Ngas Resources (NGAS) 10-Q 2008 Q1 Quarterly report

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 OF 1934

For the Quarter Ended March 31, 2008

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

Commission File No. 0-12185

NGAS Resources, Inc.

(Exact name of registrant as specified in its charter)

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

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

(Former name or former address, if changed since the last report)

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

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

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

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

Number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.

Title of Class	Outstanding at May 2, 2008
Common Stock	26,263,064

NGAS Resources, Inc.

INDEX

	Page
Part I.Financial Information
Item 1. Financial Statements:
Condensed Consolidated Balance Sheets – March 31, 2008 (unaudited) and December 31, 2007		1
Condensed Consolidated Statement of Operations – Three months ended March 31, 2008 and 2007		2
Condensed Consolidated Statement of Cash Flows – Three months ended March 31, 2008 and 2007		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		19
Item 4. Controls and Procedures		19
Part II.Other Information
Item 6. Exhibits		20
EX-31.1
EX-31.2
EX-32.1
EX-32.2

Forward-Looking Statements

     Some matters discussed in this report are prospective and constitute forward-looking statements within the meaning of the Private Litigation Reform Act of 1995. Other than statements of historical fact, all statements that address our future activities, events, outcomes and other matters we plan, expect, budget, intend or estimate (and other similar expressions) are forward-looking statements. While we believe these forward-looking statements are based on reasonable assumptions, they involve known and unknown risks, uncertainties and other factors that may cause future results to differ materially from those discussed or implied in this report. Additional information about issues that could cause actual results to differ from our forward-looking statements is provided in our annual report on Form 10-K for the year ended December 31, 2007.

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

NGAS Resources, Inc.

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash	$	1,643,262		$	2,816,678
Accounts receivable		8,718,209			7,909,943
Prepaid expenses and other current assets		962,512			505,778
Loans to related parties		7,750			7,654
Total current assets		11,331,733			11,240,053
Bonds and deposits		610,445			535,445
Oil and gas properties		194,398,168			183,823,702
Property and equipment		3,624,092			3,689,636
Loans to related parties		247,376			249,410
Deferred financing costs		1,681,852			1,706,852
Other non-current assets		—			3,242,790
Goodwill		313,177			313,177
Total assets	$	212,206,843		$	204,801,065
LIABILITIES
Current liabilities:
Accounts payable	$	8,987,575		$	6,649,809
Accrued liabilities		3,784,488			3,655,684
Customer drilling deposits		3,027,091			2,857,806
Long term debt, current portion		24,000			388,856
Total current liabilities		15,823,154			13,552,155
Deferred income taxes		9,834,430			9,218,770
Long term debt		84,333,809			80,160,915
Deferred compensation		2,062,858			1,960,020
Total liabilities		112,054,251			104,891,860
SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
26,243,064 Common shares (2007 – 26,136,064)		109,087,029			108,842,526
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital – options and warrants		3,408,056			3,484,148
Contributed surplus		955,009			1,043,222
To be issued:
9,185 Common shares		45,925			45,925
		113,472,389			113,392,191
Deficit		(13,319,797	)		(13,482,986	)
Total shareholders’ equity		100,152,592			99,909,205
Total liabilities and shareholders’ equity	$	212,206,843		$	204,801,065

See accompanying notes.

1

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
REVENUE
Contract drilling	$	6,602,118		$	9,245,219
Oil and gas production		8,489,434			6,752,232
Gas transmission, compression and processing		2,558,092			1,947,941
Total revenue		17,649,644			17,945,392
DIRECT EXPENSES
Contract drilling		5,119,849			7,180,717
Oil and gas production		2,764,955			1,683,014
Gas transmission, compression and processing		1,090,246			1,099,593
Total direct expenses		8,975,050			9,963,324
OTHER EXPENSES (INCOME)
Selling, general and administrative		3,288,483			4,021,882
Options, warrants and deferred compensation		137,679			341,123
Depreciation, depletion and amortization		2,871,760			2,306,470
Bad debt expense		347,840			—
Interest expense		1,325,970			1,224,756
Interest income		(69,710	)		(84,054	)
Other, net		(6,277	)		92,749
Total other expenses		7,895,745			7,902,926
INCOME BEFORE INCOME TAXES		778,849			79,142
INCOME TAX EXPENSE		615,660			333,406
NET INCOME (LOSS)	$	163,189		$	(254,264	)
NET INCOME (LOSS) PER SHARE
Basic	$	0.01		$	(0.01	)
Diluted	$	0.01		$	(0.01	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		26,235,811			21,791,107
Diluted		26,731,037			21,791,107

See accompanying notes.

2

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2008			2007
OPERATING ACTIVITIES
Net income (loss)	$	163,189		$	(254,264	)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Incentive bonus paid in common shares		31,570			—
Options, warrants and deferred compensation		137,679			341,123
Depreciation, depletion and amortization		2,871,760			2,306,470
Bad debt expense		347,840			—
Loss on sale of assets		(1,336	)		(5,920	)
Deferred income taxes		615,660			333,406
Changes in assets and liabilities:
Accounts receivable		(1,156,106	)		2,632,366
Prepaid expenses and other current assets		(456,734	)		32,713
Other non-current assets		3,242,790			(527,262	)
Accounts payable		2,337,766			(3,055,522	)
Accrued liabilities		128,804			(662,173	)
Customers’ drilling deposits		169,285			(6,233,268	)
Net cash provided by (used in) operating activities		8,432,167			(5,092,331	)
INVESTING ACTIVITIES
Proceeds from sale of assets		12,200			27,200
Purchase of property and equipment		(155,287	)		(510,401	)
Increase in bonds and deposits		(75,000	)		(25,000	)
Additions to oil and gas properties, net		(13,096,966	)		(10,816,141	)
Net cash used in investing activities		(13,315,053	)		(11,324,342	)
FINANCING ACTIVITIES
Decrease in loans to related parties		1,938			1,843
Proceeds from issuance of common shares		102,000			40,300
Payments of deferred financing costs		(114,293	)		—
Proceeds from issuance of long term debt		5,740,000			4,000,000
Payments of long term debt		(2,020,175	)		(6,000	)
Net cash provided by financing activities		3,709,470			4,036,143
Change in cash		(1,173,416	)		(12,380,530	)
Cash, beginning of period		2,816,678			14,431,977
Cash, end of period	$	1,643,262		$	2,051,447
SUPPLEMENTAL DISCLOSURE
Interest paid	$	1,327,683		$	1,231,044
Income taxes paid		—			—

See accompanying notes.

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NGAS Resources, Inc.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1. Summary of Significant Accounting Policies

     (a) General. The accompanying condensed consolidated financial statements of NGAS Resources, Inc. (NGAS) have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. 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, 2007. Our accounting policies and their method of application in the accompanying condensed consolidated financial statements are consistent with those described in the annual report.

     (b) Basis of Presentation. The accompanying condensed consolidated financial statements include the accounts of NGAS, our wholly owned subsidiary, Daugherty Petroleum, Inc. (DPI), and its wholly owned subsidiaries. The condensed consolidated financial statements also reflect DPI’s interests in a total of 37 drilling programs sponsored to participate in some of its drilling initiatives. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References to theCompany,we,ourorusinclude DPI, its subsidiaries and interests in sponsored drilling programs. These interim consolidated financial statements are unaudited but reflect all normal recurring adjustments that, in the opinion of our management, are necessary to fairly present our financial position at March 31, 2008 and results of operations and cash flows for the three months ended March 31, 2008 and 2007.

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

Note 2. Oil and Gas Properties

     (a) Capitalized Costs and DD&A. All of our oil and gas development and producing activities are conducted within the continental United States. Capitalized costs and accumulated depreciation, depletion and amortization (DD&A) for our oil and gas properties, gathering facilities and well equipment as of March 31, 2008 and December 31, 2007 are summarized below.

	March 31,			December 31,
	2008			2007
Proved oil and gas properties	$	158,104,748		$	148,981,923
Unproved oil and gas properties		4,202,536			3,876,721
Gathering facilities and well equipment		59,019,321			55,370,995
		221,326,605			208,229,639
Accumulated DD&A		(26,928,437	)		(24,405,937	)
Net oil and gas properties and equipment	$	194,398,168		$	183,823,702

     (b) Suspended Well Costs. We adopted FSP No. 19-1,Accounting for Suspended Well Costs, effective January 1, 2005. Based on our evaluation at the time of adoption, we had found proved reserves for all our exploratory wells within one year after completion of drilling. We added suspended well costs late in 2005 and

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during 2006 for an exploratory program to test the New Albany shale formation on the eastern rim of the Illinois basin in western Kentucky. Based on the criteria of FSP No. 19-1, we expensed suspended well costs of $178,700 for the first three wells in that program during 2006 and $964,000 for the remaining 27 wells in the program during the second quarter of 2007. As of March 31, 2008, we had no wells for which exploratory wells costs had been capitalized for a period of greater than one year after completion of drilling.

Note 3. Property and Equipment

     The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of March 31, 2008 and December 31, 2007.

	March 31,			December 31,
	2008			2007
Land	$	12,908		$	12,908
Building improvements		58,051			58,051
Machinery and equipment		3,211,013			3,170,601
Office furniture and fixtures		170,782			168,217
Computer and office equipment		598,965			578,317
Vehicles		1,929,894			1,869,551
		5,981,613			5,857,645
Accumulated depreciation		(2,357,521	)		(2,168,009	)
Net other property and equipment	$	3,624,092		$	3,689,636

Note 4. Deferred Financing Costs

     Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 7 – Long Term Debt. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for our outstanding notes and credit facility aggregated $1,681,852 at March 31, 2008 and $1,706,852 at December 31, 2007, net of accumulated amortization totaling $1,618,787 and $1,479,494, respectively.

Note 5. Goodwill

     Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and was amortized over ten years on a straight-line basis until 2002, when we adopted the Canadian equivalent of Financial Accounting Standards (SFAS) No. 142,Goodwill and Other Intangible Assets. Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment at least annually. Our annual analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of March 31, 2008 and December 31, 2007, with unamortized goodwill of $313,177.

Note 6. Customer Drilling Deposits

     Net proceeds received under drilling contracts with sponsored programs are recorded as customer drilling deposits at the time of receipt. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits aggregated $3,027,091 at March 31, 2008 and $2,857,806 at December 31, 2007, representing unapplied drilling contract payments for wells that were not yet drilled as of the balance sheet dates.

Note 7. Long Term Debt

     (a) Convertible Notes. We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment from the issuance of 4.2 million shares of our common stock in November 2007, based on our net proceeds of approximately $23.7 million. See Note 8 – Capital Stock. We will be entitled to redeem the notes at 100% of their principal amount plus accrued and unpaid interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. Upon any event of default under the notes or any change of control, we may be required to redeem the notes at a default rate equal to

5

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

     (b) Credit Facility. We have a senior secured revolving credit facility maintained by DPI with KeyBank National Association, as agent and primary lender. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $65 million at March 31, 2008. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 0.75% above that rate, depending on the amount of borrowing base utilization. Alternatively, we may elect Eurodollar based pricing from 1.5% to 2.5% above quoted LIBOR rates. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. As of March 31, 2008, outstanding borrowings under the facility aggregated $48 million, with $2 million in letters of credit. The facility is secured by liens on our oil and gas properties. Obligations under the facility have a scheduled maturity in September 2011 and are guaranteed by NGAS.

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

     (d) Acquisition Debt. We issued a note for $854,818 to finance our 1986 acquisition of mineral property on Unga Island, Alaska. The debt is repayable without interest in monthly installments of $2,000 and is secured by liens on the acquired property, buildings and equipment. Although the acquisition agreement provides for royalties at 4% of production revenues, the property has remained inactive. The outstanding acquisition debt was $312,818 at March 31, 2008.

     (e) Total Long Term Debt and Maturities. The following tables summarize our total long term debt at March 31, 2008 and December 31, 2007 and the principal payments due each year through 2012 and thereafter.

	Principal Amount Outstanding
	March 31,			December 31,
	2008			2007
Total long term debt (including current portion)(1)	$	84,357,809		$	80,549,771
Less current portion		24,000			388,856
Total long term debt(1)	$	84,333,809		$	80,160,915
Maturities of Debt
Remainder of 2008	$	18,000
2009		24,000
2010		36,068,991	(1)
2011		48,024,000
2012 and thereafter		222,818

(1) Reflects allocations of $955,009 at March 31, 2008 and $1,043,222 at December 31, 2007 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features and related warrants, which expired unexercised in 2006.

Note 8. Capital Stock

     (a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at March 31, 2008 or December 31, 2007.

     (b) Common Shares. We have 100,000,000 authorized shares of common stock. The following table reflects transactions in our common stock during the reported periods, including a direct placement of 4.2 million common shares at $6.00 per share completed in November 2007 under our existing shelf registration statement.

6

	Number of
	Shares		Amount
Common Shares Issued
Balance, December 31, 2006		21,788,551	$	84,531,832
Issued in registered direct placement		4,200,000		23,687,955
Issued as stock awards under incentive plan		10,430		61,010
Issued upon exercise of stock options and warrants		137,083		561,729
Balance, December 31, 2007		26,136,064		108,842,526
Issued to employees as incentive bonus		7,000		31,570
Issued upon exercise of stock options		100,000		212,933
Balance, March 31, 2008		26,243,064	$	109,087,029
Paid In Capital – Options and Warrants
Balance, December 31, 2006			$	3,073,287
Recognized				529,062
Exercised				(118,201	)
Balance, December 31, 2007				3,484,148
Recognized				34,841
Exercised				(110,933	)
Balance, March 31, 2008			$	3,408,056
Contributed Surplus
Balance, December 31, 2006			$	1,396,074
Accreted(1)				(352,852	)
Balance, December 31, 2007				1,043,222
Accreted(1)				(88,213	)
Balance, March 31, 2008			$	955,009
Common Shares to be Issued
Balance, March 31, 2008 and December 31, 2007		9,185	$	45,925

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

     (c) Stock Options and Awards. We maintain three stock plans for the benefit of our directors, officers, employees and certain consultants or advisors. The plans provide for the grant of options to purchase up to 3,600,000 common shares and, in the case of our most recent plan, either stock awards or options for an aggregate of up to 4,000,000 common shares. Option grants under all the plans must be at prevailing market prices and may be subject to vesting requirements over a period of up to ten years from the date of grant. Stock awards were made under the third plan for 10,430 shares during 2007 and 7,000 shares during the first quarter of 2008. The following table shows transactions in stock options under the plans during the reported periods.

							Weighted Average
	Issued			Exercisable			Exercise Price
Balance, December 31, 2006		2,815,000			945,833		$	4.68
Vested		—			920,833			6.03
Exercised		(127,083	)		(127,083	)		3.17
Forfeited		(6,667	)		—			6.02
Balance, December 31, 2007		2,681,250			1,739,583			4.75
Exercised		(100,000	)		(100,000	)		1.02
Balance, March 31, 2008		2,581,250			1,639,583			4.89

     At March 31, 2008, the exercise prices of options outstanding under our equity plans ranged from $4.03 to $7.04 per share, and their weighted average remaining contractual life was 1.76 years. The following table provides additional information on the terms of stock options outstanding at March 31, 2008.

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Options Outstanding								Options Exercisable
				Weighted		Weighted				Weighted
Exercise				Average		Average				Average
Price				Remaining		Exercise				Exercise
or Range		Number		Life (years)		Price		Number		Price
$   4.03	4.09		1,776,250		1.52		4.05		976,250		4.06
6.02	7.04		805,000		2.30		6.75		663,333		6.91
			2,581,250						1,639,583

     In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R),Share-Based Payment, which we adopted retroactively in 2004. We use the Black-Scholes pricing model to determine the fair value of each stock option at the grant date, and we recognize the compensation cost ratably over the vesting period. For the periods presented in the interim consolidated financial statements, the fair value estimates for each option grant assumed a risk free interest rate ranging from 4.5% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to five years based on the option’s vesting provisions. This resulted in non-cash charges for options and warrants of $529,062 in 2007 and $34,841 in the first three months of 2008.

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

Note 9. Income (Loss) Per Share

     The following table shows the computation of basic and diluted earnings (loss) per share (EPS) for the reporting periods.

	Three Months Ended
	March 31,
	2008		2007
Numerator:
Net income (loss) as reported for basic EPS	$	163,189	$	(254,264	)
Adjustments to income (loss) for diluted EPS		—		—
Net income (loss) for diluted EPS	$	163,189	$	(254,264	)
Denominator:
Weighted average shares for basic EPS		26,235,811		21,791,107
Effect of dilutive securities:
Stock options		495,226		—
Adjusted weighted average shares for dilutive EPS		26,731,037		21,791,107
Basic EPS	$	0.01	$	(0.01	)
Diluted EPS	$	0.01	$	(0.01	)

Note 10. Segment Information

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

Note 11. Commitments

     We incurred operating lease expenses of $2,317,526 in 2007 and $640,833 in the first quarter of 2008. As of March 31, 2008, we had future obligations under operating leases and other commercial commitments in the amounts listed below.

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	Operating		Other
Year	Leases		Commitments(1)		Total
Remainder of 2008	$	1,652,084	$	340,000	$	1,992,084
2009		2,095,062		2,045,000		4,140,062
2010		2,026,933		—		2,026,933
2011		1,820,255		—		1,820,255
2012 and thereafter		713,014		—		713,014
Total	$	8,307,348	$	2,385,000	$	10,692,348

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

Note 12. Recent Accounting Standards

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

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

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

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

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

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

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     EITF 6-10. In March 2007, the FASB ratified the consensus reached by the EITF in Issue No. 6-10,Accounting for the Deferred Compensation and Post Retirement Benefit Aspects of Collateral Assignment Split-Dollar Life Insurance Arrangements. Under this consensus, an employer should recognize a liability for any postretirement benefit related to a collateral assignment split-dollar life insurance arrangement and should recognize and measure the underlying asset based on the substance of the arrangement. The consensus is effective for fiscal years beginning after December 15, 2007, and its adoption did not have a material impact on our consolidated financial position or results of operations.

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

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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 that provide us with repeatable drilling opportunities, principally in the southern portion of the Appalachian Basin. We have specialized for over 20 years in generating our own geological prospects in this region, where we have established expertise and recognition. We also control the gas gathering facilities for our core Appalachian properties, which spanned a total of 619 miles as of March 31, 2008, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets. We believe our extensive geological, geophysical, engineering and operating experience in this region, coupled with our midstream assets, gas gathering infrastructure and relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to achieve annual volumetric growth and strong financial returns on a long term basis.

Strategy

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

• Organic Growth through Drilling. Development drilling is our mainstay for production and reserve growth. We participated in 217 gross (82.2 net) wells during 2007 and an additional 60 gross (27.7 net) wells in the first quarter of 2008. This reflects the evolution of our business model for accelerating organic growth by retaining all of our available working interest in wells drilled on operated properties in the Appalachian and Illinois Basins, which averaged 94% in the first quarter of 2008, compared to 56% during 2007. We implemented this shift in our development strategy late in 2007, and most of our higher net interest wells were awaiting connection at year end. We anticipate significant upside as we bring our backlog of unconnected wells on line. Our growth strategy during 2008 is focused on that task, as well as increasing our acreage position and taking advantage of horizontal drilling opportunities on core properties. We have a drilling budget of $44 million for 2008, including our horizontal drilling initiatives, plus $6 million in related infrastructure build-outs. Both of these components of our capital expenditure program may be adjusted based on various timing considerations, particularly in the view of the added complexities in the permitting process for our horizontal wells.

• Horizontal Drilling Initiatives. The value proposition for many of our Appalachian properties may be enhanced by the use of horizontal drilling, which has been found to provide advantages in extracting natural gas in various environments, including shale and other tight reservoirs that are challenging to produce efficiently. While substantially more expensive, horizontal drilling may improve overall returns on investment by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells. We have focused these initiatives in our Leatherwood field, where we drilled two horizontal wells in the first quarter of 2008 and an additional two wells through the date of this report. Each well has a single lateral leg up to 3,500 feet through the lower Huron section of the Devonian shale, which is present throughout most of our operating areas. For the first month in production, the initial well had an average flow rate 367 Mcf per day. We are encouraged by our preliminary results and plan to drill a total of twenty horizontal wells by year end.

• Enhancement of Field-Wide Infrastructure. We construct and operate field-wide gas gathering facilities to provide compression, connection and local distribution capabilities for most of our Appalachian production. Because we control third-party access to our field-wide systems, they

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	provide us with competitive advantages in acquiring and developing nearby acreage. We continually upgrade these facilities to keep pace with our expanding production base. Recent additions to our field-wide systems include 26 miles of gathering lines installed during the first quarter of 2008, facilities for producing our New Albany shale project in western Kentucky, known as Haley’s Mill, and facilities to provide deliverability from our Fonde field for compression into our midstream system. Production in Fonde has historically been limited by pipeline capacity constraints, and our new system has enabled us to begin connecting a backlog of wells drilled in Fonde over the last several years and open nearly 50,000 acres for future development in this field.
•	Investment in Midstream Assets. We own and operate a strategically located open-access gas gathering system spanning 116 miles in southeastern Kentucky and southwestern Virginia. We acquired these midstream assets in March 2006 through our NGAS Gathering subsidiary and augmented the system through two high-pressure lateral upgrades for connections to our field-wide gathering facilities, plus a recently completed processing plant for liquids extraction We currently deliver all our production from the Leatherwood, Straight Creek and SME fields to the interstate pipeline network through the NGAS Gathering system, and we recently began adding production from our Fonde field through a 14-mile, six-inch steel line to the system. As of March 31, 2008, the system had daily gross throughput of over 19,000 Dth, including third-party deliveries. In addition to generating gas transmission and processing revenues from third-party throughput and cost savings for our own Appalachian production, ownership of these midstream assets gives us control over gas flow from our connected fields and enhances our competitive position in the region.
•	Development of Additional Drilling Prospects. We follow a disciplined capital allocation process in selecting opportunities to expand our substantial inventory of drilling prospects that meet our criteria for predictable, long-lived reserves. Our goal is to consolidate our position in the Appalachian Basin, while diversifying our asset base with similar unconventional plays outside the basin. As part of this strategy, we are aggressively developing our New Albany shale play in the Haley’s Mill field, which is situated within the southcentral portion of the Illinois Basin in western Kentucky. We have also acquired exclusive development rights and a 50% interest in currently constrained gathering infrastructure for a project spanning approximately 63,000 acres across six counties in eastern Kentucky, known as the Licking River prospect. We commenced drilling operations on the Licking River prospect in second quarter this year and have drilled five wells through the date of this report. We plan to continue capitalizing on opportunities to assemble or participate in developing large tracts with significant reserve potential.
•	Purchase of Producing Properties. The purchase of third-party production offers a means in addition to drilling for capitalizing on our operating experience and accelerating our growth. Our acquisition criteria for producing properties include reserve life, profit enhancement potential, existing infrastructure, geographic concentration and working interest levels permitting operation of acquired properties. Based on our current evaluations, we believe our mature drilling programs present attractive acquisition candidates, providing opportunities to increase our interest in producing properties meeting all these criteria. We plan to begin purchasing the assets of targeted programs based on independent reserve valuations that will give effect to our working interests and reversionary interests in these programs. The consolidation of these assets is expected to increase our reserves and cash flows, while also generating administrative efficiencies and simplifying our capital structure.

Drilling Operations

          General. As of March 31, 2008, we had interests in a total of 1,291 wells, concentrated on Appalachian properties that we operate and control through our gas gathering infrastructure. We believe our long and successful operating history in Appalachia and proven ability to drill a large number of wells year after year have positioned us as a leading player in this region. Historically, we conducted most of our drilling operations through sponsored drilling programs. Our combined interest as both general partner and an investor in these programs ranges from 12.5% to 75%, with additional reversionary interests after distribution thresholds are reached. Beginning in the second half of 2007, we changed our business model to accelerate organic growth by limiting our use of future drilling programs to participation in our non-operated initiatives, retaining all of our available working interest in new wells drilled on operated properties.

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     Geological Factors. Most of our Appalachian wells are drilled to relatively shallow total depths up to 5,000 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout this region is the Devonian shale formation. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance natural fracturing in these reservoirs. Typically, vertical gas wells in this part of Appalachia recover between 100 to 450 Mmcf of reserves per drilling unit. While these unconventional shale plays are characterized by modest initial volumes and pressures, their geological features also account for the low annual decline rates demonstrated by vertical wells in the region, many of which are expected to produce for 25 years or more.

     Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2007 and the first three months of 2008. Drilling results shown in the table for 2007 include 89 gross (39.54 net) wells that were drilled by year end but were awaiting installation of gathering lines or extensions prior to completion. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests in wells, without giving effect to any reversionary interest we may subsequently earn in wells drilled through our drilling programs.

	Development Wells						Exploratory Wells
	Productive				Dry		Productive				Dry
	Gross		Net		Gross		Gross		Net		Gross
Year ended December 31, 2007		211		76.1508		—		6		6.0000		—
Three months ended March 31, 2008		60		27.6931		—		—		—		—

     The exploratory wells shown in the table are part of a project started late in 2006 to test the New Albany shale in the southcentral portion of the Illinois Basin on our acquired Haley’s Mill acreage. Results for a total of 22 exploratory and development wells drilled in Haley’s Mill through the end of March 2008 have been promising, and we are continuing to aggressively develop this play, including additions to our lease position and infrastructure, which we expect to bring on line late in the third quarter.

     Participation Rights. The interests in some of our operated properties in the Appalachian Basin, primarily our Leatherwood field, are subject to participation rights retained by the mineral interest owners for up to 50% of the working interest in wells drilled on the covered acreage. During the first quarter of 2008, we had third-party participation in Leatherwood for average working interests of 10.4% in our vertical wells and 37.5% in our horizontal wells.

Producing Activities

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

     Oil and Gas Production. The following table shows our total production volumes and average sales prices for natural gas, oil and natural gas liquids during the three months ended March 31, 2008 and 2007 and for the year ended December 31, 2007.

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	Three Months Ended				Year Ended
	March 31,				December 31,
	2008		2007		2007
Production volumes:
Natural gas (Mcf)		743,998		684,649		2,950,690
Oil (Bbl)		13,488		15,611		57,738
Natural gas liquids (gallons)		634,135		41,333		154,797
Equivalents (Mcfe)		880,414		781,929		3,310,665
Average sales prices:
Natural gas (per Mcf)	$	8.51	$	8.62	$	8.19
Oil (per Bbl)		90.48		51.44		64.97
Natural gas liquids (per gallon)		1.48		1.08		1.41

Results of Operations – Three Months Ended March 31, 2008 and 2007

     Revenues. The following table shows the components of our revenues for the three months ended March 31, 2008 and 2007, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.

	Three Months Ended March 31,
			% of					%
	2008		Revenue			2007		Change
Revenue:
Contract drilling	$	6,602,118		37	%	$	9,245,219		(29	)%
Oil and gas production		8,489,434		48			6,752,232		26
Gas transmission, compression and processing		2,558,092		15			1,947,941		31
Total	$	17,649,644		100	%	$	17,945,392		(2	)%

     Our revenue mix for the first quarter of 2008 reflects our ongoing strategy for transitioning to a more production based business, with oil and gas sales accounting for 48% of total revenues, compared to 38% of total revenues for the first quarter of 2007 and 40% for the year as a whole. We expect this trend to continue as we bring higher interest wells on line and execute our initiatives for expanding our infrastructure, acreage position and working interests in core fields.

     Contract drilling revenues reflect the size and timing of our drilling program initiatives, as well our ownership interest in sponsored programs. Although we receive the proceeds from private placements in sponsored programs as customers’ drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. Our contract drilling revenues in the current quarter reflect the substantial completion of last year’s programs. We are currently sponsoring a program for participation in up to 150 wells on non-operated properties spanning six counties in West Virginia and Virginia, where our investors will have a 75% program interest.

     The growth in our production revenues in the first quarter of 2008 reflects a 13% increase in production output to 880.4 Mmcfe, compared to 781.9 Mmcfe in the same quarter last year. We anticipate ongoing production gains as we continue to upgrade our infrastructure and bring completed wells on stream. Principal purchasers of our production are gas marketers and customers with transmission facilities near our producing properties. Although our realized prices for Appalachian production averaged $9.18 per Mcf in the current quarter, our overall average gas sales prices were marginally lower on a period-over-period basis, amounting to $8.51 per Mcf in the current quarter, compared to $8.62 per Mcf in the first quarter of 2007. Approximately 45% of our natural gas production in the first quarter of 2008 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.

     Gas transmission, compression and processing revenues were driven by fees totaling $1,083,481 for moving third-party gas through our NGAS Gathering system and $203,538 in related processing fees for liquids extraction through our Rogersville plant. This component of revenues also reflects our drilling program investors’ share of gathering and compression fees for moving gas through our field-wide facilities, together with contributions

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of $265,103 from gas utility sales and $108,593 from our minority interest in the gathering system that services a non-operated coalbed methane project in the Arkoma Basin.

     Expenses. The following table shows the components of our direct and other expenses for the three months ended March 31, 2008 and 2007. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

	Three Months Ended March 31,
	2008		Margin			2007		Margin
Direct Expenses:
Contract drilling	$	5,119,849		22	%	$	7,180,717		22	%
Oil and gas production		2,764,955		67			1,683,014		75
Gas transmission, compression and processing		1,090,246		57			1,099,593		44
Total direct expenses		8,975,050		49			9,963,324		44

				% Revenue					% Revenue
Other Expenses:
Selling, general and administrative		3,288,483			19	%		4,021,882		22	%
Options, warrants and deferred compensation		137,679			1			341,123		2
Depreciation, depletion and amortization		2,871,760			16			2,306,470		13
Bad debt expense		347,840			2			—		N/A
Interest expense, net of interest income		1,256,260			7			1,140,702		6
Other, net		(6,277	)		N/A			92,749		1
Total other expenses	$	7,895,745					$	7,902,926

     Contract drilling expenses reflect the level of drilling initiatives conducted through our sponsored programs. These expenses decreased by 29% on a period-over-period basis and represented 78% of contract drilling revenues in both periods. The contraction in this part of our business reflects a planned phase-out of drilling programs to participate in developing our operated properties in the Appalachian Basin. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

     Production expenses for the current quarter were consistent with our volumetric growth. In addition to lifting costs, production expenses include field operating and maintenance costs, related overhead, severance and other production taxes, third-party transportation fees, processing costs and lease operating expenses. Our margins in both periods reflect cost savings realized from ownership of the NGAS Gathering system acquired in March 2006, eliminating transportation and processing fees for our share of Leatherwood, Straight Creek and SME production delivered through the system. As a percentage of oil and gas production revenues, our production expenses were 33% in the first quarter of 2008, compared to 25% in the year-earlier period, primarily reflecting start-up costs for bringing our Rogersville processing plant on line during the current quarter.

     Gas transmission, compression and processing expenses in the first quarter of 2008 were 43% of associated revenues, compared to 56% in the same quarter last year. The margins for this part of our business have benefited from third-party fees generated by the NGAS Gathering system acquired two years ago. Our gas transmission, compression and processing expenses do not include capitalized costs of approximately $3.6 million in the current quarter for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

     Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling programs and overhead costs for supporting our expanded operations as a whole, including additions to our staff and technology infrastructure over the last several years. Although our SG&A expenses in the first quarter of 2008 decreased by 18% from the same period last year, reflecting the shift in our business model to limit our use of drilling programs to non-operated projects, this component of SG&A is subject to considerable fluctuation based on the timing of those initiatives.

     Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $102,838 for deferred compensation cost.

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

     We recognized a bad debt expense of $347,840 in the first quarter of 2008. Coupled with existing reserves from prior periods, this represents the entire amount due for oil sales to a regional refinery prior to its filing for reorganization under the bankruptcy laws last year. See “Critical Accounting Policies and Estimates – Allowance for Doubtful Accounts.”

     Interest expense for the first quarter of 2008 increased from higher overall bank borrowings. Draws under our credit facility during the current quarter were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.

     Deferred income tax expense recognized in the first quarter of 2008 represents future tax liability at the operating company level. Although we have no current tax liability due to the utilization of intangible drilling costs, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level.

     Net Income and EPS. We realized a net income of $163,189 in the first quarter of 2008, compared to a net loss of $254,264 recognized in the same quarter last year, reflecting the foregoing factors. Basic earnings (loss) per share (EPS) was $0.01 based on 26,235,811 weighted average common shares outstanding in the current quarter, compared to EPS of $(0.01) based on 21,791,107 weighted average common shares outstanding in the first quarter of 2007.

     The results of operations for the three months ended March 31, 2008 are not necessarily indicative of results to be expected for the full year.

Liquidity and Capital Resources

     Liquidity. Net cash of $8,432,167 was provided by operating activities for the first three months of 2008. During the period, we used $13,315,053 in investing activities, most of which reflects net additions to our oil and gas properties and gathering systems. These investments were funded in part with net cash of $3,709,470 from financing activities. As a result of these activities, net cash decreased from $2,816,678 at the end of last year to $1,643,262 at March 31, 2008.

     As of March 31, 2008, we had a working capital deficit of $4,491,421. This reflects wide fluctuations in our current assets and liabilities from the timing of customer deposits and expenditures under drilling contracts with our sponsored programs. Since these fluctuations are normalized over relatively short time periods, we do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of the first quarter this year is not expected to have an adverse effect on our financial condition or results of operations in future periods.

     Capital Resources. Our business involves significant capital requirements. The rate of production from oil and gas properties declines as reserves are depleted. Without successful development activities, our proved reserves would decline as oil and gas is produced from our proved developed reserves. Our long term performance and profitability is dependent not only on recovery of existing oil and gas reserves, but also on our ability to find or acquire additional reserves and provide the infrastructure to support their development on terms that are economically and operationally advantageous. Historically, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities to fund our ongoing reserve and infrastructure development and acquisition activities, as well as participation in our drilling initiatives by outside investors in our sponsored programs. With the evolution of our business model for accelerating organic growth by retaining all of our available working interest in wells drilled on operated properties, we have limited our use of future drilling programs to participation in our non-operated initiatives. This may increase our dependence on the credit and capital markets to meet our ongoing development objectives.

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

     We maintain a secured credit facility with KeyBank National Association, as agent and primary lender. The facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a borrowing base of $65 million as of March 31, 2008. The facility is secured by liens on our oil and gas properties. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 0.75% above that rate, depending on the amount of borrowing base utilization. Alternatively, we may elect Eurodollar based pricing from 1.5% to 2.5% above quoted LIBOR rates. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of March 31, 2008, our outstanding borrowings under the facility aggregated $48 million, and the interest rate amounted to 5.5%, reflecting our election for prime-based pricing during the first quarter of 2008.

     We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $12.94, reflecting an antidilution adjustment based on the pricing of our registered direct equity placement in November 2007. We will be entitled to redeem the notes at their face amount plus accrued interest if the prevailing market price of our common stock exceeds 160% of the note conversion price for specified periods. In the event of a default under the notes or any change of control, the holders may require us to redeem the notes at a default rate equal to 125% of their principal amount or a change of control rate equal to the greater of 110% of their principal amount or the consideration that would be received by the holders for the underlying shares in the change of control transaction. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares, valued for that purpose at 92.5% of their prevailing market price.

     Our ability to repay our bank debt and convertible notes will be subject to our future performance and prospects as well as market and general economic conditions. We will likely be dependent on additional financings to repay our outstanding long term debt at maturity. Our future revenues, profitability and rate of growth will continue to be substantially dependent on the demand and market price for natural gas. Future market prices for natural gas will also have a significant impact on our ability to maintain or increase our borrowing capacity, to obtain additional capital on acceptable terms and to attract drilling program capital for participation in our non-operated initiatives. The market price for natural gas is subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of other factors that are beyond our control.

     We expect our cash reserves, cash flows from operations and anticipated borrowing base availability under our credit facility to provide adequate working capital to meet our short-term capital expenditure objectives. To fully realize our financial goals for growth in revenues and reserves, we will continue to be dependent on the capital markets or other financing alternatives.

Forward Looking Statements

     Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of Private Litigation Reform Act of 1995. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate (and other similar expressions) are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. They include subsurface risks on the recoverability of hydrocarbons, operating risks involving logistical, infrastructure and regulatory issues and commercial risks stemming from the volatility of natural gas prices. A discussion of these risk factors is included in our annual report on Form 10-K for the year ended December 31, 2007. There were no material changes in these risk factors during the interim period covered by this report.

Contractual Obligations and Commercial Commitments

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

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	Operating Leases						Other		Long Term
Year	Equipment		Premises		Total		Commitments(1)		Debt
Remainder of 2008	$	1,468,505	$	183,579	$	1,652,084	$	340,000	$	18,000
2009		1,848,198		246,864		2,095,062		2,045,000		24,000
2010		1,779,118		247,815		2,026,933		—		36,068,991	(2)
2011		1,567,866		252,389		1,820,255		—		48,024,000
2012 and thereafter		435,685		277,329		713,014		—		222,818
Total	$	7,099,372	$	1,207,976	$	8,307,348	$	2,385,000	$	84,357,809

(1)	Reflects (i) obligations of $240,000 under a guaranty secured by a certificate of deposit provided for bank debt of a limited liability company in which we previously held an interest and (ii) commitments under a purchase contract for an airplane.
(2)	Excludes an allocation of $955,009 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features.

Critical Accounting Policies and Estimates

     General. The preparation of financial statements requires management to utilize estimates and make judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. These estimates are based on historical experience and on various other assumptions that management believes to be reasonable under the circumstances. The estimates are evaluated by management on an ongoing basis, and the results of these evaluations form a basis for making decisions about the carrying value of assets and liabilities that are not readily apparent from other sources. Although actual results may differ from these estimates under different assumptions or conditions, management believes that the estimates used in the preparation of our financial statements are reasonable. The critical accounting policies affecting these aspects of our financial reporting are summarized in Note 1 to the consolidated financial statements included in our 2007 annual report on Form 10-K. Policies involving the more significant judgments and estimates used in the preparation of our consolidated financial statements are summarized below.

     Estimates of Proved Reserves and Future Net Cash Flows. Estimates of our proved oil and gas reserves and related future net cash flows are used in impairment tests of goodwill and other long-lived assets. These estimates are prepared as of year end by our independent petroleum engineers and are updated internally at mid-year. There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling, testing and production after the date of these estimates may require future revisions, and actual results could differ materially from the estimates.

     Impairment of Long-Lived Assets.Our long-lived assets include property and equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, while other long-lived assets are reviewed whenever events or changes in circumstances indicate that carrying values of these assets are not recoverable. During 2007, we recognized an impartment charge of $964,000 for exploratory well costs that had been capitalized for less than one year pending our assessment of reserves for the project.

     Allowance for Doubtful Accounts.We maintain an allowance for doubtful accounts when deemed appropriate to reflect losses that could result from failures by customers or other parties to make payments on our trade receivables. The estimates of this allowance, when maintained, are based on a number of factors, including historical experience, aging of the trade accounts receivable, specific information obtained on the financial condition of customers and specific agreements or negotiated amounts with customers.

Forward Looking Statements and Risk Factors

     Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of the Private Litigation Reform Act of 1995. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate (and other similar expressions) are forward-looking statements. The forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. They include subsurface risks on the recoverability of hydrocarbons, operating risks involving logistical, infrastructure and regulatory issues and commercial risks stemming from the volatility of natural gas prices. A discussion of these risk factors is included in

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our annual report on Form 10-K for the year ended December 31, 2007. There were no material changes in these risk factors during the interim period covered by this report.

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 for 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 production at specified prices during varying periods of time up to two years from the contract date. Because these physical delivery contracts qualify for the normal purchase and sale exception under SFAS No. 133, they are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of physical delivery contracts is included in our oil and gas revenues at the time of settlement, which in turn affects our average realized natural gas prices. For the remaining three quarters of 2008, we have contracts in place for approximately 78% of our gas production from operated properties at a weighted average sales price of $9.45 per Mcf.

Financial Market Risks

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

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 March 31, 2008, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures are effective to ensure that material information about our business and operations is recorded, processed, summarized and publicly reported within the time periods required under the Exchange Act, and that this information is accumulated and communicated to our management to allow timely decisions about required disclosures.

Management’s Report on Internal Control over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the effectiveness of our internal control over financial reporting as of March 31, 2008 using the criteria established underInternal Control – Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment, management concluded that our internal control over financial reporting was effective based on those criteria as of March 31, 2008.

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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 6. Exhibits

Exhibit
Number	Description of Exhibit
3.1	Notice of Articles, certified on June 3, 2004 by the Registrar of Corporations under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
3.2	Alteration to Notice of Articles, certified on June 25, 2004 by the Registrar of Corporations under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
3.3	Articles dated June 25, 2004, as amended and restated for corporate transition under the British Columbia Business Corporations Act (incorporated by reference to Exhibit 3.3 to Current Report on Form 8-K [File No. 0-12185], filed June 29, 2004).
10.1	1997 Stock Option Plan (incorporated by reference to Exhibit 10[a] to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2002).
10.2	2001 Stock Option Plan (incorporated by reference to Exhibit 10[b] to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2002).
10.3	2003 Incentive Stock and Stock Option Plan (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.4	Asset Purchase and Sale Agreement dated as of January 17, 2006 among Duke Energy Gas Services, LLC, NGAS Gathering, LLC and Daugherty Resources, Inc. (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated January 19, 2006).
10.5	Form of 6% convertible notes issued pursuant to the Securities Purchase Agreement dated as of December 13, 2005 among NGAS Resources, Inc. and the investors named therein (incorporated by reference to Exhibit 10.2 to current report on Form 8-K [File No. 0-12185] dated December 14, 2005).
10.6	Credit Agreement dated as of September 8, 2006 among NGAS Resources, Inc., Daugherty Petroleum, Inc. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated September 8, 2006).
10.7	Form of Change of Control Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.9 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.8	Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.9	Form of Long Term Incentive Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.11 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).
10.10	Form of general partnership agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.11 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.10	Form of limited partnership agreement with sponsored investment partnerships (incorporated by reference to Exhibit 10.12 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).

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Exhibit
Number	Description of Exhibit
10.12	Form of assignment of drilling rights with sponsored drilling programs (incorporated by reference to Exhibit 10.13 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.13	Form of drilling and operating agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.14 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
11.1	Computation of Earnings Per Share (included in Note 9 to the accompanying consolidated financial statements)
21.0	Subsidiaries (incorporated by reference to Exhibit 21.1 to annual report on Form 10-K [File No. 0-12185] for the year ended December 31, 2006).
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.
32.2	Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

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: May 8, 2008	By:	/s/William S. Daugherty
		William S. Daugherty
		Chief Executive Officer (Duly Authorized Officer) (Principal Executive Officer)

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