FORM 10-K

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, 2008


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 (Address of principal executive offices)		40509-1844 (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. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ

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. Yes þ No o

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 filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2). Yes o No þ

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 $237,348,732.

As of March 10, 2009, there were 26,968,646 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain portions of the proxy statement for the 2009 annual meeting of shareholders are incorporated by reference
into Part III of this report.

Table of Contents


		Page
Part I:
1 and 2	Business and Properties		1
1A	Risk Factors		14
1B	Unresolved Staff Comments		18
3	Legal Proceedings		18
4	Submission of Matters to Security Holders		18
Part II:
5	Market for Common Equity and Related Matters		18
6	Selected Financial Data		20
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20
7A	Quantitative Disclosure About Market Risk		28
8	Index to Financial Statements and Supplementary Data		28
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		28
9A	Controls and Procedures		29
9B	Other Information		29
Part III:
10	Directors, Executive Officers and Corporate Governance		29
11	Executive Compensation		30
12	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters		30
13	Certain Relationships and Related Transactions, and Director Independence		30
14	Principal Accountant Fees and Services		30
Part IV:
15	Exhibits, Financial Statement Schedules		30

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. Our principal and administrative offices are located in Lexington, Kentucky. Our common stock is traded on the Nasdaq Global Select Market under the symbol NGAS. Unless otherwise indicated, references in this report to the Company or to we, our or us include NGAS Resources, Inc., our direct and indirect wholly owned subsidiaries and our interests in sponsored drilling partnerships. As used in this report, NGL means natural gas liquids, CBM means coalbed methane, Dth means decatherm, Mcf means thousand cubic feet, Mcfe means thousand cubic feet of natural gas equivalents, Mmcf means million cubic feet, Bcf means billion cubic feet and EUR means estimated ultimately recoverable volumes of natural gas or oil.

Part I

Items 1 and 2 Business and Properties

General

We are an independent exploration and production company focused on unconventional natural gas plays in the eastern United States, principally in the southern portion of the Appalachian Basin. We have specialized for over 20 years 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 operated Appalachian properties, providing deliverability directly from the wellhead to the interstate pipeline network serving major east coast natural gas markets. We believe our extensive experience in this region, coupled with our infrastructure position 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.

Business Strategy

Our business is structured for development of natural gas production and reserves, which we are accelerating by our transition to horizontal drilling throughout our operating areas. We began this transition early in 2008 and had 20 horizontal wells on line at year-end. Our success with this initiative contributed to year-over-year growth of 13% in our production volumes to 3.7 Bcfe and 37% in production revenues to $38.5 million in 2008. We also increased our estimated proved developed reserves at year-end by 20% to 57.4 Bcfe, reflecting our drilling success, although our proved undeveloped (PUD) reserves decreased substantially to 20.5 Bcfe. The decline in undeveloped reserves reflects the loss of prior-year vertical PUD locations that were no longer economic based on 2008 year-end commodity prices and drilling costs. A majority of our successful horizontal wells have been drilled on unproved locations, and we expect many of our former vertical PUD locations to be drilled horizontally. Over 70% of our 273,000-acre position in southern Appalachia is undeveloped, along with most of our recently assembled acreage in the Illinois Basin. This provides us with an extensive inventory of low-risk, repeatable horizontal drilling locations for future growth at considerably lower finding costs than vertical wells. Our strategy for capitalizing on these opportunities under currently unsettled market conditions has several components.

•

Organic Growth through Drilling with Reduced Capital Spending. Development drilling is the mainstay of our business model. During 2008, we drilled 75 gross (64.94 net) wells on our operated properties in the Appalachian and Illinois Basins, along with 118 gross (18.45 net) non-operated wells. We have an average working interest of 87% in wells drilled on operated properties during 2008, compared to 56% in the prior year. This reflects the evolution of our business model for accelerating organic growth by retaining more of our available working interest in wells drilled on our operated properties, which we implemented late in 2007. While we are committed to this long-term strategy, we have addressed the challenging conditions in our industry by reducing our 2009 capital spending budget to $15 million, allocated 80% to drilling and the balance to infrastructure and lease acquisition projects. This is in line with our anticipated cash flow from operations and may be adjusted during the year in response to market developments. To meet our 2009 drilling commitments and objectives, we are returning to our established partnership structure and sales network, which raised over $34 million for a non-operated program last year. We expect to maintain a 20% interest in this year’s program, which will increase to 35% after program payout.

•

Horizontal Drilling Initiatives. Recent advances in horizontal drilling and completion technology have enhanced the value proposition for our operated properties by substantially increasing our recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or challenging terrain. We focused these initiatives during 2008 in our Leatherwood field, where we completed 20 horizontal wells last year. Each well has a single lateral leg up to 3,500 feet through the Devonian shale formation, which is present throughout our Appalachian operating areas. Initial 30-day flow rates for our Leatherwood horizontals averaged 309 Mcf per day (Mcf/d). We achieved comparable results for our first two New Albany shale horizontals drilled late in 2008 on our Illinois Basin acreage and our initial Devonian shale horizontals completed during the first quarter of 2009 in each of our Straight Creek, Fonde and Martin’s Fork fields. We plan to continue this transition throughout our operated properties, with up to 53 horizontals planned for our 2009 drilling program.

•

Competitive Advantages from Control 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 have restricted third-party access to these facilities, they have provided us with competitive advantages in acquiring undeveloped acreage near our producing fields upon

completion of coal mining activities. We continually upgrade these field-wide gathering facilities to keep pace with our expanding production base. During 2008, we installed 65 miles of gathering lines and completed the infrastructure build-out for our New Albany shale project in western Kentucky, which we brought in line during September 2008. Earlier in the year, we also completed facilities to provide deliverability from our Fonde field, where production had been limited by pipeline capacity constraints. This enabled us to connect a backlog of wells drilled in Fonde over the last several years and open the balance of our acreage in this field for development.

•

Reduced Production Costs from Ownership of 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 this midstream system in 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 processing plant for liquids extraction completed early in 2008. We currently deliver over 90% of the production from our operated Appalachian properties to the interstate pipeline network through the NGAS Gathering system. At the end of 2008, the system had daily gross throughput of over 20,000 decatherm (Dth), including third-party deliveries. In addition to generating gas transmission and processing revenues from third-party throughput, ownership of these midstream assets generates cost savings for our own Appalachian production. It has also given us control over gas flow from our connected fields and enhanced our competitive position in the region.

•

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 developing our New Albany shale play within the southcentral portion of the Illinois Basin in western Kentucky. We began producing this project to sales in September 2008, with a total of 30 wells on line at year end. Based on encouraging results from our New Albany shale horizontals, we have expanded our lease position and plan to drill up to five horizontal wells on this acreage during 2009.

Drilling Operations

General. As of December 31, 2008, we had interests in a total of 1,375 wells, concentrated on Appalachian properties that we operate and control through our gas gathering infrastructure. We believe our long and successful operating history and proven ability to drill a large number of wells year after year have positioned us as a leading producer in this region. Historically, we conducted most of our drilling operations through sponsored drilling partnerships with outside investors, enabling us to assemble our acreage positions on the strength of our drilling commitments, while also funding infrastructure development on acquired acreage for our own account. Beginning in the second half of 2007, with our core Appalachian infrastructure in place, we changed our business model to limit our use of drilling partnerships to participation in non-operated plays, retaining all of our available working interest in wells drilled on operated properties through the end of 2008. To address part of the capital requirements for meeting this year’s drilling commitments and objectives, we are sponsoring a drilling partnership for up to $53.1 million to participate in our horizontal wells.

Geological Factors. 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. Most of our vertical wells in this region were drilled to relatively shallow total depths averaging 4,500 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout our Appalachian acreage 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. Estimated ultimately recoverable volumes (EURs) of natural gas reported for vertical gas wells in this part of Appalachia range between 100 to 450 Mmcf, with modest initial volumes offset by low annual decline rates, resulting in a reserve life index of over 25 years. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

Horizontal Drilling. Air-driven horizontal drilling advances and staged completion technology optimized for our operating areas have dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. In general, our horizontal wells use directional air drilling to create a lateral leg up to 3,500 feet through the target formation. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation than conventional vertical wells. While up to four times more expensive than vertical wells, horizontal drilling is improving overall performance 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. Typically, one horizontal well replaces between three to four vertical

locations, reducing the total footprint of the drill site. Additional economies can be achieved by drilling multiple horizontal wells on a single drilling location. In addition to these operational advantages, the initial recovery rates for these horizontals are averaging six to ten times the rates for our vertical Devonian shale wells in the same fields. Although not fully reflected in our 2008 year-end reserve estimates, we anticipate substantial upside in both production and EURs from our ongoing transition to horizontal drilling.

Air Drilling Technology. Our horizontal wells are drilled in separate sections. The initial section is identical to our standard vertical well, with 7-inch casing set approximately 600 feet above the target formation and cemented in place. After drilling about 30 feet below the casing, we begin drilling a curve that generally takes approximately 500 feet of additional vertical depth to achieve a position 90 degrees from the vertical well bore. At that point, the well bore is near the base of the target zone, 500 feet away from the original location, at the proper angle to drill the horizontal leg. The lateral leg is then drilled approximately 3,000 feet through the target formation at a slight angle to allow the well bore to cross from the bottom to the top of the formation, guided by real-time data on the drill bit location. Upon completion of drilling, 4.5-inch casing and packers are run to the end of the horizontal leg, and the packers are set at intervals, allowing the well to be completed in up to eight separate stages within the horizontal leg.

Staged Completion Technology. A staged treatment process is performed on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally one-million standard cubic feet. After the well is blown back for approximately seven days, it is connected to our existing field-wide gathering facilities to commence gas sales. We have not completed any of our horizontal wells in up-hole zones to avoid the risk of fluid production from those zones.

Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during the last three years. Drilling results shown in the table for 2008 include 11 gross (6.00 net) operated wells and 28 gross (5.56 net) non-operated wells drilled during the fourth quarter of the year. The 2008 results also include 55 gross (24.18 net) wells that were drilled by year-end but were awaiting installation of gathering lines or extensions prior to completion, primarily on non-operated properties. 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 sponsored drilling programs.


	Development Wells						Exploratory Wells
Year Ended	Productive				Dry		Productive				Dry
December 31,	Gross		Net		Gross		Gross		Net		Gross
2008
Vertical		137		58.8522		—		9		8.8125		—
Horizontal⁽¹⁾		47		15.7254		—		—		—		—

Subtotal		184		74.5776		—		9		8.8125		—
2007		211		76.1508		—		6		6.0000		—
2006		193		56.3007		—		4		3.1250		29

Total		588		207.0291		—		19		17.9375		29


(1)		Includes 25 gross (2.6003 net) non-operated wells.

The wells reflected in the table as dry exploratory wells were drilled as part of an initial 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 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 in our Haley’s Mill acreage. Based on encouraging results, we have expanded our position to over 46,000 acres in this play and have drilled a total of 12 exploratory and 30 development wells through the end of 2008. The remaining 2008 exploratory wells were drilled in our Licking River project, where we have development rights and a 50% interest in currently constrained gathering infrastructure on acreage spanning six counties in eastern Kentucky. We plan to suspend this project until market conditions improve.

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. During 2008, we had third-party participation in

Leatherwood for average working interests of 14.3% in several vertical wells drilled early in the year and 44.4% in our horizontal wells. We anticipate third-party participation between 45% to 50% during 2009 for our ongoing horizontal drilling project in Leatherwood.

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 new wells and infrastructure, while generally retaining control over all geological, drilling, engineering and operating decisions. The geological characteristics of our Appalachian properties enabled us to drill most of our vertical wells in seven to ten days. Our horizontal wells are generally drilled in 14 to 15 days. Because of the large amount of nitrogen used in completing these horizontals, the treatment stage entails scheduling complexities. As a result, we have a drilling and completion cycle of at least 28 days for most of our horizontal wells. With our core gas gathering infrastructure in place for all our operated properties, we are usually able to bring our horizontal wells on line soon after completion.

Producing Activities

Regional Advantages. Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian Basin. 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, 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 sales premiums averaging 17% over normal pipeline quality gas.

Liquids Extraction. In response to a tariff issued by the Federal Energy Regulatory Commission (FERC) limiting the upward range of energy content to 1.1 Dth per Mcf, we constructed a processing plant during 2007 with a joint venture partner in Rogersville, Tennessee to extract natural gas liquids (NGL) from our Appalachian production delivered through the NGAS Gathering system. The plant was brought on line in January 2008, ensuring our compliance with the FERC tariff. Gas processing fees for liquids extraction are shared with our joint venture partner and are volume dependent. During 2008, our share of processing fees and NGL sales offset part of the reduction in energy-related yields from our Appalachian gas production. We expect to improve the realizations for our NGL sales with rail shipping arrangements being implemented this year, which should substantially reduce our transportation costs for extracted liquids.

Production Profile. Most of our Appalachian wells share a relatively predictable production profile, producing high quality natural gas at low pressures with little or no water production. Vertical 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, 2008, the reserve life index of our estimated proved reserves, representing the ratio of reserves to annual production, was 20.2 years overall and approximately 13.8 years for our proved developed producing reserves, based on annualized fourth quarter production.

Production Volumes. Our production volumes for 2008 totaled 3.7 Bcfe, an increase of 13% over 2007 levels. Production in the fourth quarter of 2008 was 1.0 Bcfe, reflecting volumetric growth of 4.6% on a period-over-period basis. The following table shows our total net oil and gas production volumes during the last three years.


	Year Ended December 31,
Production:	2008		2007		2006

Natural gas (Mcf)		3,087,596		2,950,690		2,622,474
Oil (Bbl)		57,291		57,738		40,938
Natural gas liquids (gallons)		3,895,649		154,797		175,009


Total natural gas equivalents (Mcfe)		3,745,124		3,310,665		2,883,415

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 78% of our proved reserves on an energy equivalent basis at the end of 2008. 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, compression and processing costs in each of the reported periods.


	Year Ended December 31,
Sales Prices and Production Costs:	2008		2007		2006

Average sales prices:
Natural gas (per Mcf)	$	8.89	$	8.19	$	8.23
Oil (per Bbl)		95.07		64.97		59.60
Natural gas liquids (per gallon)		1.41		1.41		1.14

Lifting costs (per Mcfe)		1.42		1.46		1.05
Transmission, compression and processing costs (per Mcfe)		1.85		1.01		0.84

Future Gas Sales Contracts. We use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time to address commodity price volatility. Our physical delivery contracts are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of these contracts is included in our oil and gas revenues at the time of settlement. As of the date of this report, we have contracts in place for the following portions of our anticipated 2009 natural gas production.


Fixed-Price Contracts for 2009 Natural Gas Production
	Q1			Q2			Q3			Q4

Average price per Dth	$	8.73		$	8.79		$	8.78		$	8.68
Average price per Mcf		9.68			9.70			9.69			9.58
Percent of DPI gas contracted		57	%		46	%		30	%		24	%

Proved Oil and Gas Reserves

General. The estimates of our proved oil and gas reserves as of December 31, 2008, 2007 and 2006 were prepared by 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.

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 reserve volumes as of December 31, 2008, 2007 and 2006. Proved developed reserves are the estimated amounts of oil and gas that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are estimated volumes 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 evaluated with reasonable certainty, or from existing wells where a relatively major expenditure is required for recompletion.

Under current SEC regulations, proved undeveloped reserves from shale and other unconventional resource plays are generally limited to available spacing units contiguous to producing units, regardless of the continuity of the formation. As a result, we only booked 14 horizontal PUD locations at year-end 2008. The SEC recently issued amendments to its oil and gas reporting rules under the Securities Exchange Act of 1934 (Exchange Act) and Industry Guides for fiscal years ending on or after December 31, 2009. The amendments are intended to provide investors with a more meaningful and comprehensive understanding of these resources by aligning the oil and gas disclosure requirements with current industry practices and technology. The amendments will significantly impact reserve reporting for all participants in our industry but will not be effective until the end of 2009. Accordingly, the revised rules are not reflected in our reserve disclosures for the years covered in this report.

Our proved undeveloped reserves as of December 31, 2008 represented 26% of our total estimated proved reserves on an energy equivalent basis, compared to 54% of total reserves at the end of 2007. This reflects the loss of prior-year undeveloped vertical locations that were no longer economic based on 2008 year-end commodity prices and drilling costs. In view of the volatility in domestic natural gas markets and the challenges faced by producers in executing planned development, estimates of our PUD reserves may be materially higher or lower than actual recoveries from our proved undeveloped properties.


	As of December 31,
Estimated Proved Reserves:	2008		2007		2006
Natural gas (Mcf)
Proved developed		44,816,815		45,012,226		39,349,733
Proved undeveloped		16,313,814		57,152,907		58,855,060

Total natural gas (Mcf)		61,130,629		102,165,133		98,204,793

Crude oil and natural gas liquids (Bbl)
Proved developed		2,101,445		499,548		438,754
Proved undeveloped		697,040		—		13,815

Total crude oil (Bbl)		2,798,485		499,548		452,569


Total gas equivalents (Mcfe)		77,921,539		105,162,421		100,920,207

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, 2008, 2007 and 2006 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. Prices for production covered by our physical delivery contracts were applied for the term of the contracts and then reduced to year-end spot market prices for subsequent production. The prices as of December 31, 2008 had a weighted average of $5.51 per Mcf of natural gas and $40.00 per barrel of crude oil, compared to $7.39 per Mcf and $87.98 per Bbl at December 31, 2007 and $6.15 per Mcf and $56.88 per Bbl at December 31, 2006. The estimates are highly dependent on the year-end prices used in their computation and are subject to considerable uncertainty.

(In thousands)

Estimated Future Net Cash Flows


	Year Ended December 31,
From Proved Reserves:	2008			2007			2006

Undiscounted future net cash flows	$	161,455		$	317,356		$	261,146
10% annual discount for estimated timing of cash flows		(93,892	)		(214,574	)		(179,813	)

Standardized measure of discounted future net cash flows	$	67,563		$	102,782		$	81,333

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 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, 2008. 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.


	Developed⁽¹⁾				Undeveloped⁽²⁾
Property Location:	Gross Acres		Net Acres		Gross Acres		Net Acres

Kentucky		82,926		33,271		200,256		170,217
Tennessee		1,458		397		38,729		32,920
Virginia		2,749		2,362		11,833		10,058
Arkansas		8,913		2,178		2,960		2,235
Oklahoma		2,127		426		—		—


Total		98,173		38,634		253,778		215,430


(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, 2008. The table does not include wells that were in progress or were drilled by year end but were awaiting installation of gathering lines prior to completion.


	Gas Wells				Oil Wells				Total
Well Location:	Gross		Net		Gross		Net		Gross		Net

Kentucky		942		464.5447		16		12.1865		958		476.7312
Virginia		35		30.6600		1		1.0000		36		31.6600
West Virginia		195		27.0982		—		—		195		27.0982
Arkansas		55		15.0775		—		—		55		15.0775
Oklahoma		13		3.7407		—		—		13		3.7407
Tennessee		18		5.8837		—		—		18		5.8837
Louisiana		—		—		3		.3425		3		.3425


Total		1,258		547.0048		20		13.5290		1,278		560.5338

Reserves from Significant Fields. The following table shows our estimated proved reserves, both developed and undeveloped, on a field-wide basis as of December 31, 2008.


	Proved Reserves at December 31, 2008
	Developed									Undeveloped
Field:	Gas		NGL/Oil		Total		%			Gas		NGL		Total
	(Mcf)		(Bbls)		(Mcfe)					(Mcf)		(Bbls)		(Mcfe)

Leatherwood		13,242,508		857,914		18,389,992		79	%		3,389,088		257,404		4,933,512
Arkoma		10,000,894		—		10,000,894		76			3,159,596		—		3,159,596
Amvest		2,831,069		485,939		5,746,703		69			1,801,382		136,815		2,622,272
Martin’s Fork		3,532,436		260,533		5,095,634		53			3,130,591		237,768		4,557,199
Straight Creek		3,111,455		267,153		4,714,373		100			—		—		—
Kay Jay		2,700,043		962		2,705,815		48			2,878,606		—		2,878,606
Fonde		1,393,601		82,965		1,891,391		71			520,664		39,543		757,922
Western KY		1,869,489		—		1,869,489		86			307,422		—		307,422
HRE		4,194,086		5,042		4,224,338		99			35,487		—		35,487
Other fields		1,941,234		140,937		2,786,856		69			1,090,978		25,510		1,244,038


Total		44,816,815		2,101,445		57,425,485		74	%		16,313,814		697,040		20,496,054

Description of Significant Fields. Our producing properties and undeveloped acreage positions are concentrated in the southern portion of the Appalachian Basin, as well as our recently developed New Albany shale play within the Illinois Basin in western Kentucky. We also have interests in a non-operated coalbed methane project in the Arkoma Basin and non-operated projects in West Virginia and Virginia. 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, 2008.

Leatherwood. The Leatherwood field covers approximately 60,000 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 drilled 25 exploratory wells to test five natural gas pay zones in 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 254 development wells in Leatherwood, including 20 horizontal wells during 2008. Our Leatherwood horizontals have targeted the Lower Huron section of the Devonian shale, which has an average thickness of 80 feet at depths between 3,500 and 4,500 feet. As of year end, we had 269 wells on line in Leatherwood, with total daily gross and net production of 8,247 Mcfe and 3,218 Mcfe, 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 at year-end were 79% proved developed.

Our transition to horizontal drilling in Leatherwood during 2008 contributed to additions of approximately 8.3 Bcfe to our proved developed reserves from this field at year-end, although our undeveloped Leatherwood reserves were reduced from the prior year’s estimate by 16.2 Bcfe. This reflects the impact of lower year-end gas prices and higher drilling costs on the economics of our prior year’s vertical PUD locations, which were eliminated from the 2008 year-end estimates. While we expect many of the former vertical PUDs to be drilled horizontally with substantially better economics than vertical wells, we were only able to book a total of 14 horizontal PUD locations in Leatherwood under the current reserve reporting rules.

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. Over the last three years, we have added several pipeline and compression upgrades to keep pace with our expanding production base in Leatherwood, including substantially higher gas flows from our horizontal wells.

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. These rights were exercised during 2008 for average total working interests of 14.3% in several vertical wells and 44.4% in our horizontal wells in this field. We anticipate higher participation levels by the mineral interest owners in our 25 horizontal wells planned for Leatherwood during 2009.

Arkoma. The Arkoma field is a coalbed methane (CBM) 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 Arkoma, including its 25% interest in the gathering system for the field. We also entered into a farmout with CDX for 90% of its majority (75%) interest in a minimum of 32 drilling locations on its acreage. Under the farmout, we assumed all of future developments costs for the CDX position and granted them 25% carried working interest, increasing to 50% after payout of the covered wells. Combined with our interests from the Dart Energy acquisition, this gave us an overall position of approximately 73% in future development of the field.

We participated in 15 horizontal wells under our Arkoma farmout, which we elected to terminate during 2007. During the balance of the year, we participated in four CBM wells through our interests from the Dart Energy acquisition. No wells were drilled in 2008, and payments from our share of Arkoma production were suspended for several months late in the year following a bankruptcy filing by the operator. We expect to recover these receivables this year. We had interests in a total of 67 wells producing to sales in this field at the end of 2008, with daily gross and net CBM production of 12,912 Mcf and 2,886 Mcf, respectively. Estimated proved reserves from our interests in the Arkoma field were 76% proved developed at year-end.

Amvest and Martin’s Fork. We acquired our interests in the Amvest and Martin’s Fork fields, including existing wells and infrastructure, during the fourth quarter of 2004. Also known as the Stone Mountain fields, together they span approximately 90,000 acres in Harlan County, Kentucky and Lee County, Virginia. Vertical wells produce from the Big Lime, Devonian shale and Clinton formations in Martin’s Fork at depths between 3,200 and 6,500 feet and from the Big Lime, Weir sand and Devonian shale formations in Amvest 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 are subject to annual drilling commitments for two wells in Martin’s Fork and four wells in Amvest. Since acquiring these interests, we have drilled a total of 57 wells on this acreage. At year end, we had a total of 75 wells in Martin’s Fork and 73 wells in Amvest producing to sales, with daily gross and net production aggregating 3,896 Mcfe and 2,745 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 these fields at year-end were 69% proved developed in Amvest and 53% proved developed in Martin’s Fork.

We completed our initial horizontal well in Martin’s Fork during the first quarter of 2009, with encouraging gas flows. Our horizontals in Martin’s Fork will target the Lower Huron section of the Devonian shale, which ranges in thickness up to 200 feet. In Amvest, our horizontals will target the Upper Huron and Cleveland sections of the Devonian shale, with a combined thickness up to 130 feet.

Straight Creek. The Straight Creek field is located in Bell and Harlan Counties, Kentucky. We have interests in approximately 28,000 acres in this field. In addition to several wells we acquired in the field during 2004, we have drilled 180 vertical 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 for connection to our midstream system. At the end of 2008, we had a total of 191 wells producing to sales in Straight Creek, with daily gross and net production of 2,837 Mcf and 942 Mcf, respectively. Estimated proved reserves from our interests in Straight Creek at year-end were 100% proved developed. We are expanding our horizontal program to Straight Creek during 2009, targeting the Upper Huron and Cleveland sections of the Devonian shale, which have a combined thickness of approximately 80 feet in this field at an average depth of 4,000 feet. Initial results from the first of these wells have met our expectations.

Kay Jay. The Kay Jay field spans portions of Knox and Bell Counties in eastern Kentucky. Our initial interests in the field were acquired in 1996 under a farmout for approximately 11,500 acres, with an ongoing annual drilling commitment for a total of four wells. We subsequently assembled an additional 15,500 acres under a leasing program for this field. We have drilled a total of 163 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, which are currently connected to third-party pipeline systems. We had a total of 153 wells in Kay Jay producing to sales at year end, with daily gross and net production of 2,312 Mcfe and 745 Mcfe, respectively. Estimated proved reserves from our position in Kay Jay at year-end were 48% proved developed.

Fonde. The Fonde field spans portions of Bell County, Kentucky and Claiborne County, Tennessee. We acquired our initial position for 3,900 acres in this field during 1998 and subsequently assembled an additional 45,000 acres 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 produces crude oil from the Big Lime. We have drilled a total of 65 wells in Fonde. We operate all of our Fonde wells and own all of the field-wide gathering facilities for their production. During the first quarter of 2008, we completed construction of a 14-mile, six-inch steel line to provide deliverability for our Fonde production into the NGAS Gathering system. This enabled us to connect a backlog of wells drilled in Fonde over the last several years and open the balance of our acreage for development. At year end, we had 35 wells in Fonde producing to sales, with daily gross and net production of 1,144 Mcfe and 467 Mcfe, respectively. Estimated proved reserves from our interests in Fonde were 71% proved developed at year-end. We completed our initial horizontal well in Fonde during the first quarter of 2009. The well is producing at moderate levels despite mechanical problems encountered during the treatment stage.

Illinois Basin — Haley’s Mill. Our New Albany shale play is situated in the southcentral portion of the Illinois Basin, spanning approximately 46,000 acres within Christian and Hopkins Counties in western Kentucky. The New Albany shale, which blankets this acreage at depths ranging from 2,600 to 2,800 feet, has similar geologic characteristics to the Devonian shale in the Appalachian Basin. We assembled our initial lease position during 2006 in an area known as Haley’s Mill, where we drilled 15 wells through the end of 2007. During 2008, we expanded our acreage position and drilled an additional 27 wells, including our first two New Albany shale horizontals. Although we completed the construction of a gathering system for the project during 2007, along with a nitrogen-reduction unit, our deliverability was substantially reduced by unanticipated constraints in third-party pipeline capacity. In September 2008, we completed an extension to an alternative pipeline network and began producing the project to sales. We had a total of 30 New Albany shale wells in line at year end, with daily gross and net gas production of 1,846 Mcf and 1,528 Mcf, respectively. Estimated proved reserves from our Illinois Basin play are 86% proved developed.

HRE. We have participated in development of the HRE fields with a joint venture partner, Hard Rock Exploration, Inc. (Hard Rock), under its leases and farmouts covering approximately 114,000 acres in Boone, Cabell, Jackson, Randolph and Roane Counties, West Virginia and Buchanan County, Virginia. Since the beginning of 2006, we have participated in a total of 237 wells drilled by Hard Rock on its acreage, including 34 horizontal wells. Most of the HRE wells target primarily the Lower Huron section 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. We have participated in developing the HRE fields primarily through our interests in sponsored drilling programs, including a 2008 program for 89 wells. As of year end, we had interests in a total of 196 wells producing to sales in these fields, with daily gross and net production of 5,758 Mcfe and 674 Mcfe, respectively. Proved reserves from our interests in the HRE fields are 99% proved developed.

Drilling Partnerships

Investment Capital. During the last three years, we raised over $97 million from outside investors for participation in many of our drilling initiatives through private placements of interests in sponsored drilling partnerships. 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 partnerships during the last three years are summarized in the following table.


	Drilling Program Capital
	Total Wells		Partnership		Our		Total
Drilling Partnerships:	Contracted		Contributions		Contributions		Capital

2008		89	$	34,460,340	$	10,919,628	$	45,379,968
2007		140		29,829,219		13,939,508		43,768,727
2006		175		33,271,236		24,179,168		57,450,404


Total		404	$	97,560,795	$	49,038,304	$	146,599,099

Structure. Our drilling partnerships are structured to optimize tax advantages for private investors and share development costs, risks and returns proportionately, except for functional allocations of intangible drilling costs (IDC) to investors and reversionary interests that we earn after specified distribution thresholds are reached. Under our drilling program structure, proceeds from the private placement of interests in each investment partnership, together with our capital contribution, are contributed to a separate joint venture or “program” that we form with that partnership to conduct operations. The portion of the profit on drilling contracts from our ownership interest in the programs is eliminated on consolidation in our financial statements. In 2006, we changed the cost structure for these contracts from turnkey to cost-plus pricing, designed to share our exposure to cost volatility for drilling services and equipment with outside investors and stabilize our margins for contract drilling operations.

Benefits. Our established track record and sales network for sponsored drilling partnerships has enabled us to attract outside capital from private investors for participation in selected development initiatives. This addresses part of the high capital costs of our business, enabling us to increase our position in non-operated plays and accelerate the development of our own properties without relinquishing control over drilling and operating decisions. The structure also provides economies of scale with operational benefits at several levels.

	•		Expanding our drilling budget with outside capital from partnership investors enables us to build our asset base through increased drilling commitments on operated properties and larger stakes in non-operated plays. It also leverages our buying power for drilling services and materials, resulting in lower overall development costs.

	•		Accelerating the pace of development activities through our drilling partnerships expands the production capacity we can make available to gas purchasers, contributing to higher and more stable sales prices for our production.

	•		Our drilling partnership business model increases the number of gross wells we could drill on our own, diversifying our drilling risks and opportunities.

Drilling Program Investments. In addition to managing program operations, we contribute capital to each program in proportion to our initial ownership interest, and we share program distributions in the same ratio until program payout, which ranges from 100% to 110% of the partners’ investment. After payout, we are entitled to specified increases in our distributive share, up to 15% of the total program interests. In 2008, we sponsored a program for 89 natural gas development wells, including 20 horizontal wells, on acreage controlled by a joint venture partner in West Virginia and Virginia. We have a 25% stake in the 2008 program, increasing to 40% after program payout. We retained all of our available working interest in wells drilled on our operated properties last year to accelerate organic growth. We have reduced our capital expenditure budget for 2009 and are sponsoring a drilling partnership for up to $53.1 million to participate in our horizontal drilling initiatives throughout our operating areas. We expect to maintain a 20% interest in our 2009 program, which will increase to 35% after program payout.

Liquidity Features. Many of the drilling partnerships we sponsored over the last eight years have a liquidity feature enabling participants to tender requests for us to purchase their interests after specified periods under various conditions. For recent programs, this feature gives us the option to acquire tendered program interests for cash based on a multiple of partnership distributions for the preceding year. For older programs, we have the right to purchase any tendered interests in exchange for our common shares based on the most recent year-end reserve valuations for the particular partnership by independent petroleum engineers. The valuations under either of these liquidity features may not necessarily correspond to the fair value of the tendered interests. Both of these liquidity features are subject to various conditions and limitations. Less than 1% of the outside investors in our sponsored drilling partnerships have used these liquidity features, and we do not believe they affect the way we account for our interests in these programs.

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, geographic concentration and operating rights. Based on those criteria, we launched a project in mid-2008 to purchase the interests of outside investors in several of our mature drilling partnerships on an all-cash basis that gave effect to our reversionary interests in the programs. We purchased 162 Mmcfe of reserves from outside investors under this project for a total purchase price of $280,279. Based on the limited acceptance of our purchase offers, we do not plan to continue this project.

Gas Gathering Operations

Midstream System. We own and operate a strategic 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 had 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, 2008, our midstream system had daily gross throughput of over 20,000 Dth, including third-party deliveries.

Field-Wide Systems. We construct and operate local gas gathering facilities for our core Appalachian and Illinois Basin properties. These field-wide systems spanned a total of 542 miles as of December 31, 2008, including 65 miles of gathering and production lines added last year. Our infrastructure build-outs during the last two years also include upgrades of the main suction line to the compressors in our Leatherwood field, construction of a gathering system for our New Albany shale play in western Kentucky and installation of a 14-mile, six-inch steel line to provide deliverability from our Fonde field for compression into the NGAS Gathering system. We estimate that that up to 200,000 undeveloped acres surrounding our Appalachian properties serviced by this infrastructure will open up for drilling when active coal mining operations wind down. We believe our infrastructure base and established track record in this region positions us to acquire these development rights when they become available.

Gas Processing and Treatment Facilities. In 2008, we augmented our gathering infrastructure with the construction of a natural gas processing plant for Appalachian gas production delivered through our NGAS Gathering system and a nitrogen rejection facility for production from our New Albany shale play in the Illinois Basin. The processing plant is located in Rogersville, Tennessee, with a connection to a pipeline network operated by East Tennessee Natural Gas, LLC. The plant extracts natural gas liquids from production serviced by the NGAS Gathering system and flows dry pipeline quality natural gas into the interstate network. Brought on line in January 2008, the plant is currently configured for throughput at rates up to 25,000 Mcf per day, which can be increased to accommodate production growth and relief of constrained regional supplies. The nitrogen rejection facility is part of the infrastructure build-out for our New Albany shale project in western Kentucky, which we brought on line in September 2008. Both the Rogersville processing plant and the western Kentucky treatment facility were developed with a joint venture partner, Seminole Gas Company, and are operated and co-owned by Seminole.

Gas Gathering and Compression Fees. Approximately 90% of our Appalachian production is delivered from our field-wide facilities through the NGAS Gathering system. We receive fees up to $0.65 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. For transporting third-party production through the open-access section of our gas gathering network, we receive fees at current rates ranging from $0.62 to $0.64 per Mcf. Ownership of these facilities generates corresponding cost savings for our own Appalachian production.

Customers

Natural Gas Sales. We sell our natural gas production primarily through unaffiliated gas marketing intermediaries. In addition to providing 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 2008, approximately 50% of our natural gas production was sold under fixed-price contracts at rates ranging from $8.03 to $9.15 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, 2008, 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 prior to the current economic downturn 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, including our extensive infrastructure base. We maintain a disciplined approach to selecting property acquisition and development opportunities and a commitment to infrastructure control, with a view to consolidating our position as a niche developer and 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.

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 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.

Employees

As of December 31, 2008, we had 122 full-time employees. Our staff includes professionals experienced in geology, petroleum engineering, land acquisition, finance, accounting and law.

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 funds required 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 eventually monetize our interests in these properties 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 1A Risk Factors

Our business involves numerous business and operating risks, many of which have been heightened by the contraction of the financial markets and our economy as a whole. The risks and related considerations we consider material to our business are summarized below.

Natural gas and NGL prices are volatile, and continuing weakness in commodity prices could reduce our revenue, liquidity and ability to grow.

Factors Affecting Market Volatility. Our financial performance and prospects depend on the prices we receive for sales of natural gas and NGL, which accounted for 91% of our total production revenues in 2008. Commodity prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Natural gas prices declined sharply throughout the second half of 2008, ending the year at $5.71 per Mcf in the spot markets for our region, with further price erosion to a six-year low during the first quarter of 2009. While the decline from mid-year 2008 levels has been extreme, natural gas prices have historically been subject to wide fluctuations in response to relatively minor changes in the supply and demand, market uncertainty and many other factors beyond the control of producers. These factors are interrelated and include:

	•		the extent of domestic natural gas and NGL production, which has surged over the last few years from the use of horizontal drilling technologies to accelerate development of shale and other unconventional resource plays;

	•		the impact of weather and general economic conditions on consumer and industrial demand for natural gas;

	•		volatile trading patterns in the commodities trading markets;

	•		the proximity and capacity of pipelines;

	•		storage levels;

	•		comparative prices and availability of alternative fuels;

	•		worldwide supply and demand for oil, natural gas, NGL and liquefied natural gas; and

	•		federal and state regulatory, conservation and tax measures, including proposed legislation to eliminate IDC and depletion deductions for federal income tax purposes, beginning in 2011, which could impair our ability to raise capital through sponsored drilling partnerships if adopted.

Impact of Commodity Prices on Financial Performance. The volatility of energy markets makes it extremely difficult to predict future natural gas prices. Because we sell our natural gas production under market-sensitive arrangements, we are exposed us to this price volatility. We do not address this risk through financial hedging, but we do use fixed-price, fixed-volume physical delivery contracts that cover a portion of our natural gas

production for various terms, up to two years from the contract date. While prices established by our outstanding physical delivery contracts are favorable compared to current spot markets indices, the use of these arrangements in volatile markets could result in future gas sales at fixed prices below prevailing market prices at the time of delivery. Continued weakness in the energy markets or further erosion of natural gas prices would limit our ability to obtain favorable terms for future production under these type of arrangements, potentially reducing our production revenue and cash flow.

Impact of Commodity Prices on Reserve Estimates. Lower natural gas prices may not only decrease our revenues on a per unit basis but may also reduce the amount of natural gas that we can produce economically. Although we increased our estimated proved developed reserves at December 31, 2008 by 20% to 57.4 Bcfe, our proved undeveloped reserves decreased 64% from prior-year vertical PUD reserves that were no longer economic based on 2008 year-end commodity prices, coupled with higher vertical drilling costs for the year. Further deterioration in natural gas prices could require us to make additional downward adjustments to our estimated proved reserves. Under successful efforts accounting rules, this could potentially require impairment charges in future periods if the carrying value of any proved oil and gas property exceeds the expected undiscounted future net cash flows from that acreage based on drilling results, prices or other economic factors at the time of the impairment review. While any impairment charge would not affect our cash flow from operations, it would reflect our long-term ability to recover an investment based on prevailing conditions and would impact our reported earnings and leverage ratios.

We are leveraged and may be unable to repay or refinance our long-term debt on satisfactory terms.

We have $37 million outstanding principal amount of convertible notes due in December 2010 and $72 million of outstanding borrowings at year-end under our revolving credit facility, which is scheduled to mature in September 2011. The facility is secured by liens on substantially all our assets and had a borrowing base of $80 million at year-end 2008. The borrowing base limits the amount we can borrow or have outstanding at any one time, as determined semi-annually by the lenders. These redeterminations are based primarily on estimated volumes of our proved developed oil and gas reserves. However, the lenders apply their own price decks, generally at a risk-adjusted discount to prevailing commodity prices, and they may also consider other credit factors and general economic conditions in our industry. Any reduction in our borrowing base below our outstanding indebtedness and letters of credit could require us to repay the excess or provide additional collateral. Our ability to reduce, repay or refinance our debt at maturity will be subject to our future performance and prospects as well as market and general economic conditions beyond our control. There can be no assurance that we will be able to secure the necessary refinancing on satisfactory terms.

Our level of indebtedness may limit our financial and operating flexibility and performance.

The amount and maturities of our debt may adversely affect our business in various ways. Among other adverse consequences, our level of indebtedness could:

	•		limit our ability to fund planned capital expenditures, take advantage of acquisition and development opportunities or otherwise realize the value of our assets, to the extent that operating cash flow otherwise available for these activities is required to service or repay our debt;

	•		increase our vulnerability to adverse economic and industry conditions;

	•		limit our flexibility in planning for developments or reacting to changes in our industry; and

	•		place us at competitive disadvantage to producers in our operating areas with less debt and greater liquidity.

Declining economic, business and industry conditions may adversely impact our operating results, liquidity and future prospects.

The economic downturn has required us to modify our business plan and may continue to adversely affect our business and prospects in various ways. We have reduced our operating and capital budget for 2009 to meet our drilling commitments and objectives with internally generated cash flow, coupled with a return to our established drilling partnership structure and sales network for participation in these initiatives. However, these sources have historically covered only part of our total expenditures for property development, and we have generally funded property acquisitions and infrastructure development for our own account, relying on the financial markets to provide us with additional capital for these projects. Adverse conditions have restricted our access to these markets, and continuation of these conditions may increase our cost of capital or our ability to raise capital from the sale of our debt

or equity securities. Without access to the capital markets, we could be required to sell properties or find other ways to monetize assets. Otherwise, we would have to reduce our planned drilling expenditures, which could result in the loss of undeveloped acreage from unsatisfied drilling commitments. Deteriorating economic conditions could also affect the collectability of our trade receivables, including production payments from our interests in non-operated wells, and could impair the effectiveness of our physical delivery contracts if counterparties are unable or unwilling to perform their obligations.

Our proved developed reserves will decline from depletion of our existing wells.

Unless we continue to expand our reserves through the drillbit or acquire additional proved properties, 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 of over 25 years for mature wells in the region, estimates of the proved developed reserves from our vertical wells as of December 31, 2008 were based on the extensive historical production profiles for the region. This resulted in a projected decline rate for our vertical wells of approximately 18.6% during 2009, decreasing hyberbolically to 5.5% in 2023. The actual performance of these wells could differ materially from the reserve estimates, and EURs from our horizontal wells is even more uncertain in view of their limited production history. 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.

Estimates of our proved reserves are based on assumptions that could cause them to be substantially higher or lower then the volume and net present value of natural gas and oil actually recovered.

There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production, as well as the timing and amount 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 natural gas and oil that are ultimately recovered.

We may be unable to recover our proved undeveloped reserves or resources from unproved properties due to general economic conditions or capital constraints.

As of December 31, 2008, approximately 26% of our estimated proved reserves were undeveloped. The ultimate recovery of our undeveloped reserves is uncertain. Recovering these PUD reserves and developing our unproved properties will require significant capital expenditures and successful drilling operations. The estimates of our proved undeveloped reserves assume that we will be able to make the necessary capital expenditures, and we may not have the capital or financing we need for their development. Our reported reserves also assume the continuation of economic conditions at the time of the estimates, including the costs associated with reserve development, which may increase disproportionately with commodity prices over time. 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.

The timing and costs of implementing our planned drilling schedule are uncertain and may differ materially from our expectations.

Our cash flow, earnings and prospects are highly dependent on our success in efficiently developing and exploiting our current reserves and resources as well as our ability to find additional recoverable reserves economically. Executing our planned drilling initiatives is subject to a number of uncertainties, including our access to capital, seasonal conditions, regulatory approvals and the continued availability of field services and equipment. Drilling activity increased appreciably during 2007 and the first half of 2008 in response to higher commodity prices and reported success in regional shale plays, notably in the Marcellus play near our operating areas in the Appalachian Basin. The heightened demand for field services contributed to constraints on the availability of skilled labor, equipment, pipeline capacity and other resources in the region. While the steep decline in natural gas prices after July 2008 ultimately reduced drilling activity, drilling costs did not begin to moderate until the first quarter of 2009. Continued market disruptions may cause delays in drilling operations and the possibility of poor results. Because of these uncertainties, we may be unable to drill and produce our planned 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.

Our operations involve hazards and exposure to liabilities that would not be fully covered by insurance.

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 or mechanical failure of drilling equipment, casing collapse and environmental hazards such as gas leaks, ruptures and discharges of toxic gas. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties. While we maintain insurance to protect us against these operating risks, the operating hazards associated with our development and production activities may expose us to liabilities not fully covered by our insurance.

Our production volumes may be less than anticipated.

Various field operating conditions may adversely our production volumes. These conditions include potential delays in obtaining regulatory approvals and easements for connecting completed wells to our existing gathering facilities and the risk that production from connected wells could be interrupted, or shut in, from time to time for various reasons, including weather conditions, accidents, loss of pipeline access, mechanical conditions, field labor issues or intentionally as a result of market conditions. While close well monitoring and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Moreover, due to the short production history for horizontal shale wells in our operating areas and similar regional plays, the timing and extent of production declines for our horizontal wells cannot be predicted with any certainty.

We depend on key personnel for decision making and industry contacts.

We are dependent on the continued contributions of our executives and key personnel for the decision making and industry contacts necessary to manage and maintain growth within our highly competitive industry. There are a limited number of people with this level of knowledge and experience in our operating areas, and competition for qualified personnel can be intense. While we have retention agreements with our senior management or other key personnel, the loss of their services for any reason could have a material adverse effect on our business and prospects.

We have never paid dividends on our common stock and do not anticipate any change in that policy.

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.

Market prices for our common stock are volatile.

The market price of our common stock is subject to significant volatility in response to variations in our operating and financial results, perceptions about our future prospects and other factors. Sales of substantial amounts of our common stock could also affect its market price. As of December 31, 2008, there were 26,543,646 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 7,473,019 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 may occur, could adversely affect prevailing market prices of the common stock.

Failure to stay in compliance with Nasdaq listing requirements would adversely affect the market price and liquidity of our 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. Although the market price requirement for continued listing provides for various grace periods to regain compliance, the maximum grace period is currently limited to 360 days. If our common stock were to be delisted, liquidity in the common stock would be impaired. Any delisting of our common stock would also trigger an event of default requiring us to redeem our outstanding convertible notes.

Our undeveloped gold and silver properties may never be profitable or monetized.

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 3		Legal Proceedings

We are involved in several legal proceedings incidental to our business, none of which is considered to be material to our consolidated financial position, results of operations or liquidity.


Item 4		Submission of Matters to a Vote of Security Holders

No proposals were submitted for approval by our shareholders during the fourth quarter of 2008.

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 during 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

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	$	6.39	$	4.50		235,556
	Second quarter		10.31		5.58		452,262
	Third quarter		9.75		4.41		361,095
	Fourth quarter		4.80		1.30		289,235

2009	First quarter (through March 9^th)	$	2.26	$	0.77		199,862

Security Holders

As of March 9, 2009, there were 2,781 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, 2008 under our equity compensation plans, which are 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

Issuance under Equity

Options and Warrants

Options, Warrants

Compensation Plans

Plan Category

and Rights

(excluding column [a])

Plans approved by shareholders

4,613,668

3.95

271,188

Plans not approved by shareholders

—

Total

4,613,668

3.95

271,188

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 Dow Jones U.S. Exploration and Production Index and the S&P 500 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 Exchange Act and is not incorporated by reference in any registration statement under the Securities Act of 1933.

Stock Performance Graph


	2003		2004		2005		2006		2007		2008

NGAS	$	100	$	88	$	201	$	122	$	108	$	31
Dow Jones US E&P		100		142		235		247		355		213
S& P500		100		111		116		135		142		90


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 prepared our consolidated financial statements prior to 2006 in accordance with accounting principles generally accepted in Canada (Canadian GAAP). 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.

The following table presents our summary selected consolidated financial data as of and for each of the five years ended December 31, 2008. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP for 2008, 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, 2008 and 2007 and for the three years ended December 31, 2008 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:	2008		2007			2006		2005		2004

Total revenues	$	84,407	$	70,203		$	79,820	$	62,228	$	47,980
Direct expenses		43,981		39,044			49,361		40,477		33,047
Net income (loss)		2,936		(817	)		1,992		953		1,612
Net income (loss) per common share (basic)		0.11		(0.04	)		0.09		0.05		0.12
Weighted average common shares outstanding		26,409		22,240			21,511		17,351		13,994


	As of December 31,
Balance Sheet Data:	2008			2007			2006			2005			2004

Current assets	$	12,052		$	11,240		$	24,656		$	34,016		$	16,426
Current liabilities		17,571			12,381			25,484			34,880			19,693
Working capital (deficit)		(5,519	)		(1,141	)		(828	)		(864	)		(3,267	)
Total assets		247,354			204,801			178,219			146,774			89,127
Total liabilities		142,786			104,892			101,862			74,546			47,985
Shareholders’ equity		104,568			99,909			76,357			72,227			41,142


Item 7		Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent exploration and production company focused on generating and developing natural gas prospects in Appalachia and other unconventional plays 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 partnerships with outside investors, maintaining combined interests as both general partner and an investor ranging from 12.5% to 75%, along 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 retaining all of our available working interest in new wells drilled on operated properties, with a view toward limiting our use of drilling partnerships to participation in non-operated projects. While we are committed to continue expanding our reserves and production through the drillbit, we are addressing current conditions in the financial and energy markets with a planned reduction in capital spending to approximately $15 million for 2009 and a resumption of drilling partnership participation in our operated initiatives until market conditions improve. This should enable us to continue meeting our drilling commitments and objectives for core properties without access to the capital markets and with limited reliance on additional draws under our credit facility.

Results of Operations — 2008 and 2007

Revenues. The following table shows the components of our revenues for 2008 and 2007, together with their percentages of total revenue in 2008 and percentage change on a year-over-year basis.


	Year Ended December 31,
			% of					%
Revenue:	2008		Revenue			2007		Change

Contract drilling	$	35,553,956		42	%	$	34,334,829		4	%
Oil and gas production		38,522,474		46			28,148,689		37
Gas transmission, compression and processing		10,330,234		12			7,719,308		34


Total	$	84,406,664		100	%	$	70,202,826		20

Our revenue mix for 2008 reflects our ongoing strategy for transitioning to a more production based business, with oil and gas sales accounting for 46% of total revenues, compared to 40% of total revenues in 2007. Despite our planned reduction in capital expenditures for 2009, we expect this trend to continue on a long-term basis as we expand our horizontal drilling initiatives and our infrastructure and acreage position in our core operating areas.

Contract drilling revenues reflect the size and timing of our drilling program initiatives, as well our ownership interest in sponsored programs. Although we receive the proceeds from private placements in sponsored programs as customers’ drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. During 2008, we sponsored a program for participation in 89 wells on non-operated properties known as the HRE fields, spanning six counties in West Virginia and Virginia. Our contract drilling revenues in 2008 reflect ongoing operations for that program and the completion of our 2007 HRE program. Outside investors have interests of 75% before payout and 60% after payout in both of those programs.

The growth in our production revenues for 2008 reflects a 13% increase in production output to 3,745 Mmcfe, compared to 3,311 Mmcfe in 2007. Our volumetric growth was driven by added production from wells brought on line during 2008. We anticipate ongoing production gains as we continue to bring completed wells on line, including substantial contributions from our horizontal drilling initiatives. Our natural gas production is sold primarily through gas marketing intermediaries. Approximately 50% of our natural gas production in 2008 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2008 averaged $9.59 per Mcf for our Appalachian production and $8.89 per Mcf overall, compared to an average overall realization of $8.19 per Mcf in 2007.

Gas transmission, compression and processing revenues for 2008 were driven by fees totaling $5,029,815 for moving third-party gas through our NGAS Gathering system and $746,970 in related processing fees for liquids extraction through our Rogersville plant. This component of revenues also includes gathering and compression fees of $1,936,300 for moving our drilling program investors’ share of gas through our field-wide facilities, together with contributions of $565,727 from gas utility sales and $458,154 from our interest in the gathering system that services a non-operated coalbed methane project in the Arkoma Basin.

Expenses. The following table shows the components of our direct and other expenses for 2008 and 2007. 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,
	2008		Margin			2007		Margin

Direct Expenses:

Contract drilling	$	27,272,756		23	%	$	26,773,028		22	%
Oil and gas production		12,600,897		67			7,648,558		73
Gas transmission, compression and processing		4,107,763		60			3,657,977		53
Impairment of oil and gas assets		—		N/A			964,000		N/A


Total direct expenses		43,981,416		48	%		39,043,563		44	%


			% Revenue					% Revenue

Other Expenses:

Selling, general and administrative		14,005,041		17	%		12,920,591		18	%
Options, warrants and deferred compensation		911,561		1			1,069,306		2
Depreciation, depletion and amortization		12,418,234		15			10,416,696		15
Bad debt expense		749,035		1			215,000		—
Interest expense, net of interest income		5,479,233		6			6,007,105		9
Other, net		125,072		—			107,738		—


Total other expenses	$	33,688,176				$	30,736,436

Contract drilling expenses reflect the level of drilling initiatives conducted through our sponsored partnerships. These expenses increased by 2% on a year-over-year basis and represented 77% of contract drilling revenues in 2008, compared to 78% in the prior year. All of our contract drilling activities in 2008 were conducted on non-operated HRE properties in West Virginia and Virginia. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. The increase in production expenses on a year-over-year basis primarily reflects our volumetric growth and higher severance and production taxes, as well as $2,282,841 in hauling costs for natural gas liquids, which we began stripping from our Appalachian production through our Rogersville plant during the first quarter of 2008. Our margins in both reported periods reflect cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation fees for our dedicated Appalachian production, of which approximately 90% is now delivered through the system. As a percentage of oil and gas production revenues, our production expenses were 33% in 2008, compared to 27% in the prior year, primarily reflecting start-up costs for bringing our Rogersville processing plant and our Fonde and Haley’s Mill gathering systems on line, as well as added transportation fees for extracted natural gas liquids.

Gas transmission, compression and processing expenses in 2008 were 40% of associated revenues, compared to 47% in the prior year. The margins for this part of our business have benefited from third-party fees generated by the NGAS Gathering system. Our gas transmission, compression and processing expenses do not include capitalized costs of approximately $10.1 million during 2008 for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling partnerships and general overhead costs. Our SG&A expenses in 2008 increased by 8% from the prior year, primarily reflecting sales costs for a drilling partnership launched in April 2008 for participation in our non-operated initiatives in West Virginia and Virginia, along with overhead costs for supporting our expanded operations as a whole. As a percentage of revenues, SG&A expenses decreased from 18.4% in 2007 to 16.6% in 2008.

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 an accrual of $286,419 in 2008 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 reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment.

We recognized bad debt expenses aggregating $749,035 in 2008. A first quarter charge of $347,840, coupled with a prior period reserve, represents the entire amount due for oil sales to a regional refinery prior to its filing for reorganization under the bankruptcy laws last year. A second quarter charge of $59,000 reflects a writeoff of a non-performing loan to a regional operator on a three-well project in Texas. In the third quarter of 2008, we recognized a bad debt expense of $342,195 for unreimbursed trade debt we paid on behalf of a Virginia steam company in which we previously held a 50% interest. See “Critical Accounting Policies and Estimates — Allowance for Doubtful Accounts.”

Interest expense for 2008 decreased from lower variable rates under our revolving credit facility. Draws under the credit facility were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.

Deferred income tax expense recognized in both reported periods 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 realized net income of $2,936,275 in 2008, compared to a net loss of $816,597 recognized in 2007, reflecting the foregoing factors. Basic earnings per share (EPS) was $0.11 based on 26,409,275 weighted average common shares outstanding in 2008, compared to EPS of $(0.04) in 2007 based on 22,240,429 weighted average common shares outstanding in 2007.

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, compression and processing		7,719,308		11			5,478,642		41

Total	$	70,202,826		100	%	$	79,820,289		(12	)%

Contract drilling revenues reflect the size and timing of our drilling partnership initiatives, as well as our percentage interest in sponsored programs. The contraction in contract drilling revenues reflects the completion of program initiatives on operated properties and a reduction in our reliance on partnership financings for other drilling initiatives during 2007.

The growth in our production revenues for 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. 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, compression and processing revenues in 2007 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 for a non-operated coalbed methane project in the Arkoma Basin.

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, compression and processing		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 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 reduction in our use of drilling partnerships 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.

Production expenses in 2007 were consistent with our volumetric growth. 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, compression and processing 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, compression and processing 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.

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.

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 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.

Liquidity and Capital Resources

Liquidity. Net cash of $26,733,185 was provided by operating activities in 2008. During the year, we used $56,875,544 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 $28,307,580 from financing activities, primarily consisting of advances under our revolving credit facility. As a result of these activities, net cash decreased from $2,816,678 at the end of 2007 to $981,899 at December 31, 2008.

Net cash of $1,828,345 was provided by 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.

As of December 31, 2008, we had a working capital deficit of $5,519,114. 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 2008 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. We also have substantial annual drilling commitments under various leases and farmouts for our Appalachian properties, including an annual 25-well commitment for our Leatherwood field. Our long-term performance and profitability is dependent not only on meeting these commitments and recovering existing oil and gas reserves, but also on our ability to find or acquire additional reserves and fund related infrastructure build-outs on terms that are economically and operationally advantageous.

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 reserve and infrastructure development and acquisition activities. Historically, we also relied on participation in our operated drilling initiatives by outside investors in our sponsored partnerships. For 2008, we changed our business model to accelerate organic growth by retaining all of our available working interest in wells drilled on operated properties, with a view to limiting our use of drilling partnerships to non-operated initiatives.

While we are committed to continue expanding our reserves and production through the drillbit, we have addressed the challenging conditions in our industry by reducing our 2009 capital spending budget to $15 million, allocated 80% to drilling and the balance to infrastructure and lease acquisition projects. This is in line with our anticipated cash flow from operations and may be adjusted during the year in response to market developments. To meet our 2009 drilling commitments and objectives with limited reliance on additional draws under our credit facility, we are returning to our established partnership structure and sales network, which raised over $34 million for a non-operated program last year. We expect to maintain a 20% interest in this year’s program, which will increase to 35% after program payout. With our critical infrastructure in place to provide deliverability for our production at a low cash cost, this will allow us to continue delivering organic growth, although at lower rates than we could achieve with access to the capital markets. If market conditions improve, we would expect to raise additional capital to accelerate drilling and meet our long-term resource development objectives.

We have a senior secured revolving credit facility maintained by our U.S. operating subsidiary, Daugherty Petroleum, Inc. (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 scheduled maturity in September 2011. We amended the facility in May 2008 to add to the collateral package and in August 2008 to increase the borrowing base from $75 million to $90 million. The borrowing base was lowered to $80 million at year end to reflect the downturn in the energy and credit markets. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 1.0% above that rate, depending on the amount of borrowing base utilization. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on DPI’s oil and gas properties and gathering facilities. As of December 31, 2008, outstanding borrowings under the facility aggregated $72 million, with $2 million in letters of credit, and the interest rate amounted to 4.25%. We are in compliance with our financial and other covenants under the credit facility at December 31, 2008.

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 a registered direct equity placement of our common stock at $6.00 per share in November 2007. We will be entitled to redeem the notes at their face amount plus accrued interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. In the event of a default under the notes or any change of control, the holders may require us to redeem the notes at a default rate equal to 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 revolving credit and convertible debt will be subject to our future performance and prospects as well as market and general economic conditions. 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 partnership capital. While we have been able to mitigate some of the steep decline in natural gas prices with fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production, we are exposed to price volatility for future production not covered by these arrangements. See “Risk Factors” and “Quantitative and Qualitative Disclosures about Market Risk.”

We have addressed the general economic downturn and current unsettled conditions in natural gas markets by reducing our capital expenditure budget and returning to our established drilling partnership structure for participation in our development initiatives. To realize our long-term goals for growth in revenues and reserves, however, we will continue to dependent on the credit and capital markets or other financing alternatives. Any prolonged constriction in the capital markets could require us to sell assets or pursue other financing or strategic arrangements to meet those objectives and to repay or refinance our long-term debt at maturity.

Forward Looking Statements

Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of Section 21E of the Securities Exchange Act and Section 27A of the Securities Act of 1933. 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 and required capital expenditures;

	•		commodity price volatility;

	•		increases in the cost of drilling, completion, gas gathering and processing or other costs of developing and producing our reserves;

	•		unavailability of drilling rigs and services;

	•		drilling, operational and environmental risks;

	•		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. See “Risk Factors.”

Financial Market Risk

Interest Rate Risk. Borrowings 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 indebtedness 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, except to the extent that global demand may affect domestic energy markets.

Contractual Obligations and Commercial Commitments

We are parties to leases for office facilities and various types of equipment. We are also obligated to make payments at specified times and amounts under instruments governing our long-term debt and other commercial commitments. The following table lists our minimum annual commitments as of December 31, 2008 under these instruments.


	Operating Leases						Other			Long-Term
Year	Equipment		Premises		Total		Commitments			Debt

2009	$	2,089,238	$	246,864	$	2,336,102	$	2,343,000	⁽¹⁾	$	24,000
2010		2,020,158		247,815		2,267,973		—			36,333,630	⁽²⁾
2011		1,794,697		252,389		2,047,086		—			72,024,000
2012		591,469		255,973		847,442		—			24,000
2013 and thereafter		51,929		21,355		73,284		—			198,818

Total	$	6,547,491	$	1,024,396	$	7,571,887	$	2,343,000		$	108,604,448


(1)		Reflects commitments under a purchase contract for an airplane.

(2)		Excludes an allocation of $690,370 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 partnerships, 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 utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions 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 the estimates used in the preparation of our financial statements are reasonable. The critical accounting policies affecting these aspects of our financial reporting are summarized in Note 1 to the consolidated financial statements included in this report. Policies involving the more significant judgments and estimates used in the preparation of our consolidated financial statements are summarized below.

Estimates of Proved Reserves and Future Net Cash Flows. Estimates of our proved oil and gas reserves and related future net cash flows are used in impairment tests of goodwill and other long-lived assets. These estimates are prepared as of year end by our independent petroleum engineers and are updated internally at mid-year. There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. 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 these estimates may require future revisions, and actual results could differ materially from the estimates.

Impairment of Long-Lived Assets. Our long-lived assets include property, 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.

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 settlements with customers.

Item 7A Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is the pricing of natural gas production, which has been highly volatile and unpredictable during the last several years. While we do not use financial hedging instruments to manage our exposure to these fluctuations or for speculative trading purposes, we do use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time up to two years from the contract date. Because these physical delivery contracts qualify for the normal purchase and sale exception under SFAS No. 133, they are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of physical delivery contracts is included in our oil and gas revenues at the time of settlement, which in turn affects our average realized natural gas prices. During 2008, approximately 50% of our natural gas production was sold under fixed-price contracts at rates ranging from $8.03 to $9.15 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. As of December 31, 2008, we had contracts in place for portions of our anticipated 2009 gas production from operated Appalachian properties at sales prices ranging from $9.58 per Mcf to $9.70 per Mcf. See “Business and Properties — Producing Activities.”

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 Firm		F-2
Consolidated Balance Sheets — December 31, 2008 and 2007		F-4
Consolidated Statements of Operations — For the years ended December 31, 2008, 2007 and 2006		F-5
Consolidated Statements of Changes in Shareholders’ Equity — For the years ended December 31, 2008, 2007 and 2006		F-6
Consolidated Statements of Cash Flows — For the years ended December 31, 2008, 2007 and 2006		F-7
Notes to Consolidated Financial Statements		F-8
Supplementary Oil and Gas Reserve Information — Unaudited		F-19
Supplementary Selected Quarterly Financial Data — Unaudited		F-22

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, 2008, 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, 2008 using the criteria established under Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on those criteria, management concluded that our internal control over financial reporting was effective as of December 31, 2008. 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, 2008 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.

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	54	Chairman of the Board, President and Chief Executive Officer	1993
William G. Barr III	59	Vice President	1993
D. Michael Wallen	54	Vice President	1995
Michael P. Windisch	34	Chief Financial Officer	2002

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

William S. Daugherty has served as our President, Chief Executive Officer and member of our board of directors since September 1993, as well as our Chairman of the Board since 1995. He has also served as the Chairman of the Board of Daugherty Petroleum, Inc., our operating subsidiary (“DPI”), since 1984. Mr. Daugherty currently serves as the Governor of Kentucky’s Official Representative to the Interstate Oil and Gas Compact Commission and as a member of the Board of Directors of the Independent Petroleum Association of America. He also serves on the Unconventional Resources Technology Advisory Committee. He is a past president of both the Kentucky Oil and Gas Association (“KOGA”) and the Kentucky Independent Petroleum Producers Association. Mr. Daugherty holds a B.S. Degree from Berea College, Berea, Kentucky.

William G. Barr III has served as a Vice President of NGAS since 2004 and as Chief Executive Officer of DPI since September 2005, having served as a Vice President of DPI from 1993 until being appointed its CEO. Mr. Barr has more than 30 years’ experience in the corporate and legal sectors of the oil and gas industry. Before joining DPI, he served in senior management positions with several oil and gas exploration and production companies and built 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. He received a Juris Doctorate from the University of Kentucky, Lexington, Kentucky.

D. Michael Wallen has served as a Vice President of NGAS since 1997 and as a Vice President of DPI between 1995 and September 2005, when he was appointed as its President. For six years before joining DPI, he served as the Director of the Kentucky Division of Oil and Gas. He has more than 25 years’ experience as a drilling and completion engineer for various exploration and production companies. Mr. Wallen recently served as President of KOGA and currently serves as a member of its Board of Directors and Executive Committee. He has also served as President of the Eastern Kentucky Section of the Society of Petroleum Engineers and as the Governor’s Representative to the Interstate Oil & Gas Compact Commission. Mr. Wallen holds a B.S. Degree in physics from Morehead State University, Morehead, Kentucky.

Michael P. Windisch has served as Chief Financial Officer of NGAS and DPI since 2002 . Prior to that time, he was employed by PricewaterhouseCoopers LLP, participating for five years in the firm’s audit practice. He was recently named Regional Financial Executive of the Year by the Institute of Management Accountants and Robert Half International. Mr. Windisch is a member of the American Institute of Certified Public Accountants and holds a B.S. Degree from Miami University, Oxford, Ohio, where he serves on the Advisory Board of the Department of Finance.

Incorporation of Part III Information by Reference

The balance of Part III to this report is incorporated by reference to the proxy statement for our 2009 annual meeting of shareholders to be filed with the Securities and Exchange Commission before the end of April 2009.

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).



Exhibit Number		*Description of Exhibit*

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 June 30, 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		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).

10.6		Amended and Restated Credit Agreement dated as of May 30, 2008 among NGAS Resources, Inc., Daugherty Petroleum, Inc. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.6 to Quarterly Report on Form 10-Q [File No. 0-12185] for the quarter ended June 30, 2008).

10.7		Amendment No. 1 dated as of August 4, 2008 to Amended and Restated Credit Agreement dated as of May 30, 2008 among NGAS Resources, Inc., Daugherty Petroleum, Inc. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.7 to Quarterly Report on Form 10-Q [File No. 0-12185] for the quarter ended June 30, 2008).

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 June 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 June 31, 2004).

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 June 31, 2004).

10.11		Form of Long-Term Incentive Agreement dated as of December 9, 2008.

10.12		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).

10.13		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).

10.14		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).

10.15		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 9 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 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.

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, 2008. In making this assessment, management used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that, as of December 31, 2008, 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, 2008, as stated in their report appearing on page F-2.



/s/ William S. Daugherty		/s/ Michael P. Windisch
William S. Daugherty, President and Chief Executive Officer March 11, 2009		Michael P. Windisch, Chief Financial Officer March 11, 2009

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NGAS Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying 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 U.S. 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.

In our opinion, NGAS Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued 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 balance sheets and the related statements of operations, shareholders’ equity and cash flows of NGAS Resources, Inc., and our report dated March 10, 2009 expressed an unqualified opinion.



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

Canton, Ohio
March 10, 2009

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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years ended December 31, 2008. 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 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 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 audit provides 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years ended December 31, 2008, 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, 2008, 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 10, 2009 expressed an unqualified opinion thereon.



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

Canton, Ohio
March 10, 2009

F-3

NGAS Resources, Inc.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
ASSETS
Current assets:
Cash	$	981,899		$	2,816,678
Accounts receivable		10,450,173			7,909,943
Prepaid expenses and other current assets		540,253			505,778
Loans to related parties		79,188			7,654

Total current assets		12,051,513			11,240,053
Bonds and deposits		623,898			535,445
Oil and gas properties		229,218,344			183,823,702
Property and equipment		3,285,925			3,689,636
Loans to related parties		171,429			249,410
Deferred financing costs		1,689,580			1,706,852
Other non-current assets		—			3,242,790
Goodwill		313,177			313,177

Total assets	$	247,353,866		$	204,801,065

LIABILITIES
Current liabilities:
Accounts payable	$	12,362,092		$	6,649,809
Accrued liabilities		675,141			2,484,617
Customer drilling deposits		2,262,955			2,857,806
Deferred compensation		2,246,439			—
Long-term debt, current portion		24,000			388,856

Total current liabilities		17,570,627			12,381,088
Deferred compensation		—			1,960,020
Deferred income taxes		12,949,476			9,218,770
Long-term debt		108,580,448			80,160,915
Other long-term liabilities		3,685,849			1,171,067

Total liabilities		142,786,400			104,891,860

SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
26,543,646 Common shares (2007 — 26,136,064)		110,626,912			108,842,526
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital — options and warrants		3,774,600			3,484,148
Contributed surplus		690,370			1,043,222
To be issued:
9,185 Common shares (2007 — 9,185)		45,925			45,925

		115,114,177			113,392,191
Deficit		(10,546,711	)		(13,482,986	)

Total shareholders’ equity		104,567,466			99,909,205

Total liabilities and shareholders’ equity	$	247,353,866		$	204,801,065

See accompanying notes.

F-4

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2008			2007			2006
REVENUE
Contract drilling	$	35,553,956		$	34,334,829		$	50,108,545
Oil and gas production		38,522,474			28,148,689			24,233,102
Gas transmission, compression and processing		10,330,234			7,719,308			5,478,642

Total revenue		84,406,664			70,202,826			79,820,289


DIRECT EXPENSES
Contract drilling		27,272,756			26,773,028			39,231,521
Oil and gas production		12,600,897			7,648,558			6,687,874
Gas transmission, compression and processing		4,107,763			3,657,977			3,094,504
Impairment of oil and gas assets		—			964,000			346,718

Total direct expenses		43,981,416			39,043,563			49,360,617


OTHER EXPENSES (INCOME)
Selling, general and administrative		14,005,041			12,920,591			13,201,107
Options, warrants and deferred compensation		911,561			1,069,306			1,558,676
Depreciation, depletion and amortization		12,418,234			10,416,696			8,266,056
Bad debt expense		749,035			215,000			—
Interest expense		5,575,007			6,330,760			4,321,815
Interest income		(95,774	)		(323,655	)		(356,302	)
Loss (gain) on sale of assets		(14,104	)		54,304			(3,197,834	)
Other, net		139,176			53,434			519,692

Total other expenses		33,688,176			30,736,436			24,313,210


INCOME BEFORE INCOME TAXES		6,737,072			422,827			6,146,462

INCOME TAX EXPENSE		3,800,797			1,239,424			4,154,024


NET INCOME (LOSS)	$	2,936,275		$	(816,597	)	$	1,992,438


NET INCOME (LOSS) PER SHARE
Basic	$	0.11		$	(0.04	)	$	0.09

Diluted	$	0.11		$	(0.04	)	$	0.09


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		26,409,275			22,240,429			21,510,594

Diluted		26,910,642			22,240,429			22,922,615

See accompanying notes.

F-5

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY


	Years Ended December 31,
	2008						2007						2006
	Shares			Amount			Shares			Amount			Shares			Amount
COMMON STOCK
Beginning balance		26,136,064		$	108,842,526			21,788,551		$	84,531,832			21,357,628		$	82,371,189
Issued in registered direct placement		—			—			4,200,000			23,687,955			—			—
Issued as bonus under incentive plan		50,000			259,690			10,430			61,010			65,945			468,612
Issued upon exercise of options and warrants		357,582			1,524,696			137,083			561,729			336,106			1,472,026
Issued for contract settlement		—			—			—			—			28,872			220,005

Ending balance		26,543,646			110,626,912			26,136,064			108,842,526			21,788,551			84,531,832

Treasury stock		(21,000	)		(23,630	)		(21,000	)		(23,630	)		(21,100	)		(23,630	)

Paid-in-capital — options and warrants					3,774,600						3,484,148						3,073,287
Contributed surplus					690,370						1,043,222						1,396,074
To be issued		9,185			45,925			9,185			45,925			9,185			45,925

DEFICIT
Beginning balance					(13,482,986	)					(12,666,389	)					(14,658,827	)
Net income (loss)					2,936,275						(816,597	)					1,992,438

Ending balance					(10,546,711	)					(13,482,986	)					(12,666,389	)

TOTAL SHAREHOLDERS’ EQUITY				$	104,567,466					$	99,909,205					$	76,357,099

See accompanying notes.

F-6

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2008			2007			2006
OPERATING ACTIVITIES
Net income (loss)	$	2,936,275		$	(816,597	)	$	1,992,438
Adjustments to reconcile net income to net cash provided by operating activities:
Incentive bonus paid in common shares		259,690			61,010			468,612
Compensation from options and warrants		911,561			1,069,306			1,558,676
Contract settlement paid in common shares		—			—			220,005
Depreciation, depletion and amortization		12,418,234			10,416,696			8,266,056
Bad debt expense		749,035			215,000			—
Impairment of oil and gas assets		—			964,000			346,718
Loss (gain) on sale of assets		(14,104	)		54,304			(3,197,834	)
Deferred income taxes		3,730,706			1,182,991			4,154,024
Changes in assets and liabilities:
Accounts receivable		(3,289,265	)		983,631			(2,224,874	)
Prepaid expenses and other current assets		(34,475	)		602,956			2,053,113
Other non-current assets		3,242,790			(608,519	)		(1,984,271	)
Accounts payable		5,712,283			(2,637,040	)		3,847,412
Accrued liabilities		(1,809,476	)		(852,151	)		(2,027,286	)
Customer drilling deposits		(594,851	)		(9,316,099	)		(11,454,070	)
Other long-term liabilities		2,514,782			508,857			237,710

Net cash provided by operating activities		26,733,185			1,828,345			2,256,429

INVESTING ACTIVITIES
Proceeds from sale of assets		66,555			394,720			6,841,368
Purchase of property and equipment		(504,329	)		(1,571,772	)		(1,026,778	)
Increase in bonds and deposits		(88,453	)		(1,750	)		(101,000	)
Additions to oil and gas properties, net		(56,349,317	)		(49,654,013	)		(49,526,536	)

Net cash used in investing activities		(56,875,544	)		(50,832,815	)		(43,812,946	)

FINANCING ACTIVITIES
Decrease in loans to related parties		6,447			7,513			26,035
Proceeds from issuance of common shares		1,190,006			24,131,483			1,472,026
Payments of deferred financing costs		(590,698	)		—			(429,819	)
Proceeds from issuance of long-term debt		29,740,000			13,360,000			31,000,000
Payments of long-term debt		(2,038,175	)		(109,825	)		(24,000	)

Net cash provided by financing activities		28,307,580			37,389,171			32,044,242

Change in cash		(1,834,779	)		(11,615,299	)		(9,512,275	)
Cash, beginning of year		2,816,678			14,431,977			23,944,252

Cash, end of year	$	981,899		$	2,816,678		$	14,431,977

SUPPLEMENTAL DISCLOSURE
Interest paid	$	5,575,759		$	6,343,734		$	4,411,157
Income taxes paid		—			—			—

See accompanying notes.

F-7

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, 2008, 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 prepared our financial statements prior to 2006 in accordance with accounting principles generally accepted in Canada (Canadian GAAP). Our adoption of U.S. GAAP in 2006 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 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 programs 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.

(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

F-8

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, 2008, 2007 and 2006, gas transmission, compression and processing revenue includes gas utility sales from Sentra’s regulated operations aggregating $565,727, $365,951 and $273,180, 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 6.67% of its aggregate indebtedness. At December 31, 2008, NGAS Securities had net capital of $96,609 and aggregate indebtedness of $18,853.

(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.

(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.

F-9

(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 had long-term incentive agreements with four of our executive officers and one key employee, providing for the vesting of stock options and incentive awards based on their annual base salary and bonus if they continued to serve in their positions until February 25, 2009 or any earlier termination of their employment without cause or resignation for good reason following a change of control. The bonus awards were payable and the options became exercisable on the vesting date. In December 2008, we provided new long-term incentive agreements to our executive officers and twelve key employees for a five-year retention period beginning February 25, 2009. See Note 9 — Capital Stock -— Stock Options and Awards. The awards under these agreements vest 40% after three years and 100% after five years or any earlier termination of their employment without cause or resignation for good reason following a change of control. The cash incentive awards for our executive officers are set at 100% of their annual base salary and bonus at the time of vesting. The cash incentive awards for key employees total $705,000. Accruals for deferred compensation under these agreements are recorded ratably based on estimated future payment dates and forfeiture rates.

(n) 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. We recognized bad debt expenses aggregating $749,035 in 2008 and $215,000 in 2007 as reserves against past due receivables.

(o) Reclassifications and Adjustments. Certain amounts included in the 2007 and 2006 consolidated financial statements have been reclassified to conform to the 2008 presentation.

(p) 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 20,000 Dth of controlled and third-party gas as of December 31, 2008.

(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.

(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, 2008 and 2007.

F-10


	As of December 31,
	2008			2007
Proved oil and gas properties	$	192,186,676		$	148,981,923
Unproved oil and gas properties		5,065,835			3,876,721
Gathering facilities and well equipment		67,326,445			55,370,995

		264,578,956			208,229,639
Accumulated DD&A		(35,360,612	)		(24,405,937	)

Net oil and gas properties and equipment	$	229,218,344		$	183,823,702

(c) Suspended Well Costs. The following table reflects the net changes in capitalized exploratory well costs, in accordance with FSP No. 19-1, Accounting for Suspended Well Costs, during each of the years presented:


	2008		2007			2006
Beginning balance at January 1	$	—	$	964,000		$	43,700
Additions pending determination of proved reserves		2,669,407		—			1,099,000
Reclassifications to proved reserves		—		—			—
Charged to expense		—		(964,000	)		(178,700	)

Ending balance at December 31	$	2,669,407	$	—		$	964,000

The following table provides an aging of capitalized exploratory well costs at December 31, 2008, 2007 and 2006, 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,
	2008		2007		2006
Exploratory well costs capitalized for one year or less	$	2,669,407	$	—	$	964,000
Exploratory well costs capitalized for more than one year		—		—		—

Balance at December 31	$	2,669,407	$	—	$	964,000

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, 2008 and 2007.


	As of December 31,
	2008			2007
Land	$	12,908		$	12,908
Building improvements		64,265			58,051
Machinery and equipment		3,333,981			3,170,601
Office furniture and fixtures		175,862			168,217
Computer and office equipment		670,349			578,317
Vehicles		1,951,279			1,869,551

		6,208,644			5,857,645
Accumulated depreciation		(2,922,719	)		(2,168,009	)

Net other property and equipment	$	3,285,925		$	3,689,636

Note 4. Loans to Related Parties

We extended loans to several of our officers prior to 2003 and to one of our shareholders in 2004. The shareholder loan bears interest at 5% per annum and had an outstanding balance of $79,188 at December 31, 2008 and $85,635 at December 31, 2007. The loan is collateralized by the shareholder’s interests in our drilling programs and is repayable over a five-year term from program production revenues, with a balloon payment at maturity. The loans receivable from officers totaled $171,429 at December 31, 2008 and 2007. These loans are non-interest bearing and unsecured.

F-11

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 $1,689,580 at December 31, 2008 and $1,706,852 at December 31, 2007, net of accumulated amortization.

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, 2008 and 2007, 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 were $2,262,955 at December 31, 2008 and $2,857,806 at December 31, 2007, representing 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 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 at our option 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, with a scheduled maturity in September 2011. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $80 million at December 31, 2008. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 1.0% above that rate, depending on the amount of borrowing base utilization. Alternatively, we may elect Eurodollar based pricing from 1.5% to 3.0% above quoted Libor rates. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. As of December 31, 2008, outstanding borrowings under the facility aggregated $72 million, with $2 million in letters of credit. The facility is secured by liens on substantially all our assets and is guaranteed by NGAS.

(c) Equipment Loan. We obtained a term loan of $2.1 million in September 2007 from Central Bank & Trust Co. to finance two previously purchased drilling rigs that we leased to one of our drilling contractors. The loan was repayable in monthly installments over a five-year term, bearing interest at 8% per annum, and was prepaid without penalty during the first quarter of 2008.

(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 $294,818 at December 31, 2008 and $318,818 at December 31, 2007.

(e) Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at December 31, 2008 and 2007 and the principal payments due each year through 2013 and thereafter.

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	At December 31,
	2008			2007
Principal Amount Outstanding
Total long-term debt (including current portion)⁽¹⁾	$	108,604,448		$	80,549,771
Less current portion		24,000			388,856

Total long-term debt⁽¹⁾	$	108,580,448		$	80,160,915

Maturities of Debt
2009	$	24,000
2010		36,333,630	⁽¹⁾
2011		72,024,000
2012		24,000
2013 and thereafter		198,818


(1)		Reflects allocations of $690,370 at December 31, 2008 and $1,043,222 at December 31, 2007 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features and related warrants.

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, 2008 or 2007.

(b) Common Shares. The following table reflects transactions involving our common stock during the reported periods.


	Number of
	Shares		Amount
Common Shares Issued
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
Issued to employees as incentive bonus		50,000		259,690
Issued upon exercise of stock options		357,582		1,524,696

Balance, December 31, 2008		26,543,646	$	110,626,912

Paid In Capital — Options and Warrants
Balance, December 31, 2006			$	3,073,287
Recognized				529,062
Exercised				(118,201	)

Balance, December 31, 2007				3,484,148
Recognized				625,142
Exercised				(334,690	)

Balance, December 31, 2008			$	3,774,600

Contributed Surplus
Balance, December 31, 2006			$	1,396,074
Accreted⁽¹⁾				(352,852	)

Balance, December 31, 2007				1,043,222
Accreted⁽¹⁾				(352,852	)

Balance, December 31, 2008			$	690,370

Common Shares to be Issued
Balance, December 31, 2008 and 2007		9,185	$	45,925


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

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(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 2008 and 2007, stock awards and option grants were made under these plans for a total of 2,350,000 and 10,430 shares, respectively. The following table shows transactions in stock options during 2008 and 2007.


							Weighted Average
	Issued			Exercisable			Exercise Price
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

Granted		2,300,000			—			2.93
Vested		—			41,667			6.02
Exercised		(357,582	)		(357,582	)		3.33
Forfeited		(10,000	)		(10,000	)		7.04

Balance, December 31, 2008		4,613,668			1,413,668			3.95

At December 31, 2008, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, and their weighted average remaining contractual life was 3.27 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2008.


Options Outstanding							Options Exercisable
			Weighted		Weighted				Weighted
Exercise			Average		Average				Average
Price			Remaining		Exercise				Exercise
or Range	Number		Life (years)		Price		Number		Price
$1.51		1,650,000		6.36	$	1.51		—	$	—
4.03 4.09		1,540,000		0.82		4.05		740,000		4.06
6.02 7.64		1,423,668		2.36		6.66		673,668		6.88

		4,613,668						1,413,668

In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment, which we adopted retroactively 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 0.03% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to six years based on the vesting provisions of the options. This resulted in non-cash charges for options and warrants of $625,142 in 2008 and 529,062 in 2007.

(d) Common Stock Purchase Warrants. We have issued common stock purchase warrants in various financing transactions. We had warrants for the purchase of 10,000 common shares at $4.03 per share outstanding at December 31, 2006, which were fully exercised in the first quarter of 2007.

Note 10. Income Taxes

(a) Components of Income Tax Expense. The following table sets forth the components of income tax expense for each of the years presented in the consolidated financial statements.

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	Year Ended December 31,
	2008		2007		2006

Current	$	—	$	—	$	—
Deferred		3,800,797		1,239,424		4,154,024


Total income tax expense	$	3,800,797	$	1,239,424	$	4,154,024

(b) Reconciliation of Tax Rates. 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.


	Year Ended December 31,
	2008		2007		2006

Income tax computed at statutory combined basic income tax rates	$	2,694,829	$	169,131	$	2,458,585
Increase (decrease) in income tax resulting from:
Non-recognition of tax benefit from parent company net losses		1,078,055		1,031,288		1,670,217
Non-deductible expenses		27,913		18,286		25,222
Difference in tax rates between Canada and the United States		—		20,719		—


Total income tax expense	$	3,800,797	$	1,239,424	$	4,154,024

(c) Components of Deferred Income Tax Liabilities. 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,
	2008			2007			2006

Net operating loss carryforward and investment tax credit	$	19,025,393		$	10,860,013		$	7,363,486
Gold and silver properties		2,522,094			2,522,094			2,522,094
Oil and gas properties		(23,586,375	)		(15,654,201	)		(10,661,622	)
Property and equipment		(625,351	)		(634,988	)		(605,960	)
Less valuation allowance		(10,285,237	)		(6,311,688	)		(6,653,777	)


Deferred tax liabilities	$	(12,949,476	)	$	(9,218,770	)	$	(8,035,779	)

(d) Net Operating Loss Carryforwards. As of December 31, 2008, we had net operating loss carryforwards of $54.1 million, including approximately $30.6 million at the parent company level. We have provided a valuation allowance in the full amount of the parent company loss carryforwards. The following table summarizes those net operating loss carryforwards by year of expiry.


Year of Expiry

2009	$	903,491
2010		922,437
2014		1,313,828
2015		4,288,214
2024		118,705
2025		1,622,053
2026		6,855,244
2027		16,781,239
2028		21,299,643


Total net operating loss carryforwards	$	54,104,854

(e) Uncertain Tax Positions. We adopted the provisions of FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes — Interpretation of FASB No. 109, on January 1, 2008. FIN No. 48 prescribes a two-step process for recognizing and measuring income tax uncertainties. First, a threshold condition of “more likely than not” should be met to determine whether any of the benefit from an uncertain tax position should be recognized in the financial statements. If the recognition threshold is met, FIN No. 48 provides additional guidance on measuring the amount of the uncertain tax position. We may recognize a tax benefit from an uncertain tax position under FIN No. 48 only if it is more likely than not that the tax position will be sustained on examination by taxing authorities based on the technical merits of the position. The tax benefit recognized in the financial

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statements from an uncertain position should be measured under FIN No. 48 based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, transition and increased disclosure of uncertain tax positions. We recognized no liability for unrecognized tax benefits resulting from our adoption of FIN No. 48.

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,
	2008		2007			2006

Numerator:
Net income (loss) as reported for basic EPS	$	2,936,275	$	(816,597	)	$	1,992,438
Adjustments for diluted EPS		—		—			—


Net income (loss) for diluted EPS	$	2,936,275	$	(816,597	)	$	1,992,438


Denominator:

Weighted average shares for basic EPS		26,409,275		22,240,429			21,510,594
Effect of dilutive securities:
Stock options		501,367		—			1,289,382
Warrants		—		—			122,639

Adjusted weighted average shares and assumed conversions for dilutive EPS		26,910,642		22,240,429			22,922,615


Basic EPS	$	0.11	$	(0.04	)	$	0.09


Diluted EPS	$	0.11	$	(0.04	)	$	0.09

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 $195,145 in 2008, $172,075 in 2007 and $123,596 in 2006.

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

2008	$	35,553,956
2007		34,334,829
2006		50,108,545

(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

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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.

Note 14. Financial Instruments

(a) Credit Risk. We grant credit to our customers in the normal course of business. We perform ongoing credit evaluations of customers’ financial condition and generally require no collateral. In addition, 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, 2008 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	$	294,818	$	207,846
Loans to related parties		250,617		206,413

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 $2,583,417 in 2008, $2,317,526 in 2007 and $1,727,982 in 2006. As of December 31, 2008, we had future obligations under operating leases and other commercial commitments in the amounts listed below.


	Operating		Other
Year	Leases		Commitments			Total

2009	$	2,336,102	$	2,343,000	⁽¹⁾	$	4,679,102
2010		2,267,973		—			2,267,973
2011		2,047,086		—			2,047,086
2012		847,442		—			847,442
2013 and thereafter		73,284		—			73,284


Total	$	7,571,887	$	2,343,000		$	9,914,887


(1)		Reflects 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

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generally determined on a units-of-production basis over the life of the asset, while the accretion escalates over the 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,
	2008			2007			2006

Asset retirement obligations, beginning of the year	$	947,100		$	820,400		$	491,900
Liabilities incurred during the year		152,449			182,594			489,154
Liabilities settled during the year		(82,982	)		(90,803	)		(206,323	)
Accretion expense recognized during the year		78,133			34,909			45,669


Asset retirement obligations, end of the year	$	1,094,700		$	947,100		$	820,400

Note 18. Recent Accounting Standards

Oil and Gas Reporting Requirements. In December 2008, the SEC amended its oil and gas reporting rules under the Exchange Act and Industry Guides. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by aligning the oil and gas disclosure requirements with current industry practices and technology. The amendments will be effective for fiscal years ending on or after December 31, 2009 and will significantly impact reserve and resource reporting for all E&P companies.

SFAS No. 162. In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS 162 identifies the sources of accounting principles and the framework for selecting principles to be used in the preparation and presentation of financial statements in accordance with U.S. GAAP. The statement will be effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. We do not expect the adoption of SFAS 162 to have an effect on our consolidated financial statements.

SFAS No. 161. In March 2008, the FASB issued SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities, which expands the quarterly disclosure requirements in SFAS No. 133 for derivative instruments and hedging activities, effective for fiscal years beginning after November 15, 2008. We do expect SFAS No. 161 to affect our consolidated financial position and results of operations.

FSP No. 157-2. In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which defers the effective date of SFAS 157 for certain nonfinancial assets and nonfinancial liabilities, except those recognized or disclosed at fair value in the financial statements on a recurring basis. The deferred provisions of SFAS 157 affect assets measured at fair value in goodwill impairment testing, nonfinancial long-lived assets measured at fair value for impairment assessment and asset retirement obligations initially measured at fair value. We will adopt these deferred provision on January 1, 2009 and do not expect them to have a material impact on our consolidated financial position or results of operations.

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.

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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,
Operating results:	2008			2007			2006

Revenues	$	38,522,474		$	28,148,689		$	24,233,102
Production costs		(12,600,897	)		(7,648,558	)		(6,687,874	)
DD&A		(9,252,942	)		(7,676,617	)		(6,501,001	)
Income taxes (allocated on percentage of gross profits)		(2,162,500	)		(815,435	)		(2,392,780	)


Results of operations for producing activities	$	14,506,135		$	12,008,079		$	8,651,447

(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,
Capitalized costs:	2008			2007			2006

Proved properties	$	192,186,676		$	148,981,923		$	110,169,303
Unproved properties		5,065,835			3,876,721			3,000,465
Gathering facilities and well equipment		67,326,445			55,370,995			46,369,858


		264,578,956			208,229,639			159,539,626
Accumulated DD&A		(35,360,612	)		(24,405,937	)		(15,322,094	)


Total	$	229,218,344		$	183,823,702		$	144,217,532

(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 and development costs:	2008		2007		2006

Unproved properties	$	1,189,114	$	1,405,603	$	1,928,556
Proved properties		39,970,220		35,185,951		21,714,182
Development costs		15,189,983		13,062,459		25,883,798


Total	$	56,349,317	$	49,654,013	$	49,526,536

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.

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(b) Estimated Oil and Gas Reserve Quantities. The following table summarizes our estimated quantities of proved oil and gas reserves and changes in net proved reserves for each of the years presented in the consolidated financial statements. The reserve additions reflected in the table for 2008 resulted primarily from our transition to horizontal drilling in our Leatherwood field, where we added 8.3 Bcfe to our proved developed reserves at year-end. However, our proved undeveloped reserves at year-end 2008 were reduced by 64% from the prior year’s estimates, including 16.2 Bcfe in Leatherwood. The reduction resulted primarily from the loss of previously booked vertical PUD locations that were no longer economic based on 2008 year-end commodity prices and drilling costs. While we expect many of the former vertical PUDs to be drilled horizontally with substantially better economics than vertical wells, we were only able to book a total of 14 horizontal PUD locations at the end of 2008, all in Leatherwood, based on restrictions for unconventional shale plays under the current reserve reporting rules.


										Crude Oil and
	Natural Gas									Natural Gas Liquids
	(Mmcf)									(Mbbls)
	2008			2007			2006			2008			2007			2006
Proved developed and undeveloped reserves:
Beginning of year		102,165			98,205			73,254			500			453			329
Purchase of reserves in place		164			82			—			2			—			—
Extensions, discoveries and other additions		9,994			23,290			28,086			400			14			2
Transfers/sales of reserves in place		(45	)		(3,801	)		(6,243	)		—			—			—
Revision to previous estimates		(48,059	)		(12,660	)		5,730			2,046			91			163
Production		(3,088	)		(2,951	)		(2,622	)		(150	)		(58	)		(41	)

End of year		61,131			102,165			98,205			2,798			500			453

Proved developed reserves at end of year		44,817			45,012			39,350			2,101			500			439

(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, 2008, 2007 and 2006 are calculated using weighted average prices in effect as of those dates. Those prices were $5.51, $7.39 and $6.15, respectively, per Mcf of natural gas and $40.00, $87.98 and $56.88, respectively, per barrel of oil and natural gas liquids. 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.

(In thousands)


	Year Ended December 31,
	2008			2007			2006
Future cash inflows	$	374,832		$	798,769		$	629,909
Future development costs		(39,097	)		(165,984	)		(136,850	)
Future production costs		(121,047	)		(197,730	)		(170,401	)
Future income tax expenses		(53,233	)		(117,699	)		(61,512	)

Undiscounted future net cash flows		161,455			317,356			261,146
10% annual discount for estimated timing of cash flows		(93,892	)		(214,574	)		(179,813	)

Standardized measure of discounted future net cash flows	$	67,563		$	102,782		$	81,333

F-20

(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.

(In thousands)


	Year Ended December 31,
	2008			2007			2006
Balance, beginning of year	$	102,782		$	81,333		$	207,648
Increase (decrease) due to current year operations:
Sales and transfers of oil and gas, net of related costs		(25,922	)		(20,500	)		(17,545	)
Extensions, discoveries and improved recovery, less related costs		12,071			64,083			9,828
Purchase of reserves in place		2,667			98			—
Increase (decrease) due to changes in standardized variables:
Net changes in prices and production costs		(27,272	)		38,984			(161,610	)
Revisions of previous quantity estimates		(24,060	)		(17,138	)		(13,227	)
Accretion of discount		10,278			8,133			20,765
Net change in future income taxes		17,879			(55,005	)		31,347
Production rates (timing) and other		(860	)		2,794			4,127

Net increase (decrease)		(35,219	)		21,449			(126,315	)

Balance, end of year	$	67,563		$	102,782		$	81,333

F-21



Exhibit Number		*Description of Exhibit*

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 2002.

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.



By:	/s/ William S. Daugherty	By:	/s/ Michael P. Windisch
	William S. Daugherty, President and Chief Executive Officer (Principal executive officer)		Michael P. Windisch, Chief Financial Officer (Principal financial and accounting officer)


Name		Date

William S. Daugherty James K. Klyman* Thomas F. Miller* Steve U. Morgan*


By:	/s/ William S. Daugherty	March 11, 2009
	William S. Daugherty,
	Individually and *as attorney-in-fact


	(In thousands, except per share amounts)
	Year Ended December 31,
	2008								2007
	4th		3rd		2nd		1st		4th		3rd			2nd			1st
Revenues	$	21,825	$	23,590	$	21,342	$	17,650	$	20,964	$	15,216		$	16,078		$	17,945
Income (loss) before income taxes		735		2,082		3,141		779		923		68			(647	)		79
Net income (loss)		307		945		1,521		163		257		(59	)		(761	)		(254	)
Diluted EPS		0.01		0.04		0.06		0.01		0.01		0.00			(0.03	)		(0.01	)

Common stock price range:
High	$	4.80	$	9.75	$	10.31	$	6.39	$	7.59	$	8.33		$	8.89		$	7.25
Low		1.30		4.41		5.58		4.50		5.50		6.50			6.70			6.02


	WRIGHT & COMPANY, INC.
	By:	/s/ D. Randall Wright
		D. Randall Wright,
		President



	/s/ James K. Klyman
	James K. Klyman



	/s/ Thomas F. Miller
	Thomas F. Miller



	/s/ Steve U. Morgan
	Steve U. Morgan



/s/ William S. Daugherty
William S. Daugherty
Chairman, Chief Executive Officer and President
March 11, 2009