United States Securities and Exchange Commission
Washington, D.C. 20549

FORM 10-K

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

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

NGAS Resources, Inc.

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

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

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

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

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

Yes o No x

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 x

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 x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for any shorter
period required).

Yes x 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.

x

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer o		Accelerated filer o		Non-accelerated filer x		Smaller Reporting Company o

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

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 $39,174,933.

As of February 28, 2011, there were 70,953,689 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain portions of the proxy statement for the 2011 annual meeting of shareholders are incorporated by reference
into Part III of this report.

     

     

Cautionary Notice

               Statements made by us in this report other than statements of historical fact are prospective and constitute forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. 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, including:

	•		lack of liquidity and limited forbearance from covenant defaults on our senior and convertible debt;
	•		conditions to closing for the pending sale of the company, including shareholder approval;
	•		uncertainty about our ability to continue as a going concern in the absence of a sale of the company;
	•		commodity price volatility;
	•		increases in the cost of developing and producing our reserves and unproved properties;
	•		drilling, operational and environmental risks; and
	•		uncertainties about future federal and state regulatory, conservation and tax measures.

               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.”

_________________________

Table of Contents

		Part I		Page
Items 1 and 2		Business and Properties		1
Item 1A		Risk Factors			14
Item 1B		Unresolved Staff Comments			18
Item 3		Legal Proceedings			18
Item 4		Submission of Matters to Security Holders			18
Part II
Item 5		Market for Common Equity and Related Matters			19
Item 6		Selected Financial Data			20
Item 7		Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 7A		Quantitative Disclosure About Market Risk			29
Item 8		Index to Financial Statements and Supplementary Data			29
Item 9		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			30
Item 9A		Controls and Procedures			30
Item 9B		Other Information			30
Part III
Item 10		Directors, Executive Officers and Corporate Governance			30
Item 11		Executive Compensation			32
Item 12		Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			32
Item 13		Certain Relationships and Related Transactions, and Director Independence			32
Item 14		Principal Accountant Fees and Services			32
Part IV
Item 15		Exhibits, Financial Statement Schedules			32
EX-23.1
EX-23.2
EX-24.1
EX-31.1
EX-31.2
EX-32.1
EX-99.1

_________________________

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. 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

Overview

               We are an independent exploration and production company focused on natural gas shale plays in the eastern United States, principally in the southern Appalachian Basin. We have specialized for over 25 years in generating our own geological prospects in this region, where we have established expertise and recognition. We also operate the gas gathering facilities for our core properties, providing deliverability directly from the wellhead to the interstate pipeline network serving major east coast natural gas markets. During the last three years, we have transitioned to horizontal drilling throughout our Appalachian acreage and expanded our operations to the Illinois Basin. Our core assets include over 330,000 acres with interests in approximately 1,350 wells and an extensive inventory of horizontal drilling locations.

               We were organized in 1979 under the laws of British Columbia. All of our oil and gas operations are conducted through our wholly owned subsidiary, NGAS Production Co. (NGAS Production), which we acquired in 1993. Our principal executive offices are located at Lexington, Kentucky. Unless otherwise indicated, references in this report to NGAS, the company or to we, our or us include NGAS Resources, NGAS Production and its subsidiaries and interests in managed drilling partnerships.

Recent Developments

               Reduced Capital Spending. We have addressed the challenging market conditions in our industry by funding our capital budget from cash flow and opening up our core properties to joint development with industry partners and sponsored drilling partnerships. Our 2010 drilling partnership raised over $23 million for participation in 25 horizontal wells. We have a 20% interest in that program, increasing to 35% after payout. This enabled us to meet most of our annual drilling commitments, while continuing to fund our capital expenditures from cash flows.

               Deleveraging Initiatives. Since mid-2009, we completed several initiatives to deleverage and rationalize our capital structure. We substantially reduced our revolving senior debt during the third quarter of 2009 by monetizing most of our Appalachian gas gathering assets, while retaining firm capacity for our controlled gas flows and long-term operating rights for the facilities, which we refer to as the Appalachian gathering system. See “Gas Gathering and Processing.” We further reduced our credit facility debt with proceeds from equity offerings in August 2009 and May 2010. In addition, during the first quarter 2010, we restructured convertible debt that was maturing at year end with new 6% amortizing convertible notes due May 1, 2012 (convertible notes). While improving our balance sheet, we were unable to mitigate the impact of reduced drilling activity, higher gas transportation costs from third-party ownership of the Appalachian gathering system and continuing weakness in natural gas prices on our operating cash flows. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) – Liquidity and Capital Resources.”

               Debt Covenant Defaults. On November 9, 2010, we reported that we were not in compliance with the leverage coverage covenant under our credit agreement as of end of the third quarter, which also triggered a cross default on the convertible notes. Our third quarter report also disclosed our prior engagement of a financial advisor to assist us pursue strategic alternatives. At that time, we had $35.8 million of credit facility debt and $21.5 million of outstanding convertible notes. We subsequently obtained limited forbearance from the covenant defaults, conditioned on completing a qualifying transaction that results in the repayment of the credit facility in full and all outstanding convertible notes at a default rate by March 31, 2011 or any extension by the credit facility lenders.

               Pending Sale of the Company. On December 23, 2010, we entered into a definitive agreement with Magnum Hunter Resources Corporation (Magnum Hunter) for the acquisition of the company by Magnum Hunter in an all-stock transaction to be implemented as an arrangement under British Columbia law, where we are organized at the parent company level (arrangement). Under the terms of the arrangement agreement, each common share of NGAS will be transferred to Magnum Hunter for the right to receive 0.0846 of a share of Magnum Hunter common stock (NYSE: MHR). The consummation of the arrangement is subject to various conditions, including approval of the arrangement by the company’s shareholders, receipt of Canadian court approval, repayment of the company’s senior and convertible debt by Magnum Hunter and restructuring of the company’s gas gathering agreements. See “MD&A – Contractual Obligations and Commercial Commitments.” The transactions contemplated by the arrangement agreement are scheduled to close on or about March 31, 2011, although there is no assurance that the acquisition will ultimately be consummated or that our lenders and note holders would continue to forbear on pursuing their legal remedies in that event. See “Risk Factors.” If the arrangement is completed, NGAS will become a wholly owned subsidiary of Magnum Hunter.

Drilling Operations

               Geographic Focus. As of December 31, 2010, we had interests in a total of 1,364 wells, concentrated on our operated Appalachian properties. Although mineral development in Appalachia has historically been dominated by coal mining interests, it is also one of the oldest and most prolific natural gas producing areas in the United States. The primary pay zone throughout our Appalachian acreage is the Devonian shale formation, providing predictable locations for repeatable drilling. It is considered an unconventional target due to its low permeability, requiring effective treatment to enhance gas flows. Estimated ultimately recoverable volumes (EURs) of natural gas for our vertical Devonian shale wells reflect modest initial volumes offset by low annual decline rates. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

               Horizontal Drilling Advances. Air-driven horizontal drilling and staged completion technologies optimized for our operating areas in the Appalachian and Illinois Basins have dramatically improved the economics of our shale plays. The ability to drill extended lateral legs also allows us to develop areas that would otherwise be inaccessible due to challenging terrain or coal mining activities. Most of our horizontals traverse Huron or Cleveland sections of the Devonian shale formation, which blankets our Appalachian properties at an average depth of 4,500 feet, or the New Albany shale in the Illinois Basin at depths from 2,600 to 2,800 feet. We have also drilled our first two horizontals through the Weir sandstone formation in the Roaring Fork field. Although the wells are at the beginning stages of production, we are very encouraged by initial results We have over 70,000 undeveloped acres that are prospective for this play

               Drilling Results. Our laterals are drilled at a slight angle from the bottom to the top of the formation, guided by real-time data on the drill bit location. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation. We perform a staged treatment process on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally one-million standard cubic feet for each of eight or more stages. While up to four times more expensive than vertical wells, horizontal drilling has substantially increased our recovery volumes and rates at lower overall finding costs. By stacking multiple horizontals on a single drill site and extending their lateral legs up to 4,500 feet, we have further improved our cost efficiencies and performance.

               The following table shows the number of our gross and net development and exploratory wells drilled during the last three years. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may earn in managed drilling partnerships. Drilling results for 2010 include 4 gross (0.7000 net) horizontal wells drilled during the fourth quarter of the year. All of the wells drilled during 2010 were on line and producing to sales at year-end.

		Development Wells												Exploratory Wells
Year Ended		Productive								Dry				Productive								Dry
December 31,		Gross				Net				Gross				Gross				Net				Gross
2010
Vertical			1				1.0000				—				—				—				—
Horizontal			26				4.2000				—				—				—				—
Subtotal			27				5.2000				—				—				—				—
2009
Vertical			10				1.6972				—				—				—				—
Horizontal			24				5.0588				—				—				—				—
Subtotal(1)			34				6.7560				—				—				—				—
2008
Vertical			137				58.8522				—				9				8.8125				—
Horizontal			47				15.7254				—				—				—				—
Subtotal(2)			184				74.5776				—				9				8.8125				—
Total			245				86.5336				—				9				8.8125				—

               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, generally up to 50% of the working interest in wells drilled on the covered acreage. During 2010, we had third-party participation for average working interests of 34% in our horizontal wells in Leatherwood. See “Oil and Gas Properties.”

               Drilling Operations. We do not operate any of the rigs or equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This has enabled us to streamline our operations and conserve capital for new wells, while retaining control over all geological, drilling, engineering and operating decisions. The geological characteristics of our Appalachian properties enables us to drill most of our horizontal wells within 15 days from spudding. Because of scheduling complexities for handling large volumes of nitrogen in the treatment stage, we have an overall drilling and completion cycle of at least 28 days for most of our horizontal wells. With the core gas gathering infrastructure in place for all our operated properties, we are usually able to bring our horizontal wells on line within one week after completion.

Producing Activities

               Regional Advantages. Our proved reserves, both developed and undeveloped, are concentrated in the southern Appalachian Basin. The proximity of this region to major east coast gas markets generates realization premiums above Henry Hub spot prices. 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 above 1 Dth per Mcf, this resulted in additional energy related premiums 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 production delivered through the Appalachian 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. Our share of processing fees, coupled with savings from rail shipping arrangements implemented for our NGL sales during 2009, have offset part of the reduction in energy-related yields from our Appalachian gas sales.

               Production Profile. Our Appalachian wells produce high quality natural gas at low pressures with little or no water production. Vertical wells in this region share a predictable profile characterized by moderate annual production declines throughout an economic life of 25 years or more without significant remedial work. Although the production history for horizontal wells in our operating areas is limited, reported production declines are consistent with profiles for vertical shale wells in the region. As of December 31, 2010, the reserve life index of our estimated proved reserves, representing the ratio of reserves to annual production, was 17.3 years overall and approximately 12.8 years for our proved developed producing reserves, based on 2010 production levels.

               Production Volumes, Prices and Costs. The following table shows our net production volumes for natural gas, crude oil and NGL during the last three years and the fourth quarters of 2010 and 2009.

		Three Months Ended
		December 31,								Year Ended December 31,
Production volumes:		2010				2009				2010				2009				2008
Natural gas (Mcf)			690,497				799,923				2,719,209				3,321,146				3,087,596
Crude oil (Bbl)			7,960				11,424				44,846				48,737				57,291
Natural gas liquids (gallons)			1,124,664				962,845				4,614,274				4,858,044				3,895,649
Equivalents (Mcfe)			822,606				940,681				3,334,354				3,977,920				3,745,124

               Production Prices and Costs. Our average sales prices for natural gas, crude oil and NGL during the last three years are listed below, along with our average lifting costs and transmission, compression and processing costs in each of the reported periods. The significant increase in transmission and compression costs during 2010 reflects the impact of gas gathering and sales agreements entered in connection with the sale of our Appalachian gas gathering system during the third quarter of 2009, which eliminated both our revenues and cost savings from ownership of these facilities. See “Gas Gathering and Processing” and “MD&A – Contractual Obligations and Commercial Commitments.”

Sales Prices and Production Costs:		Year Ended December 31,
		2010				2009				2008
Average sales prices:
Natural gas (per Mcf)		$	5.81			$	6.17			$	8.89
Crude oil (per Bbl)			71.76				52.63				95.07
Natural gas liquids (per gallon)			0.86				0.73				1.41
Lifting costs (per Mcfe)			0.85				0.74				1.42
Transmission, compression and processing costs (per Mcfe)			2.42				2.28				1.85

               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 hedges 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 December 31, 2010, we have contracts in place for approximately 33% of our gas production from operated Appalachian properties at a weighted average sales price of $6.66 per Mcf during the first six months of 2011.

Proved Oil and Gas Reserves

               General. The estimates of our proved oil and gas reserves at the end of each period covered in this report were prepared by Wright & Company, Inc., independent petroleum engineers (Wright & Co.). Wright & Co. was selected for its geographic expertise and historical experience in engineering properties in our operating areas. The technical personnel of Wright & Co. responsible for preparing the estimates meet the qualification, independence, objectivity and confidentiality standards of the Society of Petroleum Engineers for estimating and auditing reserves. The summary reserve report of Wright & Co. covering its estimates of our proved oil and gas reserves as of December 31, 2010 is included as an exhibit to this report. We have not filed any estimates of our proved reserves with any federal agency during the past year other than estimates included in periodic reports filed with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934 (Exchange Act). We also file our Exchange Act reports with Nasdaq Stock Market, Inc. and the British Columbia Securities Commission.

               We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished for their reserve estimates. This includes regular updates on our ownership interests in oil and gas properties, production information, well test data, commodity prices and operating and development costs. Our technical team meets throughout the year with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal reserve review committee, our senior management periodically reviews our reserve estimation and reporting process and our internal reserve and resource estimates.

               Revised Reserve Rules. Our reserve estimates as of December 31, 2010 were prepared in accordance with Subpart 1200 of Regulation S-K and Item 4-10 of Regulation S-X under the Exchange Act and related Compliance and Disclosure Interpretations on the Oil and Gas Rules issued by the SEC in October 2009 (current reserve rules). The current reserve rules went into effect at the end of 2009. They are intended to modernize reserve estimation and reporting standards to reflect current industry practices and technologies. Estimates of our proved oil and gas reserves as of December 31, 2008 were prepared in accordance with the SEC’s reserve estimation and disclosure rules in effect prior to the current reserve rules (prior reserve rules).

               Under the current reserve rules, proved reserves are generally defined as quantities of oil and gas that can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and governmental regulations. The reasonable certainty standard must be based on analysis of geoscience and engineering data that provides a high degree of confidence for deterministic estimates or at least a 90% probability that EURs will meet or exceed estimates based on probabilistic methods. Estimates of our proved oil and gas reserves were based on deterministic methods. The technologies and economic data used in estimating of our proved reserves include empirical evidence through drilling results and well performance, well logs and test data, geologic maps and available downhole and production data.

               Commodity Pricing. Economic producibility for estimates under the current reserve rules is determined using the unweighted average of the first-of-the-month spot prices for each commodity category during the twelve months preceding the date of the estimate, except for future production to be sold at contractually determined prices. Under the prior reserve rules in effect for 2008, economic producibility was based on commodity prices as of the date of the estimate. In all cases, costs are determined as of the date the estimate, and both prices and costs are held constant over the estimated life of the reserves. These prices are shown in the following table.

Commodity prices for reserve estimates:		2010				2009				2008
Natural gas (Mcf)		$	4.38			$	3.87			$	5.51
Crude oil (Bbl)			79.43				61.18				44.60
Natural gas liquids (Bbl)			49.64				34.32				26.20

               Reserve Quantities. The following table summarizes the estimated quantities of our proved developed reserves and proved undeveloped reserves as of December 31, 2010 and 2009, using the twelve-month average pricing model under the current reserve rules. Historical reserve estimates shown in the table as of December 31, 2008 were based on commodity prices as of the date of the estimates in accordance with the prior reserve rules. All reserves are located within the continental United States.

		As of December 31,
Proved Reserves:		2010				2009				2008
Natural gas (Mmcf)
Proved developed			35,192				38,177				44,817
Proved undeveloped			11,949				19,984				16,314
Total natural gas			47,141				58,161				61,131
Natural gas liquids (Mbbl)
Proved developed			1,260				1,391				1,500
Proved undeveloped			616				1,262				697
Total natural gas liquids			1,876				2,653				2,197
Crude oil (Mbbl)
Proved developed			650				709				602
Proved undeveloped			139				4				—
Total crude oil			789				713				602
Total natural gas equivalents (Mmcfe) (1)
Proved developed			46,652				50,776				57,425
Proved undeveloped			16,479				27,581				20,496
Total proved reserves			63,131				78,357				77,922

               Changes in Proved Reserves. As of December 31, 2010, our proved undeveloped (PUD) reserves of 16.5 Bcfe represented 26% of our total proved reserves. None of our 2010 year-end PUDs have been included in our reported reserves for more than five years. Under the current reserve rules, proved undeveloped reserves are estimated volumes expected with reasonable certainty to be recovered from new wells on undrilled acreage within a reasonable time horizon, generally limited to five years from the date of the estimate, based on reliable technology that has demonstrated by field testing to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We added 5.4 Bcfe in horizontal PUD locations supported by reliable technology as of December 31, 2010 and 1.1 Bcfe in proved developed reserves from wells drilled during the year on unproved locations. The additions were offset by net negative revisions of 16.9 Bcfe to our prior year estimates. The revisions reflect an increase of 2.3 Bcfe from higher 2010 average prices and decreases of 6.9 Bcfe due to quantity revisions and 12.3 Bcfe from the loss of 23,872 undeveloped acres due to a drilling commitment shortfall under our Leatherwood farmout. See “Oil and Gas Properties – Reserves from Significant Fields.”

               As of December 31, 2009, our PUD reserves of 27.6 Bcfe represented 35% of our total proved reserves and included 15.9 Bcfe in new horizontal PUD locations supported by reliable technology. During 2009, we converted 0.03 Bcfe in prior year-end PUDs and 19.4 Bcfe in unproved reserves into proved developed reserves. The additions were partially offset by negative revisions of 6.7 Bcfe to our proved developed reserves from lower 2009 average prices.

               Reserve Values. The following table summarizes the estimated future net cash flows from the production and sale of our proved reserves as of December 31, 2010, 2009 and 2008 and the standardized measure for reporting 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 (SEC-10). 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.

(In thousands)

Estimated future net cash flows		As of December 31,
from proved reserves:		2010				2009				2008
Undiscounted future net cash flows(1)		$	89,254			$	88,207			$	161,455
10% annual discount for estimated timing of cash flows			(63,150	)			(59,441	)			(93,892	)
Standardized measure of discounted future net cash flows		$	26,104			$	28,766			$	67,563

               Estimates of our proved reserves include PUD locations that would generate positive future net revenue based on the constant prices and costs determined under the current reserve rules but would have negative present value when discounted at 10% per year under the standardized measure. Although we lost 23,872 undeveloped acres in Leatherwood at the end of 2010 for failure to meet our annual drilling commitment for that block, the PUDs booked to that acreage had a negative SEC-10 value at December 31, 2009, creating a positive impact on the standardized measure at December 31, 2010. This was partially offset by the impact of adding 5.4 Bcfe in horizontal PUD locations in 2010, since all but one of the PUDs had a negative SEC-10 value.

               Reserve Pricing Sensitivity. Under the twelve-month average pricing model required by the current reserve rules, the natural gas price used in our reserve estimates at December 31, 2010 was 16% less than the 5-year average NYMEX strip price, before basis differentials. The following table shows the impact of NYMEX pricing assumptions on our reported proved reserves at December 31, 2010, both developed and undeveloped, and the discounted future net cash flows from our estimated proved reserves, before giving effect to any future income taxes on the discounted future cash flows (PV-10).

		Natural				Crude								Proved								Total
		Gas				Oil				NGL				Developed				PUD				Proved
2010 Pricing Assumptions:		Price				Price				Price				Reserves				Reserves				Reserves				PV-10
		($/Mcf)				($/Bbl)				($/Bbl)				(Bcfe)				(Bcfe)				(Bcfe)				(000)
Twelve-month average		$	4.38			$	79.43			$	49.64				46.65				16.48				63.13			$	42,198
5-year average NYMEX strip			5.22				93.01				58.13				50.97				46.36				97.60				55,865

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, 2010. 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								Undeveloped
Property Location:		Gross Acres				Net Acres				Gross Acres				Net Acres
Kentucky			93,209				34,701				184,116				156,498
Virginia			2,749				2,362				14,358				12,204
Tennessee			1,691				397				38,497				32,722
Arkansas			8,913				2,179				2,960				2,235
Oklahoma			2,127				426				—				—
Total			108,689				40,065				239,931				203,659

               Our oil and gas interests also include an overriding royalty interest of 1.35% retained after monetizing an assembled lease position in the Williston basin at the end of 2006. The position covers 18,411 gross (14,864 net) acres in the southwestern portion of Dunn County, North Dakota.

               Productive Wells. The following table shows, by state, our gross and net productive oil and gas wells as of December 31, 2010. All of the wells that were in progress or were drilled by year end but were awaiting installation of gathering lines.

		Gas Wells								Oil Wells								Total
Well Location:		Gross				Net				Gross				Net				Gross				Net
Kentucky			964				465.94				15				11.73				979				477.67
West Virginia			240				37.53				—				—				240				37.53
Arkansas			54				14.83				—				—				54				14.83
Virginia			40				31.83				1				1.00				41				32.83
Tennessee			19				6.69				—				—				19				6.69
Oklahoma			13				3.74				—				—				13				3.74
Other			—				—				18				0.23				18				0.23
Total			1,330				560.56				34				12.96				1,364				573.52

               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, 2010.

		Proved Reserves at December 31, 2010
		Developed																				Undeveloped
Field:		Gas				NGL				Oil				Total				%				Gas				NGL/Oil				Total
		(Mmcf)				(MBbls)				(MBbls)				(Mmcfe)								(Mmcf)				(MBbls)				(Mmcfe)
Leatherwood			9,737				584				80				13,723				85	%			1,754				105				2,386
Arkoma			7,509				—				—				7,509				87				1,090				—				1,090
SME–Amvest			3,575				214				287				6,585				67				1,776				242				3,230
SME–Martin’s Fork			3,512				211				47				5,058				64				2,115				127				2,876
HRE			3,081				—				1				3,084				100				—				—				—
Straight Creek			2,413				145				84				3,786				93				203				12				276
Kay Jay			2,256				—				2				2,267				89				279				—				279
Fonde			1,488				79				2				1,976				25				4,363				262				5,933
Other fields			1,621				27				147				2,664				87				370				7				410
Total			35,192				1,260				650				46,652				74	%			11,950				755				16,480

               Description of Significant Fields. Our producing properties and undeveloped acreage positions are concentrated in the southern Appalachian Basin. We also have interests in a non-operated coalbed methane project in the Arkoma Basin and non-operated projects in West Virginia and Virginia, as well as our New Albany shale play within the Illinois Basin in western Kentucky. 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, 2010.

               Leatherwood. The Leatherwood field extends 41 miles through Letcher, Perry, Leslie and Harlan Counties in eastern Kentucky. We acquired most of interests in this field late in 2002 under a farmout agreement with the mineral interest owners, Equitable Production Company and KRCC Oil & Gas, LLC. At that time, there was no gas gathering infrastructure in the region, which has a history as an active coal producing district. In 2005, we completed the construction of a 23-mile gathering system for Leatherwood and a 16-mile line connecting the field to the midstream portion of the Appalachian gathering system. Prior to the sale of the system in the third quarter of 2009, we added several pipeline and compression upgrades to keep pace with expanding Leatherwood production. Subject to meeting various stages of drilling commitments, our development rights under the initial Leather farmout covered approximately 59,000 acres. We expanded our position in Leatherwood during 2009 with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky.

               Since completion of a successful 25-well exploratory project under the original Leatherwood farmout in 2003, we drilled a total 282 development wells on this acreage, including 45 horizontal wells. Vertical wells in Leatherwood produce from the Maxon sand, Big Lime and Devonian shale formations, and the horizontals have targeted the Lower Huron and Cleveland sections of the Devonian shale. The Leatherwood farmout provides the mineral interest owners with participation rights for up to 50% of the working interest in new wells, which were exercised for average total working interests of 34% in Leatherwood wells during 2010. Our interests in horizontal Leatherwood wells drilled during 2010 added 5.8 Bcfe to our proved developed reserves. We had a total of 297 wells on line in Leatherwood at year-end, with total daily gross and net production of 6,552 Mcfe and 2,403 Mcfe, respectively. We operate all the wells, which produce to sales through the Appalachian gathering system. Estimated reserves are 85% proved developed.

               The original Leatherwood farmout required us to drill a total of 200 wells through 2007, followed by an annual 25-well commitment. We satisfied the initial 200-well commitment ahead of schedule and continued to meet our annual drilling commitments through 2009. In December 2010, the farmout was terminated on a block of 23,872 undeveloped acres for failure to satisfy the portion of our annual drilling commitment required to hold that acreage. The termination does not affect the balance of our ownership interests or operating rights under the farmout. The lease acquired in 2009 to expand our Leatherwood position required us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment. [Status]

               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. In November 2005, we acquired Dart Energy’s position, including its 25% interest in the field’s gathering system and a total of 48 CBM wells drilled by the joint venture. We also entered into a farmout with CDX for 90% of its majority (75%) interest in specified drilling locations on its acreage. Under the farmout, we assumed all of future developments costs for the CDX position and granted them a 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 the Arkoma farmout before electing to terminate it in 2007. During the balance of 2007, we participated in four CBM wells through our interests from the Dart Energy acquisition. No wells were drilled in the last three years. We had interests in a total of 66 wells producing to sales in this field at the end of 2010, with daily gross and net CBM production of 8,036 Mcf and 1,799 Mcf, respectively. Estimated reserves from our interests in the Arkoma field are 87% proved developed.

               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 or SME fields, they span approximately 86,500 acres in Harlan County, Kentucky and Lee County, Virginia. 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 66 wells on this acreage, including seven horizontal wells during 2010. 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 horizontals have targeted the Lower Huron section of the Devonian shale in Martin’s Fork, which ranges in thickness up to 200 feet, and the Upper Huron and Cleveland sections of the Devonian shale in Amvest, with a combined thickness up to 130 feet. At year end, we had a total of 80 wells in Martin’s Fork and 81 wells in Amvest, with daily gross and net production aggregating 4,357 Mcfe and 2,919 Mcfe, respectively. We operate all the wells and produce all natural gas in these fields through the Appalachian gathering system. Estimated reserves are 67% proved developed in Amvest and 64% proved developed in Martin’s Fork.

               In May 2009, we acquired a farmout from Chesapeake Appalachia, LLC for a tract of 56,000 gross (42,000 net) undeveloped acres contiguous to the Amvest portion of our Stone Mountain field in Letcher and Harlan Counties, Kentucky. Prior development includes approximately 100 producing wells and infrastructure connecting to the Appalachian gathering system. Penn Virginia Operating, LLC, the royalty interest owner, and Chesapeake each have participation rights for up to 25% of the working interests in our future wells on the acreage, and we have a minimum annual drilling commitment of four wells under the farmout. We also had an initial commitment to drill six vertical Devonian shale wells by the beginning of June 2009. To meet the commitment, we entered into arrangements with a joint venture partner that provides us with a 15% carried working interest in these wells, which we completed on schedule with encouraging results. We granted our joint venture partner participation rights for up to 50% of our available working interest in subsequent wells drilled on the acquired acreage.

               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. From 2006 through the 2008, we participated in a total of 246 wells drilled by Hard Rock on its acreage, including 39 horizontals. Most of the HRE wells target 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 partnerships. As of year-end, we had interests in a total of 244 wells producing to sales in these fields, with daily gross and net production of 5,497 Mcfe and 731 Mcfe, respectively. Estimated reserves from our interests in the HRE fields are 100% proved developed.

               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. During 2010, we drilled one horizontal well in Straight Creek through 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. We operate all the wells in Straight Creek, which produce to sales through the Appalachian gathering system. As of year-end, we had a total of 193 wells on line in this field, with daily gross and net production of 2,176 Mcfe and 708 Mcfe, respectively. Estimated reserves from our interests in Straight Creek are 93% proved developed.

               Kay Jay. The Kay Jay field spans portions of Knox and Bell Counties, 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. Wells in Kay Jay 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 retained our ownership of the field-wide gathering facilities, which are currently connected to third-party pipeline systems. In connection with our sale of the Appalachian gathering system during the third quarter of 2009, we granted certain first refusal rights to Seminole Energy for any sale of our interests in Kay Jay or in its field-wide gathering facilities. We had a total of 131 wells in Kay Jay producing to sales at year end, with daily gross and net natural gas production of 1,755 Mcfe and 562 Mcf, respectively. Estimated reserves from our interests in Kay Jay are 89% 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 39,000 acres under a series of farmouts and leases. We drilled a total of 65 vertical wells in Fonde, which produce natural gas from the Big Lime and Devonian shale formations at depths up to 4,500 feet, along with crude oil from the Big Lime. We completed construction of a 14-mile steel line early in 2008 to provide deliverability for our Fonde production into the Appalachian gathering system, enabling us to connect a backlog of wells. During 2009, we drilled our first horizontal well in Fonde through the Cleveland section of the Devonian shale, which ranges in thickness up to 100 feet at an average depth of 4,500 feet. We deferred our plans for additional horizontal wells in Fonde throughout 2010 and subsequently obtained an extension of a five-well drilling commitment under a lease covering approximately 23,000 acres in Fonde. At year-end, we had 37 wells in Fonde, with daily gross and net production of 903 Mcfe and 388 Mcfe, respectively. We operate all the wells and produce all natural gas in the field through the Appalachian gathering system. Estimated proved reserves are 62% proved developed.

               Haley’s Mill. Our New Albany shale play, known as Haley’s Mill, is situated in the southcentral portion of the Illinois Basin, spanning portions of Christian and Hopkins Counties in western Kentucky. We assembled our initial lease position during 2006 and subsequently expanded our position to approximately 52,000 acres. The New Albany shale formation blankets this acreage at depths ranging from 2,600 to 2,800 feet and has similar geologic characteristics to the Devonian shale in the Appalachian Basin. Although we completed the infrastructure build-out for the project during 2007, including a processing facility to reduce nitrogen levels in the gas to pipeline quality standards, 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 35 wells on line in Haley’s Mill at the end of 2010, including three horizontals, with daily gross and net year-end production of 683 Mcf and 546 Mcf, respectively. We did not book any proved reserves in Haley’s Mill at year-end.

Drilling Partnerships

               Partnership Business Model. Since 1996, NGAS Production has sponsored 38 drilling partnerships for accredited investors to participate in many of our drilling initiatives. 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 partnership 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. In 2006, we changed the structure of our drilling and operating agreements with sponsored programs 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. The portion of the profit on drilling contracts from our ownership interest in each program is eliminated on consolidation in our financial statements.

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

	•		Expanding our drilling budget with outside capital from partnership investors enables us to build our asset base through increased drilling commitments, while also leveraging our buying power for drilling services and materials, resulting in lower overall development costs.
	•		Accelerating the pace of development activities through our drilling programs expands the production capacity we can make available to gas purchasers, contributing to higher and more stable sales prices for our production.
	•		Our drilling partnership business model increases the number of gross wells we could drill on our own, diversifying our drilling risks and opportunities.

               Investment Capital. During the last three years, our sponsored drilling partnerships raised over $76 million in private placements with accredited investors for participation in many of our drilling initiatives. Proceeds from these private placements are used to fund the investors’ share of drilling and completion costs under our drilling and operating agreements. These payments are recorded as customer drilling deposits at the time of receipt. We recognize revenues from these operations on the completed contract method as the wells are drilled, rather than when funds are received. Our development activities through 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
2010			25			$	23,105,546			$	5,776,387			$	28,881,933
2009			22				19,251,125				4,812,781				24,063,906
2008			89				34,460,340				10,919,628				45,379,968
Total			136			$	76,817,011			$	21,508,796			$	98,325,807

               Drilling Program Interests. In addition to managing operations, we contribute capital to an operating joint venture program formed with each of our sponsored drilling partnerships in proportion to our initial ownership interest, and we share program distributions in the same ratio until program payout, generally established at 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 in 2008 to accelerate organic growth. In response to market conditions since that time, we reduced our capital expenditure budget and opened up our operated properties for joint development with sponsored partnerships, as well as industry partners. We have a 20% interest before payout and a 35% interest after payout in our 2010 and 2009 drilling partnerships..

               Liquidity Features. Many of the drilling partnerships we sponsored over the last nine 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 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. 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 drilling partnerships have used these liquidity features, which do not affect the way we account for our interests in these programs.

Gas Gathering and Processing

               Infrastructure Monetization. Historically, we constructed and operated the gas gathering and compression facilities for all of our operated properties in the Appalachian and Illinois Basins. During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering and midstream facilities to Seminole Energy Services, LLC and its subsidiary (Seminole Energy) for $50 million, of which $14.5 million is payable in monthly installments through December 2011 with interest at 8% per annum. As part of the sale, we entered into gas gathering and sales agreements with Seminole Energy that provide us with long-term operating rights and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas through the Appalachian gathering system for a fifteen-year terms with renewal options. This ensures continued deliverability from our connected fields, representing over 90% of our Appalachian production, to major east coast natural gas markets through an interconnect with Spectra Energy Partners’ East Tennessee Interstate pipeline network.

               Gas Gathering and Compression. Our gas gathering and sales agreements with Seminole Energy provide for fixed monthly gathering fees of $862,750, monthly operating fees of $182,612, plus $0.20 per Mcf of purchased gas, and capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the system by Seminole Energy. The gathering and compression fees reflect our firm capacity commitment for 30,000 Mcf/d and are subject to periodic increases based on operating costs and other contractual adjustments. On a per unit basis, these fees are volume dependent, and ranged from $2.25 to $3.08 per Mcf during 2010 for deliveries of our controlled gas through the Appalachian gathering system.

               Retained Gathering Systems Our sale of the Appalachian gathering system did not include the infrastructure for our Kay Jay field in eastern Kentucky or our Haley’s Mill project in western Kentucky, and we continue to receive gas gathering and compression fees for third-party production serviced by these facilities. We also own a 25% interest in the gas gathering facilities for our non-operated wells in the Arkoma Basin.

               Gas Processing. We own 50% interests in a liquids extraction plant for natural gas delivered through the Appalachian gathering system, located in Rogersville, Tennessee, and a nitrogen rejection facility for our Illinois Basin production. The Rogersville plant extracts NGL at levels enabling us to flow 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 are co-owned and operated by Seminole Energy. Gas processing fees are volume dependent and are shared with Seminole Energy.

Customers

               Natural Gas Sales. We sell our natural gas production primarily through unaffiliated gas marketing intermediaries, including Seminole Energy and Stand Energy Corporation, which each account for more than 10% of our total gas sales. 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 2010, approximately 50% of our natural gas production was sold under fixed-price contracts at rates ranging from $5.20 to $8.68 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. The gas sales contracts covering both types of marketing arrangements yield upward adjustments from index based pricing for throughput with an energy content between 1 Dth and 1.1 Dth per Mcf.

               Crude Oil and NGL Sales. Our crude oil production and NGL extracted from our Appalachian gas production is sold primarily to refineries at posted field or spot prices, net of transportation costs. Crude oil is generally picked up and transported by our customers from storage tanks located near the wellhead. NGL is delivered to customers from our Rogersville plant under rail shipping arrangements implemented during 2009, reducing our transportation costs for extracted natural gas liquids.

               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, 2010, 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 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 for several 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 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, with increased 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 can 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 FERC. During the last decade, a series of initiatives were undertaken by FERC to remove various barriers and eliminate 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. These include regulations governing the generation, storage, handling and disposal of materials and the discharge of materials into the environment. 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 (EPA) 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 can result in substantial liabilities, penalties and injunctive restraints, as well as potential claims by landowners and other third parties for personal injury and property damage.

               We conduct our drilling and production activities to comply with all applicable environmental regulations, permits and lease conditions, and we monitor drilling subcontractors 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 materials, remediate property contamination or undertake plugging operations to prevent future contamination.

               Regulation of greenhouse gas (GHG) emissions and hydraulic fracturing presents a number of issues for our industry. Although we use only nitrogen fracturing and are not subject to a recently adopted EPA rule requiring annual reporting of GHG emissions, we monitor legislative and regulatory developments on these issues at both the federal and state levels.

               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, 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.

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. We stopped all exploratory work on the properties in 1996 and elected to write off their remaining carrying value in 2000. We have no plans to develop these properties, which would require rehabilitation and equipping of existing mine shafts and workings, level rehabilitation and geologic sampling and mapping prior to any surface and underground drilling.

Office Facilities

               We occupy 13,852 square feet of commercial space for our principal and administrative offices in Lexington, Kentucky. The building was acquired in 2006 by a company formed for that purpose by our executive officers and a key employee. We entered into lease renewals for our offices in November 2007 for a five-year term at monthly rents initially totaling $20,398, subject to annual escalations, on the same terms as our prior lease. The building was purchased by NGAS Production in February 2010 for approximately the same purchase price paid by the management group in 2006. See “MD&A – Related Party Transactions.”

Employees

               As of December 31, 2010, we had 102 full-time employees. Our staff includes professionals experienced in geology, petroleum engineering, land acquisition, finance, accounting and law.

Item 1A Risk Factors

               The risks and related factors we consider material to our business are summarized below. The occurrence of any one of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows. In addition to the other information contained in this report, including the matters addressed in “Cautionary Statement Regarding Forward-Looking Statements,” you should carefully consider the following risk factors in evaluating the company.

We are in covenant default under our credit agreement and cross default of our convertible notes and, if we are unable the complete our pending sale to Magnum Hunter or enter into an alternative transaction which results in repayment of these debt obligations by March 31, 2011, we may be forced into bankruptcy by the credit facility lenders and note holders.

               We are currently in default of the leverage coverage covenant under our credit agreement, which triggered a cross default under our 6% amortizing convertible notes during the fourth quarter of 2010. The credit facility lenders and note holders have agreed to forbear from pursuing their legal remedies under the condition that the company complete a qualifying transaction that results in the repayment in full of all obligations under the credit agreement and the payment of all remaining convertible notes at a default rate by March 31, 2011 or a subsequent date not later than April 15, 2011 that the lenders may extend the forbearance deadline. There is no certainty that the lenders and note holders would continue to forbear if we fail to complete the pending sale of the company under our arrangement agreement with Magnum Hunter and are not able to enter into an alternative qualifying transaction which results in repayment of these obligations by the scheduled deadline. In that event, the company would not have sufficient funds to make these debt payments, and could be forced into bankruptcy if the credit facility lenders or note holders choose to pursue their legal remedies.

If we are unable to complete the arrangement or other qualifying transaction by the forbearance deadline imposed by our credit facility lenders and are forced into bankruptcy, our common stock would be severely diluted or eliminated entirely.

               We had a working capital deficit of $47.8 million as of December 31, 2010, primarily reflecting our obligations as of year-end under our credit agreement and convertible notes. Substantially all of our assets are pledged as collateral under our credit facility, and the lenders would be entitled to take possession and foreclose on our assets, including our cash balances, if we are unable to complete the arrangement or other qualifying transaction by the forbearance deadline. In that event, the holders of our convertible notes or other creditors may seek to initiate involuntary bankruptcy proceedings against us or against one or more of our subsidiaries, which would force us to make defensive voluntary filings of our own under the federal bankruptcy laws. In either case, it is likely that our common stock would be severely diluted if not eliminated entirely.

Based on our lack of financial liquidity and the limited forbearance from the covenant default under our credit agreement and cross default of our convertible notes, our independent registered public accounting firm included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 2010 regarding their substantial doubt as to our ability to continue as a going concern.

               Based on our lack of financial liquidity and the limited forbearance from the covenant default under our credit agreement and cross default of our convertible notes, our independent registered public accounting firm has included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 2010 regarding their substantial doubt as to our ability to continue as a going concern. As of December 31, 2010, our credit facility had an outstanding balance of $35.5 million, and we had $16.5 million in convertible notes outstanding, all of which had been called for redemption in cash at a default rate. Our consolidated financial statements included in this report have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include any adjustments to our recorded assets and liabilities that could be required if we were unable to satisfy the terms of our forbearance agreements with the credit facility lenders and note holders.

Although the arrangement will be a qualifying transaction, if completed by the forbearance deadlines imposed by our lenders and note holders, the consummation of arrangement is subject to certain closing conditions, and there is no assurance that those conditions will be satisfied.

               The consummation of the arrangement transaction with Magnum Hunter is subject to certain closing conditions including, among other things:

	•		the affirmative vote of two-thirds of the votes cast by the holders of the company’s common stock;
	•		the receipt of Canadian court approval;
	•		the continuing effectiveness of the company’s agreement with its credit facility lenders to forbear from exercising any rights or remedies under our credit agreement;
	•		the effective date of the arrangement being on or before March 31, 2011 or a subsequent date not later than April 15, 2011 that the lenders may extend the forbearance deadline;
	•		the issuance of no more than 32 million shares of the company’s common stock to the holders of our convertible notes since November 15, 2010;
	•		the absence of any event, circumstance or fact that individually or in the aggregate has had or would be expected to have a material adverse effect with respect to the company;
	•		the absence of injunctions or restraints imposed by governmental entities;
	•		the restructuring of our gas gathering and sales arrangements with Seminole Energy on substantially the terms set forth in a letter of intent among Magnum Hunter, NGAS Production and Seminole Energy in connection with our entry into the arrangement agreement; and
	•		the full payment by Magnum Hunter of all remaining convertible notes at the applicable default rate and all outstanding obligations under the company’s credit facility.

               The arrangement agreement contains certain termination rights for both the company and Magnum Hunter, including a termination right for either party if the arrangement is not consummated by March 31, 2011 or any extension of the forbearance deadline by the credit facility lenders to not later than April 15, 2011. In addition, upon termination of the arrangement agreement under specified circumstances, the company will owe Magnum Hunter a cash termination fee of $4 million or reimbursement of its expenses not to exceed $4 million if our shareholders do not approve the arrangement. There is no assurance that the arrangement will be consummated. Whether or not the arrangement is completed, we have incurred and will continue to incur legal, financial advisor and other costs relating to the sale process.

If the arrangement is consummated, there is no assurance that its anticipated benefits will be realized, which could adversely affect the value of Magnum Hunter common stock received by shareholders of the company.

               If the arrangement is completed, NGAS will become a wholly owned subsidiary of Magnum Hunter. The success of the arrangement will depend, in part, on Magnum Hunter’s ability to effectively integrate our business with its own operations and realize the anticipated benefits from combined operations. However, it is possible that Magnum Hunter will not be able to achieve these benefits fully, or at all, or will not be able to achieve them within the anticipated timeframe. We have operated independently and will continue to do so until the completion of the arrangement, and there can be no assurance that our businesses can be integrated successfully. It is possible that the integration process could result in the disruption of each company’s ongoing businesses or inconsistencies in standards, controls, procedures and policies. Specific issues that must be addressed upon completion of the arrangement in order to realize the anticipated benefits include, among other things:

	•		integrating the companies’ oil and natural gas exploration and production operations;
	•		applying each company’s best practices to the combined oil and natural gas portfolio;
	•		combining the companies’ oil and natural gas processing, marketing and transportation operations;
	•		harmonizing the companies’ operating practices, employee development and compensation programs, internal controls and other policies, procedures and processes;
	•		integrating the companies’ corporate, administrative and information technology infrastructure; and
	•		managing any tax costs or inefficiencies associated with integration.

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

               As a result, our reserve estimates may differ materially from the quantities of natural gas and oil that are ultimately 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 and production costs. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be directly measured. 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 and production as well as changes in commodity prices and production costs after the date of our estimates may require future revisions of the estimates. In addition, 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 at the pace or levels assumed in our estimates.

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

               Our current proved developed reserves will decline as they are produced. Based on extensive historical production profiles for vertical wells in the Appalachian Basin and the limited production history for horizontal Devonian shale wells in the region, the blended decline rate for our proved developed reserves as of December 31, 2010 averaged 14.4% for 2011, decreasing hyberbolically to 5.5% in 2025. The actual performance of our wells could differ from these estimates, and EURs for our horizontal wells could vary even more materially from their estimated reserves in view of their limited production history. The depletion of our reserves, whether at anticipated rates or otherwise, will reduce cash flow from our wells and their value as collateral to support the development of our oil and gas properties and replacement of our existing reserves.

Production volumes from our properties will decline without ongoing drilling.

               Various field operating conditions may adversely affect production volumes from our existing wells. These conditions include potential delays in obtaining regulatory approvals and easements for connecting completed wells to 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.

The timing and costs of developing our oil and gas properties are uncertain and may differ materially from expectations.

               As of December 31, 2010, approximately 26% of our proved reserves were undeveloped, and 69% of our total acreage was undeveloped. Developing these properties will require significant capital expenditures for ongoing drilling operations, and we may not have the capital or financing we need for their development. The costs associated with developing these resources are also uncertain and may increase disproportionately with commodity prices over time. Any of these factors could cause our actual results from future development initiatives on unproved properties to vary significantly from the results anticipated in our business plan. Executing that plan 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 has increased in the Appalachian Basin over the last few years in reported success in regional shale plays, notably 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. Continued market disruptions may cause delays in drilling operations and the possibility of poor results.

Volatility in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

               The prices we receive for oil and natural gas production heavily influence our revenue, profitability and access to capital. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been extremely volatile. These markets

will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

	•		the extent of domestic natural gas production, which has increased 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 and conservation programs, including possible climate-related measures for regulating greenhouse gas emissions.

               Natural gas accounted for 69% of our total production revenues in 2010 and 75% of our proved reserves at year-end. Lower natural gas prices not only decrease our revenues on a per unit basis but may also reduce the amount of natural gas that we can produce economically. Our estimated proved reserves as of December 31, 2010 reflect negative revisions of approximately ___ Bcfe from the prior year-end estimates as a result of commodity price declines. In addition, our 2010 year-end estimates include proved undeveloped locations that would generate positive future net revenue, based on the constant prices and costs determined under the current reserve rules, but would have negative present value when discounted at 10% per year under the standardized measure. Continued weakness 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 commodity 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 could reflect our long-term ability to recover an investment based on prevailing conditions and would impact our reported earnings and leverage ratios.

Our operations involve hazards and exposure to liabilities that might 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. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties. See “Business and Properties – Regulation.” While we conduct our operations to comply with applicable environmental regulations, permits and lease conditions, including maintenance of insurance against these risks, we remain exposed to liabilities 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. As a result, the operating hazards associated with our development and production activities may result in substantial liabilities, some of which may not be fully covered by our insurance.

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, or the perception that substantial sales may occur, could adversely affect prevailing market prices of the common stock. There were 70,953,689 shares of our common stock issued and outstanding at February 28, 2010. As of that date, we also had $12.4 million of convertible notes outstanding, reflecting monthly note amortization installments paid in common stock through November 2010 and subsequent note conversions at an average reset price $0.37 following the cross default on the convertible notes. Subsequent conversions are subject to our compliance with the forbearance agreements we entered with the note holders in December 2010. See “MD&A – Liquidity and Capital Resources.”

We plan to transfer the listing for our common stock to the Nasdaq Capital Market on March 28, 2011 based on our failure to regain compliance with the $1.00 minimum bid price requirement for continued listing on the Nasdaq Global Select Market, which may adversely affect the market price and liquidity of our common stock.

               Since September 2010, we have been out of compliance with the $1.00 minimum bid price requirement for our common stock on the Nasdaq Global Select Market, and the grace period for regaining compliance will end on March 28, 2011. An additional 180-day period will be available to regain compliance if we transfer the listing for our common stock to the Nasdaq Capital Market and meet all other listing requirements. We intend to apply for the listing transfer, which may adversely affect the market price and liquidity of our common stock.

Item 1B   Unresolved Staff Comments

               None.

Item 2      Properties

               See “Business and Properties.”

Item 3      Legal Proceedings

General

                 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.

Litigation Relating to the Arrangement

               On January 12, 2011, a putative class action captioned David Matranga and Bill Hubbard v. NGAS Resources, Inc. et al., Case No. 11-C1-250, was filed in the Fayette Circuit Court, Division 9, in the Commonwealth of Kentucky. The defendants are NGAS and the members of the NGAS board of directors (NGAS defendants), and Magnum Hunter. The complaint alleges that the individual defendants violated British Columbia law by breaching their fiduciary duties and other obligations to the company’s shareholders in connection with the arrangement agreement and the transactions contemplated thereby. Specifically, the complaint alleges, among other things, that the proposed transaction arises out of a flawed process in which the individual defendants engaged in self-dealing and agreed to certain provisions in the arrangement agreement, which resulted in an unfair price for NGAS shares and a failure to maximize shareholder value. The suit further alleges that NGAS and Magnum Hunter aided and abetted the individual defendants’ breaches of fiduciary duties. The plaintiffs seek, among other things, an order enjoining the NGAS defendants and Magnum Hunter from consummating the arrangement, rescission of the arrangement agreement, and attorneys’ fees and costs. On February 2, 2011, defendants filed motions to dismiss the plaintiffs’ complaint. On February 15, 2011, plaintiffs filed an amended complaint, reiterating the allegations in their original pleading and adding allegations challenging the sufficiency of the disclosures in NGAS Resources’ preliminary proxy statement. On February 18, 2011, defendants filed motions to dismiss plaintiffs’ amended complaint. On the same date, plaintiffs filed a motion for limited expedited discovery.

     While the company believes that plaintiffs’ claims are without merit and that it and the other defendants named in the lawsuit have valid defenses to all claims, in an effort to minimize the burden and expense of further litigation relating to such complaints, on March 1, 2011 the defendants reached an agreement in principle with the plaintiffs to settle the litigation and resolve all allegations by the plaintiffs against the defendants in connection with the arrangement. The settlement, which is subject to further definitive documentation and court approval, provides for a settlement and release by the purported class of NGAS shareholders of all claims against the defendants in connection with the arrangement. In exchange for such settlement and release, the parties agreed, after arm’s length discussions between and among the defendants and the plaintiffs, that the company would provide certain additional disclosures to those in its preliminary proxy statement relating to the arrangement agreement, although the company does not make any admission that such additional disclosures are material or otherwise required. After reaching agreement on the substantive terms of the settlement, the parties also agreed that plaintiffs may apply to the court for an award of attorneys’ fees and reimbursement of expenses, which, under certain circumstances, defendants have agreed not to oppose. In the event the settlement is not approved by the court or the conditions to settlement are not satisfied, the defendants will continue to vigorously defend these actions.

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 2010.

Part II

Item 5      Market for Common Stock and Related Security Holder Matters

Trading Market

               Since September 2010, we have been out of compliance with the $1.00 minimum bid price requirement for our common stock on the Nasdaq Global Select Market, and the grace period for regaining compliance will end on March 28, 2011. If the pending sale of the company is not completed by that date, we expect to move the listing for our common stock to Nasdaq Capital Market. 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
	2009			First quarter		$	2.26			$	0.77				202,114
				Second quarter			3.00				1.18				280,423
				Third quarter			2.62				1.46				428,316
				Fourth quarter			2.40				1.60				268,019
	2010			First quarter		$	2.14			$	1.35				343,445
				Second quarter			1.75				1.03				433,994
				Third quarter			1.16				0.79				287,396
				Fourth quarter			0.88				0.35				1,384,085
	2011			First quarter (through February 28th)		$	0.67			$	0.51				1,172,729

Security Holders

               As of February 4, 2010, there were 609 holders of record of our common stock. We estimate there were approximately 10,500 beneficial owners of our common stock as of that date.

Dividend Policy

               We have never paid cash dividends on our common stock. 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, 2010 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.

Shares Issuable

Weighted Average

Shares Remaining

Upon Exercise of

Exercise Price of

Available for Future

Outstanding

Outstanding

Issuance under Equity

Options and Warrants

Options, Warrants

Compensation Plans

Plan Category

and Rights (a)

and Rights (b)

(excluding [a] and [b])

Plans approved by shareholders

2,245,000

$ 2.93

2,149,141

Plans not approved by shareholders

4,609,038

1.80

—

Total

6,854,038

$ 2.17

2,149,141

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.

		2005				2006				2007				2008				2009					2010
NGAS		$	100			$	60.8			$	53.7			$	15.6			$	16.2				$	5.3
Dow Jones US E&P			100				105.4				151.4				90.7				127.4					152.3
S&P 500			100				115.8				122.2				77.0				97.3					112.0

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. The following table presents our summary selected consolidated financial data as of and for each of the five years ended December 31, 2010. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP. The summary selected consolidated financial data as of December 31, 2010 and 2009 and for the three years ended December 31, 2010 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.

(In thousands, except per share data)

		Year Ended December 31,
Statement of Operations Data:		2010				2009				2008				2007				2006
Total revenues		$	50,820			$	57,824			$	84,407			$	70,203			$	79,820
Direct expenses			33,180				32,702				43,981				39,044				49,361
Net income (loss)			(19,493	)			(7,701	)			2,936				(817	)			1,992
Net income (loss) per common share (basic)			(0.50	)			(0.27	)			0.11				(0.04	)			0.09
Weighted average common shares outstanding			39,318				28,256				26,409				22,240				21,511
		As of December 31,
Balance Sheet Data:		2010				2009				2008				2007				2006
Current assets			19,805			$	18,567			$	12,052			$	11,240			$	24,656
Current liabilities			67,613				44,642				17,571				12,381				25,484
Working capital (deficit)			(47,808	)			(26,075	)			(5,519	)			(1,141	)			(828	)
Total assets			204,920				214,616				247,354				204,801				178,219
Total liabilities			88,311				102,765				143,477				104,892				101,862
Shareholders’ equity			116,609				111,851				103,877				99,909				76,357

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

General

               The following discussion presents management’s analysis of events, factors and trends with an important effect or prospective impact on our financial condition and results of operations. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Note” at the beginning of this report and “Risk Factors” in Item 1.A for additional discussion of these factors and risks.

Overview

               We are an independent exploration and production company focused on natural gas shale plays in in the eastern United States, principally in the southern Appalachian Basin. We began oil and gas operations in 1993 with the acquisition of our wholly owned subsidiary, NGAS Production Co., which was formerly named Daugherty Petroleum, Inc. Our consolidated financial statements include the accounts of NGAS Production and its subsidiaries and interests in managed drilling partnerships. We account for our drilling partnership interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation.

Going Concern

               Debt Covenant Defaults. On November 9, 2010, we reported that we were not in compliance with the leverage coverage covenant under our credit agreement as of end of the third quarter, which also triggered a cross default on the convertible notes. Our third quarter report also disclosed our prior engagement of a financial advisor to assist us pursue strategic alternatives. At that time, we had $35.8 million of credit facility debt and $21.5 million of outstanding convertible notes. We subsequently obtained limited forbearance from the covenant defaults, conditioned on completing a qualifying transaction that results in the repayment of the credit facility in full and all outstanding convertible notes at a default rate by March 31, 2011 or any extension by the credit facility lenders.

               Pending Sale of the Company. On December 23, 2010, we entered into a definitive agreement with Magnum Hunter for the acquisition of the company by Magnum Hunter in an all-stock transaction to be implemented as an arrangement under British Columbia law, where we are organized at the parent company level. Under the terms of the arrangement agreement, each common share of NGAS will be transferred to Magnum Hunter for the right to receive 0.0846 of a share of Magnum Hunter common stock. The consummation of the arrangement is subject to various conditions, including approval of the arrangement by the company’s shareholders, receipt of Canadian court approval, repayment of the company’s senior and convertible debt by Magnum Hunter and restructuring of the company’s gas gathering agreements. The transactions contemplated by the arrangement agreement are scheduled to close on or about March 31, 2011, although there is no assurance that the acquisition will ultimately be consummated or that our lenders and note holders would continue to forbear on pursuing their legal remedies in that event. See “Risk Factors.”

Results of Operations – 2010 and 2009

               Revenues. The following table shows the components of our revenues for 2010 and 2009, together with their percentages of total revenue in 2009 and percentage change on a year-over-year basis.

		Year Ended December 31,
						% of								%
Revenue:		2010				Revenue				2009				Change
Contract drilling		$	24,177,751				48	%		$	24,279,345				—	%
Oil and gas production			23,010,779				45				26,586,422				(13	)
Gas transmission, compression and processing			3,631,587				7				6,957,906				(48	)
Total		$	50,820,117				100	%		$	57,823,673				(12	)

               Total revenues for 2010 reflect the impact of reduced drilling activity, low gas prices and third-party ownership of the Appalachian gathering system, which eliminated both our revenues and cost savings from these facilities following their sale during the third quarter of 2009. Without access to capital to ramp up the development of our properties, the decline in our revenues could be expected to accelerate on a stand-alone basis.

               Contract drilling revenues are driven by the size and timing of our drilling partnership initiatives. We generally receive the proceeds from private placements by sponsored partnerships as prepayments under our drilling contracts and recognize contract drilling revenues as the wells are drilled. Contract drilling revenues for 2010 reflect the 80% share of outside investors in the last four wells drilled with our 2009 partnership and the 25 wells drilled with our 2010 drilling partnership, which raised $23.1 million from a private placement completed at year-end. Our fourth quarterly contract drilling revenues reflect reimbursements for the 2010 partnership’s share of drilling and completion costs for several wells drilled in advance of partnership funding, together with funding for its participation in the balance of its wells.

               Production revenues for 2010 reflect lower natural gas prices as well as reduced drilling activity during prior periods, which contributed to a 16% decrease in production output to 3,334 Mmcfe, compared to 3,978 Mmcfe in 2009. Weighted average prices for our natural gas sales in 2010 were $6.27 per Mcf for our Appalachian production and $5.81 per Mcf overall, compared to $7.24 and $6.17 per Mcf, respectively, in 2009. Approximately half of our natural gas production in 2010 was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.

               The contraction of gas transmission, compression and processing revenues was driven by our sale of the Appalachian gathering system in the third quarter of 2009. Following the sale, this revenue base has been limited primarily to gas utility sales, monthly operating fees from managed partnerships, third-party fees from our interest in the Rogersville processing plant, which we continue to co-own with Seminole Energy, and fees for operating the Appalachian gathering system. See “Business and Properties – Gas Gathering and Processing.”

               Expenses. The following table shows the components of our direct and other expenses for 2010 and 2009. 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:		2010				Margin				2009				Margin
Contract drilling		$	17,923,113				26	%		$	18,185,340				25	%
Oil and gas production			14,675,547				36				11,357,397				57
Gas transmission, compression and processing			581,499				84				3,159,331				55
Total direct expenses			33,180,159				35				32,702,068				43
Other Expenses:						% Revenue								% Revenue
Selling, general and administrative			12,073,792				24	%			11,658,541				20	%
Options, warrants and deferred compensation			675,113				1				1,307,194				2
Depreciation, depletion and amortization			13,280,961				26				14,019,826				24
Bad debt expense			246,570				—				—				N/A
Interest expense, net of interest income			6,271,078				12				8,694,256				15
Loss (gain) on sale of assets			219,879				—				(3,346,491	)			N/A
Fair value loss (gain) on derivative financial instruments			4,394,953				9				(14,726	)			N/A
Refinancing costs			625,344				1				—				N/A
Loss on carrying value of convertible debt			2,356,024				5				—				N/A
Impairment of goodwill			313,177				1				—				N/A
Other, net			(298,955	)		N/A					845,560				1
Total other expenses		$	40,157,936							$	33,164,160

               Contract drilling expenses reflect the level and timing of drilling initiatives conducted with participation by our sponsored drilling partnerships. These expenses represented 74% of contract drilling revenues in 2010, compared to 75% in 2009. 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, as well as improved efficiencies from ongoing refinements in our horizontal drilling and completion techniques.

               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 period-over-period basis primarily reflects higher transportation costs following our sale of the Appalachian gathering system during the third quarter last year. Our ownership of the facilities in prior periods had eliminated all transportation costs for 90% of our Appalachian production.

               Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, have been substantially reduced from our sale of the Appalachian gathering system. Our remaining infrastructure position consists of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties.

               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 2010 increased by 4% year-over-year, primarily from legal, financial advisor and other costs in connection with the pending sale of the company. As a percentage of revenues, SG&A increased to 24% in 2010 from 20% in 2009.

               Non-cash charges for options, warrants and deferred compensation primarily reflect amounts recognized for employee stock options granted in prior periods. Employee stock options are valued under the fair value method of accounting at the grant date using the Black-Scholes model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $334,430 for deferred compensation cost in 2010 and $614,548 in 2009.

               The decrease in depreciation, depletion and amortization (DD&A) charges reflects a reduction in historical depletion costs following our sale of the Appalachian gathering system, partially offset by additions to our oil and gas properties. DD&A is recognized under the units-of-production method for oil and gas properties and on a straight-line basis over the useful life of other property and equipment.

               We recognized bad debt expenses of $246,570 in 2010 as write-offs or reserves against loans receivable from affiliates. See “Related Party Transactions.” and “Critical Accounting Policies and Estimates – Allowance for Doubtful Accounts.” We also recognized refinancing costs of $625,344 for our convertible note restructuring. See “Liquidity and Capital Resources.”

               Cash interest expense in 2010 was $4,226,607, down 18% from 2009. This resulted primarily from lower convertible debt levels following our note restructuring in January 2010 and a reduction of $48.8 million in credit facility debt from our monetization of the Appalachian gathering system and separate equity raises in August 2009 and May 2010. See “Liquidity and Capital Resources.” We recognized non-cash interest expense of $2,866,394 in 2010 for accretion of the debt discount on the convertible notes under the effective interest method.

               We recognized a fair value loss on derivative financial instruments of $4,394,953 at December 31, 2010, reflecting changes in fair values of the embedded conversion features of the notes and warrants issued in the exchange transaction. We also recognized an impairment charge of $2,356,024 on the carrying value of convertible debt to reflect the cross default. See “Liquidity and Capital Resources.”

               Net Loss and EPS. We recognized net losses of $19,493,227 in 2010 and $7,701,161 in 2009, reflecting the foregoing factors. Basic and diluted EPS was $(0.50) on 39,318,038 weighted average common shares outstanding in 2010, compared to $(0.27) on 28,256,253 weighted average common shares outstanding in 2009.

Results of Operations – 2009 and 2008

               Revenues. The following table shows the components of our revenues for 2009 and 2008, together with their percentages of total revenue in 2009 and percentage change on a year-over-year basis.

		Year Ended December 31,
						% of								%
Revenue:		2009				Revenue				2008				Change
Contract drilling		$	24,279,345				42	%		$	35,553,956				(32	)%
Oil and gas production			26,586,422				46				38,522,474				(31	)
Gas transmission, compression and processing			6,957,906				12				10,330,234				(33	)
Total		$	57,823,673				100	%		$	84,406,664				(31	)

               Our contract drilling revenues in 2009 reflect the challenging economic environment, which contributed to a 44% reduction in the size of our 2009 drilling partnership compared to the prior year’s program. With a raise of $19.3 million, the 2009 partnership participated in 22 horizontal wells, of which four wells were drilled during the 2010 first quarter.

               Production revenues for 2009 reflect year-over-year declines of 31% in natural gas prices, 45% in oil prices and 48% for sales of natural gas liquids. The impact of weak commodity prices was partially offset by an increase of 6% in production output to 3,978 Mmcfe, compared to 3,745 Mmcfe in the prior year. Our volumetric growth reflects our transition to horizontal drilling throughout our operated properties in 2009. During the year, approximately 55% of our natural gas production was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2009 averaged $7.24 per Mcf for our Appalachian production and $6.17 per Mcf overall, compared to an average overall realization of $8.89 per Mcf in 2008.

               The contraction of gas transmission, compression and processing revenues was driven by our sale of the Appalachian gathering system in the third quarter of 2009. Following the sale, our gas transmission, compression and processing revenues were limited primarily to fees for moving third-party production through our retained gas gathering facilities, gas utility sales and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.

               Expenses. The following table shows the components of our direct and other expenses for 2009 and 2008. 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:		2009				Margin				2008				Margin
Contract drilling		$	18,185,340				25	%		$	27,272,756				23	%
Oil and gas production			11,357,397				57				12,600,897				67
Gas transmission, compression and processing			3,159,331				55				4,107,763				60
Total direct expenses			32,702,068				43	%			43,981,416				48	%
Other Expenses:						% Revenue								% Revenue
Selling, general and administrative			11,658,541				20	%			14,005,041				17	%
Options, warrants and deferred compensation			1,307,194				2				911,561				1
Depreciation, depletion and amortization			14,019,826				24				12,418,234				15
Bad debt expense			—			N/A					749,035				1
Interest expense, net of interest income			8,694,256				15				5,479,233				6
Gain on sale of assets			(3,346,491	)		N/A					(14,104	)		N/A
Fair value gain on derivative financial instruments			(14,726	)		N/A					—			N/A
Other, net			845,560				1				139,176				—
Total other expenses		$	33,164,160							$	33,688,176

               Contract drilling expenses represented 75% of contract drilling revenues in 2009, compared to 77% in the prior year. 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 year-over-year primarily reflects higher transportation costs following our sale of the Appalachian gathering system in the third quarter of 2009.

               Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, were substantially reduced following our sale of the Appalachian gathering system. Our remaining infrastructure position is comprised of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses in future periods will reflect this redution in our infrastructure asset base.

               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 decreased by 17% year-over-year, primarily from the decline in 2009 partnership sales. As a percentage of revenues, SG&A expenses increased from 17% in 2008 to 20% in 2009.

               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 $614,548 for deferred compensation cost in 2009.

               The 13% increase in DD&A charges reflects additions to our oil and gas properties from drilling initiatives, partially offset by a reduction in historical depletion costs for the Appalachian gathering system following its sale in the third quarter of 2009.

               Cash interest expense in 2009 decreased 8% year-over-year, reflecting the reduction of debt levels under our revolving credit facility from proceeds of our infrastructure monetization and equity raise in the third quarter of 2009. Non-cash interest expense of $3,925,531 reflects the application of the effective interest method for accretion of the debt discount for the embedded conversion feature of our 6% notes, which had a face amount of $37 million prior to the restructuring of our convertible debt in January 2010. The carrying amount of the exchange notes issued in the restructuring will be reduced by the initial fair values of the equity components of the exchange transaction. The resulting debt discount will be amortized to interest expense though the conversion or repayment dates of exchange notes and the expiration or exercise dates of the warrants.

               We recognized pre-tax gains totaling $3,346,491 during 2009, primarily from our sale of the Appalachian gathering system. We acquired the open-access portion of the system from Duke Energy in March 2006 for $18 million and built out the field-wide infrastructure at historical costs totaling approximately $33.5 million.

               Deferred income tax expense recognized in both reporting periods represents future tax liabilities at the operating company level. Although we generally have no current tax liability at that level due to the utilization of deductions primarily for intangible drilling costs and percentage depletion, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level. For 2009, we had an income tax benefit of $341,394 from our operating loss.

               Other expenses in 2009 totaled $845,560, net of minor income items. The recorded expenses include payments and accruals totaling $642,000 for various guaranteed obligations of a Virginia steam company in which we previously held a 50% interest. We have also accrued $350,000 for the unreimbursed part of a personal injury litigation settlement reached in March 2010, which we will seek to recoup under our umbrella liability insurance coverage.

               Net Income (Loss) and EPS. We recognized a net loss of $7,701,161 in 2009, reflecting the foregoing factors. Earnings (loss) per share (EPS) was $(0.27) on 28,256,253 weighted average common shares outstanding, compared to net income of $2,936,275 realized in 2008, with EPS of $0.11 on 26,910,642 fully diluted shares.

Liquidity and Capital Resources

               Liquidity. Net cash of $3,424,648 was provided by operating activities in 2010. During the year, we used net cash of $3,254,565 in investing activities, which included approximately $4.3 million of capital expenditures for developing our oil and gas properties. Net cash of $2,341,742 provided by financing activities in 2010 primarily reflects proceeds of approximately $4.7 million from a second quarter equity raise, part of which was applied to debt reduction under our credit facility, and proceeds of an installment loan that was used to fund part of our office building acquisition. See “Related Party Transactions.” As a result of these activities and related cash management, our net cash increased from $4,332,650 at December 31, 2009 to $6,844,475 at December 31, 2010.

               During 2009, we generated net cash of $6,180,241 from operating activities and $22,755,628 from investing activities, which included our proceeds from the Appalachian gathering system sale, all of which were applied to debt reduction under our revolving credit facility. Our investing activities also included capital expenditures aggregating $14,776,307, of which $11,914,566 was recorded as net additions to oil and gas properties. As a result of these activities, net cash increased to $4,332,650 at December 31, 2009 from $981,899 at the prior year-end.

               We had a working capital deficit of $47,807,944 at December 31, 2010, primarily reflecting our obligations as of year-end under our credit agreement and convertible notes, which will be repayable on March 31, 2011 or any extension of the forbearance agreements we obtained following the our announcement of a third-quarter covenant default under the credit agreement. Our consolidated financial statements for the year ended December 31, 2010 have been prepared on a going concern basis. Based on the factors described below, our ability to continue as a going concern would be subject to substantial doubt if we were unable to consummate our pending sale transaction.

               Capital Resources. Our business involves significant capital requirements. Historically, we have relied on a combination of cash flows from operations, bank borrowings and sales of our common stock, warrants and convertible debt to fund our reserve and infrastructure development and acquisition activities. We have also relied to varying degrees on participation by outside investors in sponsored drilling partnerships. During the last two years, we have addressed the challenging market conditions in our industry by reducing capital expenditures and returning to our successful partnership model for sharing development costs and returns on operated properties. We also completed initiatives to deleverage and rationalize our capital structure by monetizing gas gathering assets and restructuring our convertible debt.

               During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering facilities to Seminole Energy for $50 million, of which $14.5 million is payable in monthly installments through December 2011 under a secured promissory note (Seminole note) with interest at 8% per annum. Cash proceeds of $35.5 million from the asset sale and approximately $6.1 million from a contemporaneous equity raise were applied to debt reduction under our revolving credit facility. We assigned the Seminole note as part of the collateral package under our revolving credit facility and agreed to apply note installments payments to debt reduction under the facility.

               Our drilling partnerships raised $23.1 million in 2010 and $19.3 million in 2009 for participation in a total of 47 horizontal wells on our operated properties. We contributed proportionately for a 20% interest before payout in each of these annual programs. While our partnership model and several joint venture arrangements with industry partners enabled us to meet our annual drilling commitments with $12 million of capital expenditures in 2009, this reflected a 75% reduction from our 2008 drilling budget. As a result of further reductions in drilling activity during 2010, our Leatherwood farmout was terminated in year-end on a block of 23,872 undeveloped acres for failure to satisfy part of the 25-well drilling commitment for the year.

               On January 12, 2010, we issued $28.7 million principal amount of 6% amortizing convertible notes due May 1, 2012, together with a combination of common stock, warrants and cash payments of approximately $2.7 million, in exchange for entire $37 million outstanding principal amount of our 2005 notes, which were maturing before year-end. The exchanged convertible notes bear interest at 6% per annum, payable quarterly in cash, and are convertible at $2.18 per common share, subject to certain volume limitations and adjustments for certain corporate events. We are required to make equal monthly principal amortization payments on the convertible notes during the last 24 months of their term. Subject to certain conditions and true-up adjustments, we may elect to pay all or part of any principal installment in our common shares, valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the common stock prior to the installment date. We elected to pay all of the monthly amortization installments though November 1, 2010 in common shares.

               Upon an event of default, the convertible notes are redeemable at the option of the holders in cash at a default rate equal to 125% of the sum of their principal amount plus accrued and unpaid interest at a 12% default rate and late fees. Alternatively, under the terms of the convertible notes, each holder also has the right to rescind a redemption call on any portion of its notes and instead require the conversion price for the rescission amount to be reset to the lowest closing bid price of our common stock from the date of the holder’s redemption notice to the date of the rescission notice.

               Our credit facility is maintained by NGAS Production under an amended and restated credit agreement with KeyBank National Association, as agent and primary lender. The credit agreement provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, subject to borrowing base thresholds determined semi-annually by the lenders, with a scheduled maturity in September 2011. Outstanding borrowings under the facility bear interest at rates ranging up to 2.25% above that rate, depending on the amount of borrowing base utilization. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties.

               The credit agreement was amended in January 2010 in connection with the restructuring of our 2005 notes described below. The amendment permitted us to complete the note restructuring, subject to restrictions on upstream dividends for any principal amortization payments on the new 6% amortizing convertible notes and to monthly borrowing base reductions of $1 million until the next redetermination. The borrowing base was redetermined at $37 million as of June 30, 2010 and was fully utilized through the end of the third quarter. Our financial covenants under the credit facility are measured as the end of each quarter, and our leverage coverage ratio limits NGAS Production’s funded indebtedness to not more than 4.75 times its consolidated earnings for the trailing twelve-month period before net interest expense, income tax expense and depreciation, depletion and amortization. We were not in compliance with the covenant as of September 30, 2010.

               On November 9, 2010, we filed our third quarter report on Form 10-Q, disclosing our failure to comply with the leverage coverage ratio, our ongoing forbearance negotiations with the lenders and our inability to repay our credit facility or redeem our convertible notes under their cross default provisions in the absence of a waiver or forbearance. We also reported the our prior engagement of a financial advisor to assist us pursue strategic alternatives that would enable us to retire or replace the credit facility (qualifying transaction) and could include the sale of assets, merger or other type of strategic transaction.

               On November 19, 2010, we entered into a limited waiver and amendment to the credit agreement (credit agreement amendment). As of that date, we had $35.8 million drawn under the facility. The credit agreement amendment provided for the termination of all lending commitments, the reduction of credit facility debt by monthly installments of $588,603 under the Seminole note, an increase in the interest rate and a reduction in the term of the facility from the scheduled maturity in September 2011 to March 31, 2011 (repayment date). Subject to specified conditions, the credit agreement amendment provides for the lenders’ forbearance from exercising default remedies based on the company’s noncompliance with the leverage coverage covenant and the related cross default on the convertible notes from the date of the credit agreement amendment until the repayment date. The forbearance conditions included the company’s entry into a definitive agreement for a qualifying transaction by December 15, 2010, which was subsequently extended to December 23, 2010, and the payment of all obligations under the credit agreement by the March 31^st payment date. As of December 31, 2010, the credit facility had an outstanding balance of $35.5 million.

               Following our announcement of the covenant default under our credit agreement, we received a redemption notice based on the resulting cross default from the largest holder of the convertible notes, and we entered into negotiations for a waiver or forbearance from the holder. We subsequently received redemption notices from the other holders, as well as rescission notices for conversion of $1.2 million principal amount of convertible notes at an average reset price of $0.37 per share.

               On December 14, 2010, we entered into separate agreements (note agreements) with the holders of our convertible notes to facilitate our sale process by clarifying the impact of the cross default on our capital structure. Subject to various conditions, the note agreements limit the holders’ conversion rights to an aggregate of 32 million shares of our common stock, net of previous conversions, between the date of the note agreements and the fifth trading day prior to any shareholder vote on a qualifying transaction (conversion period). The holders also agreed not to convert any notes after the conversion period. The note agreements are conditioned on our meeting the deadline in the credit agreement amendment for consummating a qualifying transaction, including any extensions of the original deadline by the credit facility lenders to not later than April 15, 2011. For purposes of the note agreements, a qualifying transaction must provide for a purchase price at least 10% above the reset conversion price on the date of the note agreements and must result in the complete repayment of all outstanding convertible notes at a default rate equal to 125% of the sum of their unconverted principal amount plus default interest and late fees. We had outstanding convertible notes in principal amounts of $16.5 million as of December 31, 2010 and $12.4 million as of the date of this report.

               The transactions contemplated by the arrangement agreement are scheduled to close on or about March 31, 2011. In addition to approval of the arrangement by the company’s shareholders and receipt of Canadian court approval, the consummation of the arrangement is conditioned on a restructuring of the Seminole agreements on substantially the terms set forth in a letter of intent we entered with Seminole and Magnum Hunter, including the payment of $10 million in cash or Magnum Hunter restricted stock and the cancellation of approximately $4.6 million in remaining installments under the Seminole note.

               In accordance with the arrangement agreement, we have requested an extension of the repayment date under the credit agreement amendment to April 15, 2011. Although we are in compliance with the forbearance conditions under the credit agreement amendment as of the date of this report, there is no assurance that the payment deadline will be extended or that the arrangement will be consummated. If we are unable to complete the arrangement or other qualifying transaction for repayment of our senior and convertible debt by the payment deadline or any extension granted by the lenders, we could be forced into bankruptcy if the lenders or note holders choose to pursue their legal remedies. If the arrangement is completed, NGAS will become a wholly owned subsidiary of Magnum Hunter.

Financial Market Risk

               Interest Rate Risk. Borrowings under our secured credit facility bear interest at fluctuating market-based rates. Accordingly, we are exposed to interest rate risk on current and future indebtedness under the facility.

               Foreign Market Risk. We conduct operations solely in the United States. 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

               General. Our contractual obligations include long-term debt, operating leases, drilling commitments, transportation commitments, asset retirement obligations and leases for office facilities and various types of equipment. The following summarizes our contractual financial obligations at December 31, 2010 and their future maturities. The table does not include commitments under our gas gathering and sales agreements described below.

		Operating				Long-Term
Year		Leases				Debt(1)
2011		$	215,760			$	53,298,857
2012			122,815				1,670,089
2013			56,125				182,462
2014			25,567				190,363
2015 and thereafter			6,392				3,910,345
Total		$	426,659			$	59,252,116

               Gas Gathering and Sales Commitments. We have various commitments under our gas gathering and sales agreements entered with Seminole Energy in connection with our sale of the Appalachian gathering system during the third quarter of 2009. Our commitments under the Seminole agreements include fixed monthly gathering fees of $862,750, monthly operating fees of $182,612, plus $0.20 per Mcf of purchased gas, and capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the system by Seminole Energy. The gas gathering and compression fees reflect our firm capacity commitment for 30,000 Mcf/d and are subject to periodic increases based on operating costs and other contractual adjustments. See “Business and Properties – Gas Gathering and Processing.”

Related Party Transactions

               General. Because we operate through subsidiaries and managed drilling partnerships, various agreements and transactions in the normal course of business may be treated as related party transactions. Our policy is to structure any transactions with related parties only on terms that are no less favorable to the company than we could obtain on an arm’s length basis from unrelated parties. Significant related party transactions are summarized below and in Notes 8 and 15 to the consolidated financial statements included in this report.

               Purchase of Office Building. 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 executive officers and a key employee. We occupy 13,852 square feet under lease renewals entered in November 2007 for a five-year term at monthly rents initially totaling $20,398, subject to annual escalations on the same terms as our prior lease. In February 2010, NGAS Production purchased the building for $5.6 million, of which $4.48 million was funded from proceeds of a five-year installment loan secured by a mortgage on the property, as described in Note 10 to the consolidated financial statements included in this report. The terms of the transaction were negotiated on our behalf by one of our independent directors appointed for that purpose by our board. The negotiations were conducted at arm’s length with the management company for the building, and our purchase price was approximately the same as the sale price for the building in 2006. The fairness of the consideration was supported by an independent appraisal based on recent sales of comparable office buildings in our locale.

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 our financial reporting are summarized in Note 1 to the consolidated financial statements included in this report. Policies involving the most significant judgments and estimates 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 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, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable.

               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.

Off-Balance Sheet Arrangements

               We do not have any off-balance sheet debt or other unrecorded obligations with unconsolidated entities to enhance our liquidity, provide capital resources or for any other purpose.