- Quarterly Report (10-Q)

United States Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-Q


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

For the Quarter Ended September 30, 2010


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

Commission File No. 0-12185

NGAS Resources, Inc.

(Exact name of registrant as specified in its charter)


Province of British Columbia (State or other jurisdiction of incorporation)		Not Applicable (I.R.S. Employer Identification No.)

120 Prosperous Place, Suite 201 Lexington, Kentucky (Address of principal executive offices)		40509-1844 (Zip Code)

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

Indicate by check mark if the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months and (2) has been subject to those filing requirements for the past 90 days. Yes þ No o

Indicate by check mark 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 o No þ

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 þ	Non-accelerated filer o	Smaller Reporting Company o
		(Do not check if a smaller reporting company)

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

As of November 3, 2010, there were 46,416,385 shares of the registrant’s common stock outstanding.

NGAS Resources, Inc.
120 Prosperous Place, Suite 201
Lexington, Kentucky 40509

Form 10-Q — September 30, 2010

Table of Contents


	Page
Part I Financial Information

Item 1 Financial Statements:

Condensed Consolidated Balance Sheets — September 30, 2010 (unaudited) and December 31, 2009		1

Condensed Consolidated Statement of Operations — Three months ended September 30, 2010 and 2009		2

Condensed Consolidated Statement of Cash Flows — Three months ended September 30, 2010 and 2009		3

Notes to Condensed Consolidated Financial Statements		4

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3 Quantitative and Qualitative Disclosures About Market Risk		21

Item 4 Controls and Procedures		22

Part II Other Information

Item 1A Risk Factors		22

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds		22

Item 6 Exhibits		22
EX-31.1
EX-31.2
EX-32.1

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

NGAS Resources, Inc.

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash	$	5,105,017		$	4,332,650
Accounts receivable		5,535,965			7,277,311
Note receivable		6,632,906			6,247,880
Prepaid expenses and other current assets		697,614			633,884
Loans to related parties		75,141			75,679


Total current assets		18,046,643			18,567,404

Bonds and deposits		258,945			258,695
Note receivable		1,742,524			6,766,451
Oil and gas properties		175,109,611			182,189,679
Property and equipment		9,590,271			5,113,093
Loans to related parties		171,429			171,429
Deferred financing costs		837,908			1,235,705
Goodwill		313,177			313,177


Total assets	$	206,070,508		$	214,615,633


LIABILITIES
Current liabilities:
Accounts payable	$	3,016,509		$	5,587,290
Accrued liabilities		892,858			938,829
Long-term debt, current portion		49,892,193			32,534,084
Fair value of derivative financial instruments		52,306			111
Customer drilling deposits		2,511,856			5,581,877


Total current liabilities		56,365,722			44,642,191

Deferred compensation		1,112,198			651,287
Deferred income taxes		10,289,262			12,559,549
Long-term debt		15,256,975			40,949,836
Fair value of derivative financial instruments		146,668			—
Other long-term liabilities		4,292,132			3,962,254


Total liabilities		87,462,957			102,765,117


SHAREHOLDERS’ EQUITY
Capital stock
Authorized :
5,000,000 Preferred shares
100,000,000 Common shares
Issued :
42,530,766 Common shares (2009 — 30,484,361)		132,034,607			117,142,639
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital — options and warrants		4,735,629			4,467,246
To be issued :
9,185 Common shares		45,925			45,925


		136,792,531			121,632,180
Deficit		(18,184,980	)		(9,781,664	)


Total shareholders’ equity		118,607,551			111,850,516


Total liabilities and shareholders’ equity	$	206,070,508		$	214,615,633

See accompanying notes.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
REVENUE

Contract drilling	$	4,555,485		$	3,831,250		$	15,667,095		$	16,328,000
Oil and gas production		5,616,269			6,239,324			17,644,686			20,198,187
Gas transmission, compression and processing		784,750			1,123,921			2,835,327			6,528,132


Total revenue		10,956,504			11,194,495			36,147,108			43,054,319


DIRECT EXPENSES

Contract drilling		3,196,824			2,913,418			11,574,230			12,328,110
Oil and gas production		3,988,755			2,658,985			11,007,455			7,598,044
Gas transmission, compression and processing		91,902			960,879			512,452			2,955,204


Total direct expenses		7,277,481			6,533,282			23,094,137			22,881,358


OTHER EXPENSES (INCOME)

Selling, general and administrative		2,479,006			2,601,514			7,811,382			8,404,519
Options, warrants and deferred compensation		226,066			285,309			729,295			1,022,774
Depreciation, depletion and amortization		3,388,841			3,304,139			9,906,178			10,610,630
Interest expense		1,603,067			2,196,091			5,073,965			6,892,550
Interest income		(191,430	)		(52,698	)		(667,686	)		(67,708	)
Loss (gain) on sale of assets		209,206			(3,356,177	)		218,709			(3,369,082	)
Fair value loss (gain) on derivative financial instruments		(359,398	)		4,847			337,195			(4,477	)
Refinancing costs		—			—			625,344			—
Other, net		(91,228	)		292,073			(307,808	)		600,896


Total other expenses		7,264,130			5,275,098			23,726,574			24,090,102


LOSS BEFORE INCOME TAXES		(3,585,107	)		(613,885	)		(10,673,603	)		(3,917,141	)

INCOME TAX EXPENSE (BENEFIT)		(1,075,874	)		508,116			(2,270,287	)		571,357


NET LOSS	$	(2,509,233	)	$	(1,122,001	)	$	(8,403,316	)	$	(4,488,498	)


NET LOSS PER SHARE
Basic	$	(0.06	)	$	(0.04	)	$	(0.23	)	$	(0.16	)

Diluted	$	(0.06	)	$	(0.04	)	$	(0.23	)	$	(0.16	)


SHARES OUTSTANDING

Basic		41,044,918			28,873,105			36,709,848			27,508,925

Diluted		41,044,918			28,873,105			36,709,848			27,508,925

See accompanying notes.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
OPERATING ACTIVITIES
Net loss	$	(2,509,233	)	$	(1,122,001	)	$	(8,403,316	)	$	(4,488,498	)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Incentive bonus paid in common shares		80,002			68,001			80,002			426,251
Options, warrants and deferred compensation		226,066			285,309			729,295			1,022,774
Depreciation, depletion and amortization		3,388,841			3,304,139			9,906,178			10,610,630
Loss (gain) on sale of assets		209,206			(3,356,177	)		218,709			(3,369,082	)
Fair value loss (gain) loss on derivative financial instruments		(359,398	)		4,847			337,195			(4,477	)
Accretion of debt discount		640,674			1,004,682			2,093,135			2,869,276
Deferred income taxes (benefit)		(1,075,874	)		508,116			(2,270,287	)		571,357
Changes in assets and liabilities
Accounts receivable		37,767			311,360			1,741,346			5,077,373
Prepaid expenses and other current assets		(269,700	)		(353,376	)		(63,730	)		(328,971	)
Accounts payable		(868,681	)		(144,533	)		(2,570,781	)		(7,269,488	)
Accrued liabilities		(68,916	)		(46,040	)		(45,971	)		(56,024	)
Deferred compensation		—			(2,094,700	)		—			(2,209,700	)
Customers’ drilling deposits		279,941			1,923,271			(3,070,021	)		358,716
Other long-term liabilities		99,025			155,091			329,878			477,917

Net cash provided by (used in) operating activities		(190,280	)		444,989			(988,368	)		3,688,054


INVESTING ACTIVITIES

Proceeds from sale of assets		1,646,534			35,857,613			5,444,311			35,911,646
Purchase of property and equipment		(64,413	)		(195,261	)		(5,922,029	)		(2,683,061	)
Change in bonds and deposits		(250	)		5,000			(250	)		15,203
Change in oil and gas properties, net		(703,023	)		(3,841,799	)		(1,840,808	)		(7,918,894	)

Net cash provided by (used in) investing activities		878,848			31,825,553			(2,318,776	)		25,324,894


FINANCING ACTIVITIES

Decrease in loans to related parties		—			890			538			3,164
Proceeds from issuance of common shares		—			6,089,476			4,701,968			6,089,476
Payments of deferred financing costs		(2,499	)		(10,882	)		(166,773	)		(383,442	)
Proceeds from issuance of long-term debt		—			—			4,480,000			—
Payments of long-term debt		(65,494	)		(45,021,578	)		(4,936,222	)		(34,733,578	)

Net cash provided by (used in) financing activities		(67,993	)		(38,942,094	)		4,079,511			(29,024,380	)

Change in cash		620,575			(6,671,552	)		772,367			(11,432	)
Cash, beginning of period		4,484,442			7,642,019			4,332,650			981,899


Cash, end of period	$	5,105,017		$	970,467		$	5,105,017		$	970,467


SUPPLEMENTAL DISCLOSURE

Interest paid	$	997,811		$	1,204,354		$	2,608,802		$	4,026,548
Income taxes paid		—			—			—			—

See accompanying notes.

NGAS Resources, Inc.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies

General. The accompanying consolidated financial statements of NGAS Resources, Inc. ( NGAS ) have been prepared in accordance with accounting principles generally accepted in the United States of America ( GAAP ). Our accounting policies are described in Note 1 to the consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2009 ( annual report ). Our accounting policies and their method of application in the accompanying financial statements are consistent with those described in the annual report.

Basis of Consolidation. The consolidated financial statements include the accounts of our direct and indirect wholly owned subsidiaries, NGAS Production Co. ( NGAS Production ), Sentra Corporation ( Sentra ) and NGAS Securities, Inc. ( NGAS Securities ). NGAS Production (formerly named Daugherty Petroleum, Inc.) conducts all our oil and gas drilling, production and gas gathering operations. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky, and NGAS Securities provides marketing support services for private placement financings. The consolidated financial statements also reflect our interests in investment partnerships sponsored by NGAS Production to participate in many of our drilling initiatives. NGAS Production maintains a combined interest as both general partner and an investor in those partnerships ranging from 12.5% to 75%, with additional reversionary interests after certain distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References to we , our or us include NGAS, NGAS Production, its subsidiaries and interests in managed drilling partnerships.

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

Convertible Note Restructuring. In January 2010, we exchanged $37 million principal amount of our 6% convertible notes due December 15, 2010 ( 2005 notes ) for $28.7 million in new amortizing convertible notes due May 1, 2012 ( 2010 notes ), together with a combination of cash, common shares and warrants. See Note 7 — Deferred Financing Costs, Note 10 — Long-Term Debt and Note 11 — Capital Stock.

Subsequent Events. Except as described in Note 16, there were no events or transactions requiring recognition or disclosure as subsequent events in the accompanying consolidated financial statements or notes.

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

Note 2 — Recently Adopted Accounting Standards

Except as described in Note 2 to the consolidated financial statements in the annual report, there have been no recent accounting pronouncements that could have a significant impact or potential impact on our financial position, results of operations, cash flows or financial statement disclosures.

Note 3 — Oil and Gas Properties

The following table presents the capitalized costs and accumulated depreciation, depletion and amortization ( DD&A ) for our oil and gas properties, gathering facilities and well equipment as of September 30, 2010 and December 31, 2009.


	September 30,			December 31,
	2010			2009
Proved oil and gas properties	$	203,725,293		$	203,670,153
Unproved oil and gas properties		6,140,187			5,441,933
Gathering facilities and well equipment		16,154,695			15,411,788

		226,020,175			224,523,874
Accumulated DD&A		(50,910,564	)		(42,334,195	)

Net oil and gas properties and equipment	$	175,109,611		$	182,189,679

Note 4 — Other Property and Equipment

The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of September 30, 2010 and December 31, 2009. Capitalized costs for building and improvements at September 30, 2010 reflect our purchase of the building in Lexington, Kentucky that houses our principal and administrative offices for $5.6 million in February 2010. The building had been acquired for approximately the same amount during 2006 by a company formed for that purpose by our executive officers and a key employee. See Note 13 — Related Party Transactions. We obtained financing for part of the purchase price on the terms described in Note 10 — Long-Term Debt.


	September 30,			December 31,
	2010			2009
Land	$	12,908		$	12,908
Building and improvements		5,664,265			64,265
Machinery and equipment		5,414,634			5,866,853
Office furniture and fixtures		175,862			175,862
Computer and office equipment		717,130			688,261
Vehicles		1,735,852			1,810,064

		13,720,651			8,618,213
Accumulated depreciation		(4,130,380	)		(3,505,120	)

Net other property and equipment	$	9,590,271		$	5,113,093

Note 5 — Note Receivable

During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering facilities ( Appalachian Gathering System ) 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 under a promissory note issued to NGAS Production. The note bears interest at the rate of 8% per annum and is secured by a second mortgage on Seminole Energy’s interest in the Appalachian Gathering System. We assigned the note as part of the collateral package under our revolving credit facility and agreed to apply note payments to debt reduction under the facility. See Note 10 — Long-Term Debt.

Note 6 — Loans to Related Parties

We extended loans to several of our officers prior to 2003 and to one of our shareholders in 2004. The shareholder loan bears interest at 5% per annum and had an outstanding balance of $75,141 at September 30, 2010 and $75,679 at December 31, 2009. The loan is collateralized by the shareholder’s interests in our drilling partnerships and is repayable from partnership distributions. The loans receivable from officers totaled $171,429 at September 30, 2010 and December 31, 2009. These loans are non-interest bearing and unsecured.

Note 7 — Deferred Financing Costs

Other than refinancing costs recognized for our convertible note restructuring, the financing costs for our convertible debt and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 10 — Long-Term Debt. Upon any conversion of our outstanding 2010 notes or payment of amortization installments on the notes in shares of our common stock, the principal amount converted or repaid will be added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for our convertible debt and credit facility aggregated $837,908 at September 30, 2010 and $1,235,705 at December 31, 2009, net of accumulated amortization.

Note 8 — Goodwill

We recorded goodwill of $1,789,564 in our 1993 acquisition of NGAS Production and amortized the goodwill on a straight-line, ten-year basis until 2002, when we adopted authoritative guidance for evaluating goodwill annually and whenever potential impairment exists under a fair value approach at the reporting unit level. With no impairment under our initial and subsequent analyses, unamortized goodwill has remained at $313,177.

Note 9 — Customer Drilling Deposits

Prepayments under drilling contracts with sponsored partnerships are recorded as customer drilling deposits upon receipt. Contract drilling revenues are recognized on the completed contract method as wells are drilled, rather than when funds are received. Customer drilling deposits of $2,511,856 at September 30, 2010 and $5,581,877 at December 31, 2009 represent unapplied prepayments for wells that were not completed as of the balance sheet dates.

Note 10 — Long-Term Debt

Convertible Notes. On January 12, 2010, we exchanged the entire $37 million outstanding principal amount of our 2005 notes for $28.7 million in new amortizing convertible notes due May 1, 2012, together with a combination of common stock, warrants and cash payments of approximately $2.7 million. The 2010 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 2010 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 ( VWAP ) of the common stock prior to the installment date. We elected to pay the initial amortization installments in common shares. See Note 11 — Capital Stock and Note 16 — Subsequent Events. As of September 30, 2010, we had $23.9 million principal amount of 2010 notes outstanding.

Because the net present value of the cash flows from the 2010 notes did not change significantly from the 2005 notes, we accounted for the exchange transaction as a debt modification under FASB Accounting Standards Codification Topic ( ASC ) 470, Debt , which requires that any value exchanged be deferred. In addition, deferred financing costs previously recorded for the 2005 notes continue to be amortized over the life of the 2010 notes, with debt issuance costs expensed as incurred. See Note 7 — Deferred Financing Costs. As a result, we recognized refinancing costs of $625,344 during the first nine months of 2010. During that period, we also recognized non-cash interest expenses of $2,093,136, representing accretion of the debt discount on the 2010 notes under the effective interest method, as well as a fair value loss on derivative financial instruments of $337,195 under the mark-to-market provisions of ASC 815, Derivatives and Hedging , reflecting changes in fair values of the embedded conversion features of the convertible debt and the warrants issued in the exchange transaction.

Credit Facility. We have a revolving credit facility maintained by NGAS Production under a credit agreement with KeyBank National Association, as administrative agent and primary lender. The facility provides for revolving term loans in an aggregate amount up $125 million, subject to borrowing base thresholds determined semi-annually by the lenders. Interest is payable at fluctuating rates ranging from the agent’s prime rate to 2.25% above that rate, and amounted to 5.5% at September 30, 2010. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties. The facility has a scheduled maturity in September 2011, resulting in the classification of our revolving debt as a current liability at September 30, 2010.

We have outstanding borrowings of $37 million under the credit facility, with a borrowing base of $37 million as of September 30, 2010. This reflects an amendment to the credit agreement that permitted us to complete the exchange transaction for our convertible debt in January 2010, subject to monthly reductions of $1 million to the borrowing base through June 2010. The amendment also restricts upstream dividends from NGAS Production for any principal amortization payments on the 2010 notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. We are in compliance with our financial and other covenants under the credit facility, subject to receiving a waiver or forbearance from the lenders with respect to our noncompliance with the leverage ratio under our credit agreement as of September 30, 2010. See Note 16 – Subsequent Events.

Building Loan. In February 2010, NGAS Production financed 80% of the purchase price for the office building that houses our administrative offices in Lexington, Kentucky with a $4.48 million loan from Traditional Bank, Inc. See Note 13 — Related Party Transactions. The loan bears variable interest at 1.625% above the WSJ money rate index and is repayable in monthly installments of $29,420 through February 2015, with the balance of approximately $3.75 million due at maturity. Obligations under the loan are secured by a mortgage on the property and are guaranteed by NGAS. The loan had an outstanding balance of $4,400,502 at September 30, 2010.

Installment Loan. In June 2009, NGAS Production obtained a $2.3 million loan from Central Bank & Trust Co. to finance its commitment under an airplane purchase contract entered in 2005. The loan bears interest at 5.875% per annum and is repayable in monthly installments of $16,428 over a three-year term, with the balance due at maturity. During the second quarter of 2010, we sold a 25% interest in the airplane for $700,000 and applied $575,000 of the proceeds as a partial prepayment. The loan is secured by our remaining 75% interest in the airplane and had an outstanding balance of $1,626,559 at September 30, 2010.

Acquisition Debt. We issued a promissory note for $854,818 in 1986 to finance our acquisition of mineral claims in Alaska. The note is repayable at the rate of $2,000 per month, without interest, and had an outstanding balance of $252,818 at September 30, 2010.

Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at September 30, 2010 and December 31, 2009 and the principal payments due each year through 2015 and thereafter.


	September 30,		December 31,
Principal Amount Outstanding	2010		2009
Total long-term debt (including current portion)	$	65,149,168	$	73,483,920
Less current portion		49,892,193		32,534,084	⁽¹⁾

Total long-term debt	$	15,256,975	$	40,949,836

Debt Maturities ⁽¹⁾

Remainder of 2010	$	3,092,879
2011		50,252,615
2012		7,533,024
2013		182,029
2014		189,907
2015 and thereafter		3,898,714


(1)		Excludes allocations of $2,047,378 for the unaccreted debt discount on the 2010 notes at September 30, 2010 and $4,555,513 for the unaccreted debt discount on the 2005 notes at December 31, 2009.

Note 11 — Capital Stock

Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at September 30, 2010 or December 31, 2009.

Common Shares. The following table reflects transactions involving our common stock during the reported periods. These include common shares and warrants issued in our convertible note exchange during the first quarter of 2010 and in underwritten offerings during the third quarter of 2009 and the second quarter of 2010. We also issued common shares each month, beginning on June 1, 2010, in payment of the monthly amortization installments on the 2010 notes. See Note 10 — Long-Term Debt. Under the true-up provisions of the 2010 notes, if the 20-day VWAP of our stock following an installment payment in common shares differs from the share value applied to that payment, any shortfall is settled in additional common shares, and any surplus is applied to reduce the next amortization installment. The table reflects these monthly share issuances and related true-up adjustments through the end of September 2010. See Note 16 — Subsequent Events.


Common Shares Issued	Shares		Amount
Balance, December 31, 2008		26,543,646	$	110,626,912
Issued in underwritten offering		3,480,000		6,089,476
Issued as stock awards under incentive plan		460,715		426,251

Balance, December 31, 2009		30,484,361		117,142,639
Issued in convertible note restructuring		3,037,151		5,188,333
Issued in underwritten offering		3,960,000		4,701,968
Issued in payment of amortization installments under 2010 notes		4,973,062		4,921,665
Issued as stock awards under incentive plan		76,192		80,002

Balance, September 30, 2010		42,530,766	$	132,034,607


Paid In Capital — Options and Warrants	Amount
Balance, December 31, 2008	$	3,774,600
Recognized		692,646

Balance, December 31, 2009		4,467,246
Recognized		268,383

Balance, September 30, 2010	$	4,735,629


Common Shares to be Issued	Shares		Amount
Balance, September 30, 2010 and December 31, 2009		9,185	$	45,925

Stock Options and Awards. We maintain equity incentive plans adopted in 2001 and 2003 for the benefit of our directors, officers, employees and certain consultants. The 2001 plan provides for the grant of options to purchase up to 3 million common shares, and the 2003 plan reserves 4 million common shares for stock awards and grants of stock options. Awards may be subject to restrictions or vesting requirements, and option grants must be at prevailing market prices. Stock awards were made under the 2003 plan for a total of 460,715 shares during 2009 and 76,192 shares during the first nine months of 2010. Transactions in stock options during those periods are shown in the following table.


							Weighted Average
Stock Options	Issued			Exercisable			Exercise Price
Balance, December 31, 2008		4,613,668			1,413,668		$	3.95
Vested		—			1,225,000			4.69
Expired		(740,000	)		(740,000	)		4.06

Balance, December 31, 2009		3,873,668			1,898,668			3.92
Vested		—			317,500			6.53
Expired		(1,553,668	)		(1,553,668	)		5.37
Forfeited		(75,000	)		(27,500	)		3.71

Balance, September 30, 2010		2,245,000			635,000		$	2.93

At September 30, 2010, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, with a weighted average remaining contractual life of 3.75 years. The following table provides additional information on the terms of stock options outstanding at September 30, 2010.


Options Outstanding							Options Exercisable
			Weighted		Weighted				Weighted
Exercise			Average		Average				Average
Price			Remaining		Exercise				Exercise
or Range	Number		Life (years)		Price		Number		Price
$1.51		1,610,000		4.61	$	1.51		—	$	—
6.51 — 7.64		635,000		1.57		6.53		635,000		6.53

		2,245,000						635,000

We use the Black-Scholes pricing model to determine the fair value of each stock option at the grant date, and we recognize the compensation cost ratably over the vesting period. For the periods presented in the accompanying consolidated financial statements, the fair value estimates for option grants assumes a risk free interest rate ranging from 0.03% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to six years based on the vesting provisions of the options. This resulted in non-cash charges for options and warrants of $692,646 in 2009 and $268,383 in the first nine months of 2010.

Common Stock Purchase Warrants. As part of separate underwritten offerings in August 2009 and May 2010, we issued warrants to purchase up to 1,740,000 common shares through February 13, 2014 at $2.35 per share, subject to adjustment for certain dilutive issuances, and warrants to purchase up to 1,584,000 common shares through November 17, 2014 at $1.61 per share, subject to adjustment for certain corporate events. In addition, as part of the consideration in our convertible note exchange, we issued warrants to purchase up to 1,285,038 common shares through January 12, 2015 at $2.37 per share, subject to adjustment for certain corporate events.

Note 12 — Loss Per Share

The following table shows the computation of basic and diluted loss per share ( EPS ) for the reporting periods in accordance with ASC 260, Earnings per Share .


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

Numerator:
Net loss as reported for basic EPS	$	(2,509,233	)	$	(1,122,001	)	$	(8,403,316	)	$	(4,488,498	)
Adjustments to loss for diluted EPS		—			—			—			—

Net loss for diluted EPS	$	(2,509,233	)	$	(1,122,001	)	$	(8,403,316	)	$	(4,488,498	)


Denominator:

Weighted average shares for basic and diluted EPS		41,044,918			28,873,105			36,709,848			27,508,925

Basic and diluted EPS	$	(0.06	)	$	(0.04	)	$	(0.23	)	$	(0.16	)

Note 13 — Related Party Transactions

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. Note 10 — Long-Term Debt. 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.

Note 14 — Segment Information

We have a single reportable operating segment for our oil and gas business based on the integrated way we are organized by management in making operating decisions and assessing performance. Although our financial reporting reflects our separate revenue streams from drilling, production and gas gathering activities, along with the direct expenses for each component, we do not consider the components as discreet operating segments under ASC 280, S egment Reporting.

Note 15 — Commitments

Operating Lease Obligations. We incurred operating lease expenses totaling $2,670,002 in 2009 and $1,872,074 in the first nine months of 2010. As of September 30, 2010, we had future obligations under operating leases as follows:


Future Lease Obligations
Remainder of 2010	$	579,862
2011		1,853,837
2012		616,087
2013		77,495
2014 and thereafter		31,959

Total	$	3,159,240

Gas Gathering and Sales Commitments. We have various long-term commitments under 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. See Note 5 — Note Receivable. These include monthly gathering fees of $862,750, with annual escalations at the rate of 1.5%, operating fees of $182,612 per month, 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. These agreements have an initial term of fifteen years with extension rights.

Note 16 — Subsequent Events

Convertible Note Amortization . On October 1 and November 1, 2010, we paid monthly amortization installments on the 2010 notes in common shares. See Note 10 — Long-Term Debt. Based on the pricing and true-up provisions of the 2010 notes, we issued a total of 1,628,385 shares for the October installment and 2,257,235 shares for the November installment. These issuances increased our total common stock outstanding to 46,416,385 shares as of the date of this report. See Note 11 — Capital Stock.

Credit Facility Noncompliance. In November 2010, we entered into negotiations with the lenders under our credit facility for a waiver or forbearance with respect to our noncompliance with the leverage ratio under our credit agreement as of September 30, 2010. The covenant limits our consolidated funded indebtedness (excluding the 2010 notes) at the end of the quarter to not more than 4.75 times our consolidated earnings for the trailing twelve-month period before cash interest expense, income tax expense and DD&A, to the extent deducted in determining our consolidated net income or loss for that period. If we are unable to obtain a waiver of the covenant default, we will be required to restructure or seek to replace our credit facility.

NGAS Resources, Inc.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent exploration and production company focused on unconventional natural gas plays in the eastern United States, principally in the southern Appalachian Basin. For over 25 years, we have specialized 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 successfully transitioned to horizontal drilling throughout our Appalachian acreage and expanded our operations to the Illinois Basin. We believe our extensive operating experience, coupled with our relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to deliver volumetric growth.

Capital Structure

Since mid-2009, we completed several deleveraging initiatives. During the third quarter last year, we substantially reduced our credit facility debt with proceeds from the sale of 485 miles of our Appalachian gas gathering facilities ( Appalachian Gathering System ) for $35.5 million, plus a promissory note for $14.5 million, payable in monthly installments with 8% interest through December 2011. We further reduced our credit facility debt by $8.8 million with proceeds from equity offerings in August 2009 and May 2010. In addition, during the first quarter of 2010, we exchanged $37 million of 6% convertible notes due December 2010 for $28.7 million in new amortizing convertible notes due May 1, 2012 ( 2010 notes ), together with a combination of cash, common shares and warrants. See “Liquidity and Capital Resources.”

Business Strategy

Our oil and gas properties span over 360,000 gross acres, concentrated in the southern Appalachian Basin, where we added 60,000 acres last year near our Leatherwood and Amvest fields. Over 76% of our operated properties in this region and in the Illinois Basin are undeveloped. Our strategy for efficient development of these resources has been transformed by advances in air-driven horizontal drilling and staged completion technology optimized for our operating areas. We began this transition early in 2008 and had a total of 56 horizontals on line by the end of September 2010. With an extensive inventory of horizontal locations for ongoing development, we are positioned to achieve sustainable growth under a low-cost structure with several key components.

•

Organic Growth with Reduced Capital Spending . We have addressed the challenging 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 2009 drilling partnership raised over $19 million for participation in 22 horizontal wells. We have a 20% interest in that program, increasing to 35% after payout. This enabled us to meet our near-term drilling commitments and objectives with a reduced budget of $12 million in 2009. We have retained this structure for participation by our current drilling partnership in up to 57 horizontal wells on our core Appalachian properties through the first quarter of 2011, while continuing to maintain our capital expenditures in line with our operating cash flows.

•

Horizontal Drilling Advances . Horizontal drilling has enhanced the value proposition of our properties by substantially increasing recovery volumes and rates at dramatically lower finding costs. 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 one or more 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. By extending the laterals and increasing the number of completion stages, we continue to improve the performance of our horizontal shale wells. 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 and plan to drill additional Weir horizontals at an accelerated pace, with a view to shifting more of our production to crude oil.

•

Infrastructure Position . We operate the Appalachian Gathering System and have firm capacity rights for 30 Mmcf/d of controlled gas through the system, which interconnects to Spectra Energy Partners’ East Tennessee Interstate pipeline network. This ensures long-term deliverability from our connected fields, representing over 90% of our Appalachian production. Our operating and capacity rights also preserve our competitive advantages in assembling additional undeveloped acreage around our core properties in the region as coal mining operations wind down. The sale of the Appalachian Gathering System did not include our 50% interest in a processing plant for extracting natural gas liquids ( NGL ) from system throughput at its delivery point in Rogersville, Tennessee. This is within 5.5 miles of an 880-megawatt gas-fired power plant under construction by the Tennessee Valley Authority, which will substantially increase regional demand when completed next year.

Drilling Operations

Geographic Focus . As of September 30, 2010, we had interests in approximately 1,400 wells, concentrated on our Appalachian properties, which span over 315,000 acres. We believe our long and successful operating history has positioned us as a leading producer in this region. 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 payzone throughout our Appalachian acreage is the Devonian shale formation, also referred to as the Huron shale. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance gas flows. Estimated ultimately recoverable volumes ( EUR s) 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 Air Drilling . Air-driven horizontal drilling and staged completion technology has dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. Our laterals are drilled to traverse the targeted section of the payzone, 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 shale wells to enhance natural fracturing with large volumes of nitrogen, generally one-million standard cubic feet for each of eight or more stages. While approximately three times more expensive than our vertical shale wells, horizontal drilling has substantially increased our recovery volumes and rates at lower overall finding costs. Extending the lateral legs out to 4,800 feet and adding more completion stages has further improved our performance this year, with anticipated EURs exceeding 1.0 Bcfe. In addition, by stacking multiple horizontals on a single drill site, we continue to drive down our finding and development costs.

Drilling Results . The following table shows our gross and net development and exploratory wells drilled during 2009 and the first nine months of 2010.


	Development Wells						Exploratory Wells
	Productive				Dry		Productive		Dry
	Gross		Net		Gross		Gross		Gross

Year ended December 31, 2009
Vertical		10		1.6972		—		—		—

Horizontal		24		5.0588		—		—		—

Subtotal ⁽¹⁾		34		6.7560		—		—		—


Nine months ended September 30, 2010
Vertical		1		1.0000		—		—		—

Horizontal		22		3.5000		—		—

Subtotal		23		4.5000		—		—		—

Total		57		11.2650		—		—		—


(1)		Includes 9 gross (1.9560 net) non-operated wells.

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. We had third-party participation for working interests in our horizontal Leatherwood wells averaging 35% in 2009 and 33% in the first nine months of 2010.

Drilling Partnerships

Benefits . Since 1996, we have sponsored 38 drilling partnerships for accredited investors to participate in many of our drilling initiatives. In addition to addressing the high capital requirements of our business, this structure enables us to diversify our well inventory, satisfy our drilling commitments and reduce our finding costs by leveraging our buying power for drilling services and materials. It also allows us to capture higher and more stable sales prices by expanding the production capacity we can provide to gas purchasers. We focus on low risk, repeatable locations for our drilling partnerships, generally near existing production on large tracts with excellent geology that is well suited for horizontal drilling. This year’s drilling partnership has held initial closings of its private placement for approximately $16 million through the date of this report and will participate with us in up to 57 horizontal wells planned through the first quarter of 2011.

Structure . Our drilling partnerships are structured to share development costs and returns with private investors and optimize their tax advantages through functional allocations of intangible drilling costs. Under this structure, proceeds from the private placement of interests in each investment partnership, together with our 1% capital contribution, are pooled in a separate joint venture or “program” that we form to conduct operations. We contribute capital to each joint venture program in proportion to our initial interest, established at 20% in recent programs. After program payout, we earn an additional reversionary interests in program wells, generally amounting to 15% of the total program interests. We conduct drilling operations for managed programs on a cost-plus basis, with our share of drilling contract profit eliminated on consolidation in our financial statements.

Producing Activities

Regional Advantages . Our proved reserves are concentrated in the southern Appalachian Basin. In addition to the region’s established geology for predictable, long-lived natural gas reserves, its proximity to major east coast gas markets generates realization premiums above Henry Hub spot prices. Our Appalachian natural gas production also has a high energy content, providing energy related premiums over normal pipeline quality gas.

Liquids Extraction . In response to a FERC tariff limiting the upward range of throughput into the East Tennessee Interstate pipeline to 1.1 Dth per Mcf, we constructed a processing plant in Rogersville, Tennessee with a joint venture partner during 2007 to extract NGL from production serviced by the Appalachian Gathering System prior to delivery into the pipeline. The plant was brought on line in January 2008, ensuring our compliance with the FERC tariff. Sales of extracted NGL and our share of processing fees for third-party gas have more than offset the reduction in energy-related yields from our Appalachian gas sales.

Production Profile, Volumes and Prices . Our Appalachian wells produce high quality natural gas at low pressures with little or no water production. As of December 31, 2009, the reserve life index of our estimated proved reserves, representing the ratio of reserves to annual production, was 19.7 years overall and approximately 13.5 years for our proved developed producing reserves, based on annualized fourth quarter production. The following table shows our production volumes of natural gas, crude oil and NGL during the three months and nine months ended September 30, 2010 and 2009 and the year ended December 31, 2009, along with our average sales prices in each of the reported periods.


	Three Months Ended				Nine Months Ended				Year Ended
	September 30,				September 30,				December 31,
	2010		2009		2010		2009		2009
Production volumes:
Natural gas (Mcf)		652,780		816,393		2,028,711		2,521,223		3,321,146
Oil (Bbl)		12,769		11,887		36,886		37,313		48,737
Natural gas liquids (gallons)		1,540,637		1,458,541		3,489,610		3,895,199		4,858,044

Equivalents (Mcfe)		844,944		997,103		2,511,748		3,037,238		3,977,920


Average sales prices:
Natural gas (per Mcf)	$	5.74	$	5.67	$	5.98	$	6.31	$	6.17
Oil (per Bbl)		69.12		60.76		70.52		48.03		52.63
Natural gas liquids (per gallon)		0.64		0.61		0.83		0.64		0.73

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 September 30, 2010, we have contracts in place for approximately 46% of our gas production from operated Appalachian properties at a weighted average sales price of $6.61 per Mcf during the remainder of the year and for approximately 33% of that production at a weighted average sales price of $6.66 per Mcf during the first six months of 2011.

Results of Operations — Three Months Ended September 30, 2010 and 2009

Revenues . The following table shows the components of our revenues for the three months ended September 30, 2010 and 2009, together with their percentage of total revenues in the current period and percentage change on a period-over-period basis.


	Three Months Ended September 30,
			% of					%
Revenue:	2010		Revenue			2009		Change
Contract drilling	$	4,555,485		42	%	$	3,831,250		19	%
Oil and gas production		5,616,269		51			6,239,324		(10	)
Gas transmission, compression and processing		784,750		7			1,123,921		(30	)

Total	$	10,956,504		100	%	$	11,194,495		(2	)

Total revenues for the three months ended September 30, 2010 reflect the impact of reduced drilling activity in prior periods, low natural 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 last year. Although our revenues benefitted from a ramp up in contract drilling for our 2010 partnership during the third quarter, in view of our current business model for maintaining our capital budget in line with operating cash flows, we do not expect this overall trend to reverse without significant improvement in commodity prices.

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. Prior to the third quarter of 2010, however, we drilled several horizontal wells with planned participation by this year’s partnership in advance of funding from its private placement, which was launched in April 2010. Contract drilling revenues for the current quarter reflect reimbursements for the partnership’s share of drilling costs for those wells, together with funding for the partnership’s participation in additional horizontals drilled during the quarter.

Production revenues for the third quarter of 2010 reflect reduced drilling activity in prior periods, higher transportation costs and continued weakness in natural gas prices. Our production output of 845 Mmcfe in the current quarter was 15% below our near-record production of 997 Mmcfe in the third quarter of 2009, which benefitted from higher working interests in wells drilled during the prior year on operated properties. Weighted average prices for our natural gas sales were $6.08 per Mcf for Appalachian production and $5.74 per Mcf overall during the current quarter, compared to $6.53 and $5.67 per Mcf, respectively, in the third quarter of 2009. Approximately 50% of our natural gas production in the current quarter 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.

Expenses . The following table shows the components of our direct and other expenses for the three months ended September 30, 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.


	Three Months Ended September 30,
Direct Expenses:	2010		Margin			2009		Margin
Contract drilling	$	3,196,824		30	%	$	2,913,418		24	%
Oil and gas production		3,988,755		29			2,658,985		57
Gas transmission, compression and processing		91,902		88			960,879		15

Total direct expenses	$	7,277,481		34		$	6,533,282		42


Other Expenses (Income):				% Revenue						% Revenue
Selling, general and administrative	$	2,479,006			23	%	$	2,601,514			23	%
Options, warrants and deferred compensation		226,066			2			285,309			3
Depreciation, depletion and amortization		3,388,841			31			3,304,139			30
Interest expense, net of interest income		1,411,637			13			2,143,393			19
Loss (gain) on sale of assets		209,206			2			(3,356,177	)		N/A
Fair value loss (gain) on derivative financial instruments		(359,398	)		N/A			4,847			—
Other, net		(91,228	)		N/A			292,073			3

Total other expenses	$	7,264,130					$	5,275,098

Contract drilling expenses reflect the level and timing of drilling initiatives conducted with participation by our sponsored partnerships. These expenses represented 70% of contract drilling revenues in the current quarter, compared to 76% in the year-earlier period. 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 eliminated all transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system.

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. Our gas transmission, compression and processing expenses will continue to reflect this reduction 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 in the current quarter decreased by 5% from the same period last year, primarily due to the timing of marketing activities for sponsored drilling partnerships and the level of partnership sales. As a percentage of revenues, SG&A was flat on a year-over-year basis.

Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Employee stock options are valued under this method 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 $153,637 for deferred compensation cost in the current quarter.

Depreciation, depletion and amortization ( DD&A ) is recognized under the units-of-production method, based on the estimated proved developed reserves of the underlying oil and gas properties, and on a straight-line basis over the useful life of other property and equipment. The decrease in DD&A charges reflects a reduction in historical depletion costs for the Appalachian Gathering System following its sale, partially offset by additions to our oil and gas properties.

Cash interest expense for the current quarter was $962,393, representing a 19% decrease from the third quarter of 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 equity raises during the third quarter of 2009 and the second quarter of 2010. See “Liquidity and Capital Resources.” We recognized non-cash interest expense of $640,674 in the current quarter for accretion of the debt discount on the 2010 notes under the effective interest method.

We recorded a fair value gain of $359,398 on derivative financial instruments during the current quarter under mark-to-market accounting for the embedded conversion features of the 2010 notes and related warrants. The accounting treatment of the convertible debt restructuring is discussed in Note 10 to the consolidated financial statements included in this report.

Net Loss and EPS . We recognized net losses of $2,509,233 in the third quarter of 2010 and $1,122,001 in the same period last year, reflecting the foregoing factors. Basic and diluted loss per share ( EPS ) was $(0.06) on 41,044,918 weighted average common shares outstanding in the current quarter, compared to $(0.04) on 28,873,105 weighted average shares in the third quarter of 2009.

Results of Operations — Nine Months Ended September 30, 2010 and 2009

Revenues . The following table shows the components of our revenues for the nine months ended September 30, 2010 and 2009, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.


	Nine Months Ended September 30,
			% of					%
Revenue:	2010		Revenue			2009		Change
Contract drilling	$	15,667,095		43	%	$	16,328,000		(4	)%
Oil and gas production		17,644,686		49			20,198,187		(13	)
Gas transmission, compression and processing		2,835,327		8			6,528,132		(57	)

Total	$	36,147,108		100	%	$	43,054,319		(16	)

Contract drilling revenues for the first nine months of 2010 reflect the 80% share of outside investors in the last four wells drilled with our 2009 partnership and the initial 19 wells with participation by this year’s drilling partnership, which was launched in April 2010. Our 2010 drilling partnership has raised approximately $16 million through the date of this report.

Production revenues for the first nine months of 2010 reflect lower natural gas prices as well as reduced drilling activity during prior periods, which contributed to a 17% decrease in production output to 2,512 Mmcfe, compared to record production of 3,037 Mmcfe in the first nine months of 2009. During the current period, weighted average prices for our natural gas sales were $6.44 per Mcf for our Appalachian production and $5.98 per Mcf overall, compared to $7.44 and $6.31 per Mcf, respectively, in first nine months of 2009. Approximately 50% of our natural gas production in the current period was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.

Expenses . The following table shows the components of our direct and other expenses for the nine months ended September 30, 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.


	Nine Months Ended September 30,
Direct Expenses:	2010		Margin			2009		Margin
Contract drilling	$	11,574,230		26	%	$	12,328,110		24	%
Oil and gas production		11,007,455		38			7,598,044		62
Gas transmission, compression and processing		512,452		82			2,955,204		55

Total direct expenses	$	23,094,137		36		$	22,881,358		47


Other Expenses (Income):				% Revenue						% Revenue
Selling, general and administrative	$	7,811,382			22	%	$	8,404,519			20	%
Options, warrants and deferred compensation		729,295			2			1,022,774			2
Depreciation, depletion and amortization		9,906,178			27			10,610,630			25
Interest expense, net of interest income		4,406,279			12			6,824,842			16
Loss (gain) on sale of assets		218,709			1			(3,369,082	)		N/A
Fair value loss (gain) on derivative financial instruments		337,195			1			(4,477	)		—
Refinancing costs		625,344			2			—			N/A
Other, net		(307,808	)		N/A			600,896			—

Total other expenses	$	23,726,574					$	24,090,102

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 the current quarter, compared to 76% in the year-earlier period, reflecting our cost-plus pricing model adopted in 2006 to address price volatility for drilling services and materials, coupled with improved horizontal drilling efficiencies.

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 eliminated all transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system.

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 gas transmission, compression and processing expenses will continue to reflect this reduction in our infrastructure asset base.

SG&A expenses in the first nine months of 2010 decreased by 7% from the same period last year, primarily due to various cost cutting measures as well as the timing of marketing activities for sponsored drilling partnerships and the level of partnership sales. As a percentage of revenues, SG&A increased to 22% in the current period from 20% in the first nine months of 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 $460,911 for deferred compensation cost in the current period.

The decrease in DD&A charges reflects a reduction in historical depletion costs for the Appalachian Gathering System following its sale, 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.

Cash interest expense for the current period was of 2,980,830, representing a 26% decrease from the first nine months of 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 equity raises during the third quarter of 2009 and the second quarter of 2010. See “Liquidity and Capital Resources.” We recognized non-cash interest expense of $2,093,135 in the current period for accretion of the debt discount on the 2010 notes under the effective interest method.

We recognized a fair value loss of $337,195 on derivative financial instruments during the current period under mark-to-market accounting for the embedded conversion features of the 2010 notes and related warrants. We also recognized refinancing costs of $625,344 during the current period for the note restructuring.

Net Loss and EPS . We recognized net losses of $8,403,316 in the first nine months of 2010 and $4,488,498 in the same period last year, reflecting the foregoing factors. Basic and diluted EPS was $(0.23) on 36,709,848 weighted average common shares outstanding in the current period, compared to $(0.16) on 27,508,925 weighted average shares in the first nine months of 2009. The non-cash interest charges for accretion of the debt discount on our convertible debt and the fair value loss on derivative financial instruments accounted for $2,430,330 or $(0.07) per share of our reported net loss in the first nine months of 2010.

The results of operations for the three months and nine months ended September 30, 2010 are not necessarily indicative of results to be expected for the full year.

Liquidity and Capital Resources

Liquidity . We completed an underwritten offering of 3.96 million units at $1.31 per unit in May 2010, with net proceeds of approximately $4.7 million. We applied $2.7 million of the proceeds to debt reduction under our revolving credit facility and the balance to working capital. Each unit consists of one share of our common stock and a warrant to buy 0.5 common share. The warrants are exercisable through November 17, 2014 for up to 1,584,000 shares of our common stock at $1.61 per share, subject to adjustment upon certain fundamental change transactions or any share recapitalization.

Net cash of $988,368 was used in operating activities in the first nine months of 2010. During the period, we used net cash of $2,318,776 in investing activities, of which approximately $1.8 million represents capital expenditures for developing our oil and gas properties. Our net cash of $4,079,511 from financing activities primarily reflects proceeds from our equity raise, part of which was applied to debt reduction under our credit facility, and proceeds of an installment loan, which 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 $5,105,017 at September 30, 2010.

We had a working capital deficit of $38,319,079 at September 30, 2010. This reflects the current portion of the 2010 notes and the reclassification of our credit facility debt as a current liability based on the scheduled maturity of the facility in September 2011. In addition, as of September 30, 2010, we were not in compliance with the leverage ratio under our credit agreement. We have entered into negotiations with the lenders to restructure the facility as a result of the covenant default, which could otherwise result in a cross-default under our 2010 notes. See “Risk Factors.” We have engaged financial advisors to assist us pursue strategic alternatives, which may include the sale of assets or other types of merger or acquisition transactions intended to maximize shareholder value.

Capital Resources . Our business involves significant capital requirements. The rate of production from oil and gas properties declines as reserves are depleted. Without successful development activities, our proved reserves would decline as oil and gas is produced from our proved developed reserves. We also have substantial annual drilling commitments under various leases and farmouts for our Appalachian properties, including an annual 25-well commitment for our Leatherwood field. Our long-term performance and profitability is dependent not only on meeting these commitments and recovering existing oil and gas reserves, but also on our ability to find or acquire additional reserves and fund their development on terms that are economically and operationally advantageous.

Historically, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities to fund our reserve and infrastructure development and acquisition activities. We have also relied to varying degrees on participation by outside investors in sponsored drilling partnerships. During 2008, we changed our business model to accelerate organic growth by retaining all of our available working interest in wells drilled on operated properties. While we remain committed to expanding our reserves and production through the drill bit, we have addressed the challenging economic environment by monetizing gas gathering assets, restructuring convertible debt, reducing capital expenditures and returning to our successful partnership model for sharing development costs and returns on operated properties.

We raised $19.25 million last year for our 2009 drilling partnership, which participated with us in a portfolio of 22 horizontal wells on our operated properties. We have a 20% interest before payout and a 35% interest after payout in our 2009 program. This structure and several joint venture arrangements with industry partners enabled us to meet our annual drilling commitments with $12 million of capital expenditures last year, reflecting a 75% reduction from our 2008 drilling budget. We have retained this structure for our 2010 drilling partnership, which has raised $16 million through the date of this report. With our critical infrastructure in place and our partnership sales on track, we expect to meet our current drilling commitments and near-term objectives for organic growth with a reduced drilling budget funded from operating cash flow.

In January 2010, we exchanged our outstanding 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million ( 2005 notes ) for $28.7 million in new amortizing convertible notes due May 1, 2012, together with common shares, warrants and cash payments of approximately $2.7 million. The 2010 notes bear interest at 6% per annum, payable quarterly. They are convertible at the option of the holders into our common stock at $2.18 per share, and the warrants issued in the exchange are exercisable at $2.37 per share, subject in each case to certain volume limitations and adjustments for certain fundamental change transactions or share recapitalizations. We are required to make equal monthly principal amortization payments on the 2010 notes during the last 24 months of their term. Subject to certain volume limitations, true-up adjustments and other conditions, we may elect to pay all or part of any principal installment in common stock, valued at the lesser of $2.18 per share or 95% of the 10-day volume weighted-average price of the stock prior to the installment date. We made the monthly amortization installments in common shares, resulting in total issuances of 8,858,682 shares as of the date of this report, with approximately $21.5 million in 2010 notes outstanding.

The 2010 notes are subject to customary non-financial covenants and remedies upon specified events of default, including cross-default with our credit facility. Holders also have the right to require us to redeem their notes in cash upon any event of default at 125% of their principal amount or upon a change of control at 110% of their principal amount. Alternatively, holders may convert their 2010 notes in connection with any change of control and receive either common shares based on the price of our stock at that time or the consideration that would be received for the underlying shares in the change of control transaction. Under certain conditions, we may call the 2010 notes for redemption to force their conversion. Any 2010 notes that are neither repaid, redeemed nor converted will be repayable at maturity in cash plus accrued and unpaid interest.

We have a senior secured revolving credit facility maintained by our operating subsidiary, NGAS Production Co., with KeyBank National Association, as agent and primary lender. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, subject to borrowing base thresholds determined semi-annually by the lenders. The facility has a scheduled maturity in September 2011, resulting in the classification of our revolving debt as a current liability at September 30, 2010. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate 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.

In January 2010, we entered into an amendment to the credit agreement for the facility that permitted us to complete our convertible note exchange, subject to certain non-financial covenants and borrowing base modifications. These include restrictions on upstream dividends from NGAS Production for any principal amortization payments on the 2010 notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. The amendment also provided for monthly borrowing base reductions of $1 million through June 30, 2010. At that time, the borrowing base for the facility was redetermined at $37 million, reflecting the commodity price environment and our reduced drilling activity. Outstanding borrowings under the credit facility totaled $37 million on September 30, 2010 and the date of this report. As of September 30, 2010, we had $37 million outstanding under the credit facility, with $35.8 million outstanding as of the date of this report. As of September 30, 2010, we were not in compliance with the leverage ratio under our credit agreement. The covenant limits our consolidated funded indebtedness (excluding the 2010 notes) at the end of the quarter to not more than 4.75 times our consolidated earnings for the trailing twelve-month period before cash interest expense, income tax expense and DD&A, to the extent deducted in determining our consolidated net income or loss for that period. We have entered into negotiations with the lenders to restructure the facility as a result of the covenant default, which could otherwise result in a cross-default under our 2010 notes. See “Risk Factors.”

Our ability to maintain covenant compliance for our credit facility and to service and repay our revolving and convertible debt will be subject to our future performance and prospects as well as market and general economic conditions. Our future revenues, profitability and rate of growth will continue to be substantially dependent on the market price for natural gas. Future commodity prices will also have a significant impact on our ability to maintain or increase our borrowing capacity, obtain additional capital on acceptable terms and attract drilling partnership capital. While we have been able to mitigate some of the steep decline in natural gas prices with fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production, we are exposed to price volatility for future production not covered by these arrangements. See “Quantitative and Qualitative Disclosures about Market Risk” and “Risk Factors.”

We have addressed the economic downturn and challenging conditions in our industry by monetizing most of our gas gathering infrastructure, deleveraging and modifying our business model to reduce our reliance on the financial and capital markets. To realize our long-term goals for growth in revenues and reserves, however, we will continue to be dependent on those sources of capital or other financing alternatives. Any constriction in the capital markets or protracted weakness in domestic energy markets could require us to sell additional assets or pursue other financing or strategic arrangements to meet those objectives and to repay or refinance our long-term debt at maturity.

Forward Looking Statements

Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of Section 21E of the Securities Exchange Act and Section 27A of the Securities Act of 1933. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate, and other similar expressions, are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. If the assumptions we use in making forward-looking statements prove incorrect or the risks described in this report and incorporated by reference to our 2009 annual report on Form 10-K were to occur, our actual results could differ materially from future results expressed or implied by the forward-looking statements in this report. See “Risk Factors.” Risks that could affect forward-looking statements include the following:

•

uncertainty about future production levels, required capital expenditures and credit agreement compliance;

•

commodity price volatility;

•

increases in the cost of developing and producing our reserves;

•

unavailability or increased costs of drilling rigs, services and materials;

•

drilling, operational and environmental risks;

•

regulatory changes and litigation risks; and

•

uncertainties in estimating oil and gas reserves and projecting future production rates.

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 various types of equipment. The following table summarizes our contractual financial obligations at September 30, 2010 and their future maturities. The table does not include commitments under our gas gathering and sales agreements described below.


	Operating		Debt
Year	Leases		Maturities ⁽¹⁾
Remainder of 2010	$	579,862	$	3,092,879
2011		1,853,837		50,252,615
2012		616,087		7,533,024
2013		77,495		182,029
2014		25,567		189,907
2015 and thereafter		6,392		3,898,714

Total	$	3,159,240	$	65,149,168


(1)		Excludes an allocation of $2,047,378 for the unaccreted debt discount on the 2010 notes.

Gas Gathering and Sales Commitments . We have various commitments under our gas gathering and sales agreements entered with Seminole and Seminole Energy in connection with our sale of the Appalachian Gathering System in 2009. These agreements provide us with firm capacity rights for 30 Mmcf/d of controlled gas and have an initial term of fifteen years with extension rights. Our commitments under these agreements include:

•

Base monthly gathering fees of $862,750, with annual escalations at the rate of 1.5%;

•

Base monthly operating fees of $182,612, plus $0.20 per Mcf of purchased gas; and

•

Monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the Appalachian Gathering System by Seminole Energy.

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 6 and 13 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 or incorporated 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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

Our major market risk exposure is the pricing of natural gas production, which has been highly volatile and unpredictable during the last several years. While we do not use financial hedging instruments to manage our exposure to these fluctuations or for speculative trading purposes, we do use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time up to two years from the contract date. Because these physical delivery contracts qualify for the normal purchase and sale exception from derivative accounting rules, they are not treated as financial hedging activities. The financial impact of physical delivery contracts is included in our oil and gas revenues at the time of settlement, which in turn affects our average realized natural gas prices.

Financial Market Risks

Interest Rate Risk . Borrowings under our secured credit facility bear interest at fluctuating market-based rates. Accordingly, our interest expense is sensitive to market changes, which exposes us to interest rate risk on current and future borrowings under the facility.

Foreign Market Risk . We sell our products and services exclusively in the United States and receive payment solely in United States dollars. As a result, our financial results are unlikely to be affected by factors such as changes in foreign currency exchange rates or weak economic conditions in foreign markets, except to the extent they affect domestic natural gas markets.

Item 4. Controls and Procedures

Management’s Responsibility for Financial Statements

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

Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on management’s evaluation as of September 30, 2010 in connection with the filing of this report, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures are effective to ensure that material information about our business and operations is recorded, processed, summarized and publicly reported within the time periods required under the Exchange Act, and that this information is accumulated and communicated to our management to allow timely decisions about required disclosures.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the effectiveness of our internal control over financial reporting as of September 30, 2010 in connection with the filing of this report, using the criteria established under Internal Control – Integrated Framework , issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management concluded that our internal control over financial reporting was effective based on those criteria as of September 30, 2010.

Changes in Internal Control over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1A Risk Factors

In addition to the risks described elsewhere in this report and incorporated by reference to our 2009 annual report on Form 10-K, we are subject to the following risks relating to our secured credit facility, which could also impact our outstanding convertible debt.

Our cash flow is not sufficient to maintain compliance with the covenants of our existing credit facility.

As of the date of this report, we have outstanding borrowings of $37 million under our credit facility, with a borrowing base of $37 million, and $21.5 million principal amount of outstanding 2010 notes. Our credit facility requires that as of the end of each quarter our consolidated funded indebtedness (excluding the 2010 notes) be not more than 4.75 times our consolidated earnings for the trailing twelve-month period before cash interest expense, income tax expense, depreciation and amortization, each as defined in our credit agreement. As of September 30, 2010, we were not in compliance with the leverage ratio covenant.

In November 2010, we entered into negotiations with the lenders under our credit facility for a waiver or forbearance with respect to our covenant default, which will require us to to restructure our credit facility. In the event we are unsuccessful in negotiating a restructuring under our credit agreement, we could be required to repay the total outstanding credit facility balance. In addition, our 2010 notes contain a cross default provision that would entitle the holders to call their 2010 notes for redemption at a default rate equal to 125% of their principal amount if we were unable to reach agreement with our credit facility lenders. We do not have sufficient cash to make these payments and can make no assurances that our negotiations with our credit facility lenders for restructuring our obligations under the facility will be successful. If we are unable to restructure these obligations or develop a plan acceptable to our lenders for regaining compliance with the leverage covenant or for refinancing our credit facility within a specified period, our creditors could force us into bankruptcy and liquidate our assets to satisfy their debt.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

During the third quarter of 2010, we issued a total of 3,857,357 shares of our common stock to the holders of our 2010 notes in payment of the monthly amortization installments on the notes. The shares were issued without registration under the Securities Act of 1933 based on their status as exempt securities under Section 3(a)(9) of the Securities Act.

Item 6 Exhibits

See “Index to Exhibits” attached to this report and incorporated herein by reference.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	NGAS Resources, Inc.
Date: November 9, 2010	By:	/s/ William S. Daugherty
		William S. Daugherty
		Chief Executive Officer (Duly Authorized Officer) (Principal Executive Officer)

Exhibit Index


*Exhibit*
*Number*		*Description of Exhibit*
31.1		Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.