxes		923		68			(647	)		79			2,160		616		1,804		1,566
Net income (loss)		257		(59	)		(761	)		(254	)		508		136		723		625
Diluted EPS		0.01		0.00			(0.03	)		(0.01	)		0.02		0.01		0.03		0.03
Common stock price range:
High	$	7.59	$	8.33		$	8.89		$	7.25		$	8.25	$	9.95	$	9.40	$	12.35
Low		5.50		6.50			6.70			6.02			6.38		6.54		6.86		7.16