Ngas Resources (NGAS) 10-Q 2010 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

For the Quarter Ended March 31, 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. Yesþ Noo

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). Yeso Noo

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 filero	Accelerated filerþ	Non-accelerated filero	Smaller Reporting Companyo
		(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). Yeso Noþ

As of May 6, 2010, there were 33,521,512 shares of the registrant’s common stock outstanding.

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

Form 10-Q — March 31, 2010

Table of Contents

	Page
Part IFinancial Information
Items 1 Financial Statements:
Condensed Consolidated Balance Sheets — March 31, 2010 (unaudited) and December 31, 2009		2
Condensed Consolidated Statement of Operations — Three months ended March 31, 2010 and 2009		3
Condensed Consolidated Statement of Cash Flows — Three months ended March 31, 2010 and 2009		4
Notes to Condensed Consolidated Financial Statements		5
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		20
Part IIOther Information
Item 6 Exhibits
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 symbolNGAS. Unless otherwise indicated, references in this report to theCompanyor towe,ourorusinclude NGAS Resources, Inc., our direct and indirect wholly owned subsidiaries and our interests in sponsored drilling partnerships. As used in this report,NGLmeans natural gas liquids,CBMmeans coalbed methane,Dthmeans decatherm,Mcfmeans thousand cubic feet,Mcfemeans thousand cubic feet of natural gas equivalents,Mmcfmeans million cubic feet,Mmcf/dmeans million cubic feet per day,Bcfmeans billion cubic feet andEURmeans estimated ultimately recoverable volumes of natural gas or oil.

NGAS Resources, Inc.

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2010			2009
	(Unaudited)
ASSETS
Current assets:
Cash	$	448,567		$	4,332,650
Accounts receivable		7,188,977			7,277,311
Note receivable		6,373,673			6,247,880
Prepaid expenses and other current assets		498,643			633,884
Loans to related parties		75,169			75,679
Total current assets		14,585,029			18,567,404
Bonds and deposits		258,695			258,695
Note receivable		5,125,077			6,766,451
Oil and gas properties		181,734,206			182,189,679
Property and equipment		10,547,017			5,113,093
Loans to related parties		171,429			171,429
Deferred financing costs		1,206,978			1,235,705
Goodwill		313,177			313,177
Total assets	$	213,941,608		$	214,615,633
LIABILITIES
Current liabilities:
Accounts payable	$	6,111,606		$	5,587,290
Accrued liabilities		696,270			938,829
Long-term debt, current portion		9,952,515			32,534,084
Fair value of derivative financial instruments		—			111
Customer drilling deposits		1,418,569			5,581,877
Total current liabilities		18,178,960			44,642,191
Deferred compensation		804,924			651,287
Deferred income taxes		12,276,654			12,559,549
Long-term debt		63,840,396			40,949,836
Fair value of derivative financial instruments		2,433,242			—
Other long-term liabilities		4,085,788			3,962,254
Total liabilities		101,619,964			102,765,117
SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
33,521,512 Common shares (2009 — 30,484,361)		122,330,972			117,142,639
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital — options and warrants		4,579,757			4,467,246
To be issued:
9,185 Common shares		45,925			45,925
		126,933,024			121,632,180
Deficit		(14,611,380	)		(9,781,664	)
Total shareholders’ equity		112,321,644			111,850,516
Total liabilities and shareholders’ equity	$	213,941,608		$	214,615,633

See accompanying notes.

2

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2010			2009
REVENUE
Contract drilling	$	3,578,431		$	7,323,752
Oil and gas production		6,407,566			7,067,219
Gas transmission, compression and processing		1,279,129			2,804,982
Total revenue		11,265,126			17,195,953
DIRECT EXPENSES
Contract drilling		2,688,919			5,541,426
Oil and gas production		3,315,067			2,324,965
Gas transmission, compression and processing		277,104			968,917
Total direct expenses		6,281,090			8,835,308
OTHER EXPENSES (INCOME)
Selling, general and administrative		2,152,868			3,250,265
Options, warrants and deferred compensation		266,149			418,273
Depreciation, depletion and amortization		3,236,393			3,618,870
Interest expense		1,742,681			2,281,008
Interest income		(254,420	)		(8,816	)
Fair value loss (gain) on derivative financial instruments		2,433,131			(14,319	)
Refinancing costs		625,344			—
Other, net		(105,499	)		79,541
Total other expenses		10,096,647			9,624,822
LOSS BEFORE INCOME TAXES		(5,112,611	)		(1,264,177	)
INCOME TAX EXPENSE (BENEFIT)		(282,895	)		167,162
NET LOSS	$	(4,829,716	)	$	(1,431,339	)
NET LOSS PER SHARE
Basic	$	(0.15	)	$	(0.05	)
Diluted	$	(0.15	)	$	(0.05	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic		33,150,305			26,671,146
Diluted		33,150,305			26,671,146

See accompanying notes.

3

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2010			2009
OPERATING ACTIVITIES
Net loss	$	(4,829,716	)	$	(1,431,339	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Incentive bonus paid in common shares		—			361,250
Options, warrants and deferred compensation		266,148			418,273
Depreciation, depletion and amortization		3,236,393			3,618,870
Gain on sale of assets		1,622			(9,285	)
Fair value loss (gain) on derivative financial instruments		2,433,131			(14,319	)
Accretion of debt discount		747,251			908,967
Deferred income taxes		(282,895	)		167,162
Changes in assets and liabilities:
Accounts receivable		88,334			4,691,954
Prepaid expenses and other current assets		135,241			(69,597	)
Accounts payable		524,316			(7,096,249	)
Accrued liabilities		(242,559	)		(33,379	)
Customers’ drilling deposits		(4,163,308	)		(668,707	)
Other long-term liabilities		123,534			160,057
Net cash provided by (used in) operating activities		(1,962,508	)		1,003,658
INVESTING ACTIVITIES
Proceeds from sale of assets		1,520,681			19,696
Purchase of property and equipment		(5,669,918	)		(29,256	)
Increase in bonds and deposits		—			(214,000	)
Additions to oil and gas properties		(2,358,647	)		(6,008,612	)
Net cash used in investing activities		(6,507,884	)		(6,232,172	)
FINANCING ACTIVITIES
Decrease in loans to related parties		510			1,714
Payments of deferred financing costs		(164,274	)		(1,033	)
Proceeds from issuance of long term debt		7,480,000			5,500,000
Payments of long term debt		(2,729,927	)		(6,000	)
Net cash provided by financing activities		4,586,309			5,494,681
Change in cash		(3,884,083	)		266,167
Cash, beginning of period		4,332,650			981,899
Cash, end of period	$	448,567		$	1,248,066
SUPPLEMENTAL DISCLOSURE
Interest paid	$	985,529		$	1,371,480
Income taxes paid		—			—

See accompanying notes.

4

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 drilling 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 the drilling 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 towe,ourorusinclude NGAS, NGAS Production, its subsidiaries and interests in 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 flow estimates used in impairment tests of goodwill and other long-lived assets, 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.There were no events or transactions through the issuance date of the accompanying consolidated financial statements requiring recognition or disclosure as subsequent events.

     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 March 31, 2010 and December 31, 2009.

5

	March 31,			December 31,
	2010			2009
Proved oil and gas properties	$	205,401,081		$	203,670,153
Unproved oil and gas properties		5,674,684			5,441,933
Gathering facilities and well equipment		15,806,756			15,411,788
		226,882,521			224,523,874
Accumulated DD&A		(45,148,315	)		(42,334,195	)
Net oil and gas properties and equipment	$	181,734,206		$	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 March 31, 2010 and December 31, 2009. Capitalized costs for building and improvements at March 31, 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.

	March 31,			December 31,
	2010			2009
Land	$	12,908		$	12,908
Building and improvements		5,664,265			64,265
Machinery and equipment		5,930,573			5,866,853
Office furniture and fixtures		175,862			175,862
Computer and office equipment		693,359			688,261
Vehicles		1,786,764			1,810,064
		14,263,731			8,618,213
Accumulated depreciation		(3,716,714	)		(3,505,120	)
Net other property and equipment	$	10,547,017		$	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 $75,169 at March 31, 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 March 31, 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 $1,206,978 at March 31, 2010 and $1,235,705 at December 31, 2009, net of accumulated amortization.

6

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 $1,418,569 at March 31, 2010 and $5,581,877 at December 31, 2009 represent unapplied prepayments for wells that were not yet drilled or 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 (2010 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 the option of the holders into our common stock at a conversion price of $2.18 per share, subject to certain volume limitations and adjustments for certain fundamental change transactions or any share recapitalization. Beginning June 1, 2010, we are required to make 24 equal monthly principal amortization payments on outstanding 2010 notes. Subject to certain volume limitations, true-up adjustments and other conditions, we may elect to pay all or part of each principal installment in our common shares, valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the common stock prior to the installment date. Each holder may elect to defer any installment payment to maturity.

     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 in accordance with 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 quarter of 2010. We also recognized a fair value loss on derivative financial instruments of $2,433,131 under the mark-to-market provisions of ASC 815,Derivatives and Hedging, reflecting the change in fair values of the 2010 warrants and the embedded conversion features of the convertible debt.

     Credit Facility.We have a revolving credit facility maintained by NGAS Production under a credit agreement with KeyBank National Association, as administrative agent. 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, with a scheduled maturity in September 2011. Interest is payable at fluctuating rates ranging from the agent’s prime rate to 2.25% above that rate, depending on borrowing base utilization. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties.

     As of March 31, 2010, we had outstanding borrowings of $41.5 million under the credit facility, with a borrowing base of $53 million. This reflects debt reductions of over $41 million from proceeds of our Appalachian Gathering System sale and related equity raise in the third quarter of 2009, as well as a borrowing base reduction of $25 million from lower commodity prices and the release of gas gathering assets from the collateral package. Further borrowing base reductions are being implemented under an amendment to the credit agreement entered in January 2010 that permitted us to complete the exchange transaction for our convertible debt, subject to certain non-financial covenants and the 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 provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend we used for repurchasing 2005 notes in the exchange transaction, unless recontributed for debt reduction under the credit facility by June 30, 2010.

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     Building Loan.In February 2010, NGAS Production financed most of the purchase price for the office building that houses our principal and 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 building and are guaranteed by NGAS. The loan had an outstanding balance of $4,468,781 at March 31, 2010.

     Installment Loan.In June 2009, NGAS Production obtained a $2.3 million loan from Central Bank & Trust Co. to finance the balance of 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. The loan is secured by a lien on the airplane and had an outstanding balance of $2,252,574 at March 31, 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 $264,818 at March 31, 2010.

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

	March 31,		December 31,
	2010		2009
Principal Amount Outstanding
Total long-term debt (including current portion)	$	73,792,911	$	73,483,920
Less current portion		9,952,515		32,534,084	(1)
Total long-term debt	$	63,840,396	$	40,949,836
Debt Maturities(1)
Remainder of 2010	$	6,818,531
2011		54,595,457
2012		8,114,273
2013		182,029
2014		189,907
2015 and thereafter		3,892,714

(1) Excludes allocations of $3,393,262 for the unaccreted debt discount on the 2010 notes at March 31, 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 March 31, 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 during the third quarter of 2009 in a registered direct placement and during the first quarter of 2010 in our convertible note restructuring. See Note 10 — Long-Term Debt.

Common Shares Issued	Shares		Amount
Balance, December 31, 2008		26,543,646	$	110,626,912
Issued in registered direct placement		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
Balance, March 31, 2010		33,521,512	$	122,330,972

8

	Shares		Amount
Paid In Capital — Options and Warrants
Balance, December 31, 2008			$	3,774,600
Recognized				692,646
Balance, December 31, 2009				4,467,246
Recognized				112,511
Balance, March 31, 2010			$	4,579,757
Common Shares to be Issued
Balance, March 31, 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 provides for the issuance of up to 4 million common shares as stock awards or upon exercise of stock options. Awards may be subject to restrictions or vesting requirements, and Option grants must be at prevailing market prices and are generally subject to vesting requirements. Stock awards were made under the 2003 plan for a total of 460,715 shares during 2009, and there were no awards during the interim period in 2010. Transactions in stock options during those periods are shown in the following table.

							Weighted Average
	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
Expired		(900,000	)		(900,000	)		4.25
Forfeited		(75,000	)		(27,500	)		3.71
Balance, March 31, 2010		2,898,668			971,168		$	3.83

     At March 31, 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 3.38 years. The following table provides additional information on the terms of stock options outstanding at March 31, 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		5.11	$	1.51		—	$	—
	6.02 — 7.64		1,288,668		1.21		6.72		971,168		6.78
			2,898,668						971,168

     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 $112,511 in the first quarter of 2010.

     Common Stock Purchase Warrants.As part of our registered direct equity placement in August 2009, we issued warrants to purchase 1.74 million shares of our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances. The warrants are exercisable during a four-year term ending on February 13, 2014. In January 2010, as part of the consideration in our convertible note restructuring, we issued 2010 warrants that are exercisable until January 12, 2015 for a total of 1,285,038 common shares at $2.37 per share, subject to adjustment upon certain fundamental change transactions or any share recapitalization.

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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
	March 31,
	2010			2009
Numerator:
Net loss as reported for basic EPS	$	(4,829,716	)	$	(1,431,339	)
Adjustments to loss for diluted EPS		—			—
Net loss for diluted EPS	$	(4,829,716	)	$	(1,431,339	)
Denominator:
Weighted average shares for basic and diluted EPS		33,150,305			26,671,146
Basic EPS	$	(0.15	)	$	(0.05	)
Diluted EPS	$	(0.15	)	$	(0.05	)

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 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, Segment Reporting.

Note 15 — Commitments

     Operating Lease Obligations.We incurred operating lease expenses of $2,670,002 in 2009 and $639,459 in the first quarter of 2010. As of March 31, 2010, we had future obligations under operating leases as follows:

Future Lease Obligations
Remainder of 2010	$	1,739,586
2011		1,853,837
2012		616,087
2013		77,495
2014 and thereafter		31,959
Total	$	4,318,964

     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 (i) base monthly gathering fees of $850,000, with annual escalations at the rate of 1.5%, (ii) base monthly operating fees of $175,000, plus $0.20 per Mcf of purchased gas, and (iii) monthly 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.

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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, 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 two 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 and strong financial returns on a long-term basis.

Capital Structure

     Since mid-2009, we completed several initiatives to strengthen our balance sheet and improve liquidity. 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 also completed a contemporaneous equity raise netting $6.1 million. During the first quarter of 2010, we exchanged the entire $37 million of our 6% convertible notes due December 15, 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. The 2010 notes have a 6% interest coupon and are convertible into our common stock at $2.18 per share. See “Liquidity and Capital Resources.” Together, these transactions have provided us with greater financial flexibility to take advantage of our development opportunities.

Business Strategy

     Over 76% of our operated properties in the Appalachian and Illinois Basins 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 50 horizontals on line by the end of March 2010, with an extensive inventory of horizontal locations for ongoing development. With our gas gathering infrastructure in place for our core properties and our capital structure revamped for greater financial flexibility, 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. This enabled us to meet our near-term drilling commitments and objectives with a reduced budget of $12 million last year. We have a 20% interest in our 2009 drilling partnership, which will increase to 35% after payout. We have retained this structure for participation by our 2010 drilling partnership in up to 57 horizontal wells on our core properties, while continuing to maintain our capital expenditures in line with our operating cash flows.

• Horizontal Drilling Advances. Advances in air-driven horizontal drilling and staged completion technology have enhanced the value proposition of our properties by substantially increasing recovery volumes and rates at dramatically lower finding costs. Horizontal drilling has also enabled us to develop areas that would otherwise be inaccessible due to challenging terrain or coal mining activities. We began drilling horizontals early in 2008, initially focusing on our key Leatherwood field, and continued the transition to horizontal drilling throughout our operated properties during 2009. The lateral legs 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 at depths ranging from 2,600 to 2,800 feet in the Illinois Bain. This year, we have further improved the performance of our horizontals by extending the laterals and increasing the number of completion stages.

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• Infrastructure Position. We operate the Appalachian Gathering System and have firm capacity rights for 30 Mmcf/d of controlled gas through the system. This ensures long-term deliverability from our connected fields, representing over 90% of our Appalachian production, through an interconnect with Spectra Energy Partners’ East Tennessee Interstate pipeline network. These operating and capacity rights also preserve our competitive advantages in acquiring additional undeveloped acreage in the region upon completion of coal mining activities. Our 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 later this year.

• Acreage Upgrades. We follow a disciplined evaluation process in selecting opportunities to expand our substantial inventory of drilling prospects that meet our criteria for predictable, long-lived reserve development. In October 2009, we expanded our lease position near our Leatherwood field by 10,300 gross (8,280 net) undeveloped acres. Earlier in the year, we also acquired a farmout from Chesapeake Appalachia, LLC for a tract of 56,000 gross (42,000 net undeveloped) acres next to our Amvest field in eastern Kentucky. These upgrades bring our holdings in the Appalachian Basin to a total of 333,392 gross acres.

Drilling Operations

     Geographic Focus. As of March 31, 2010, we had interests in a total of 1,400 wells, concentrated on our Appalachian properties. We believe our long and successful operating history has situated 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 pay zone throughout our Appalachian acreage is the Devonian shale formation, providing predictable locations for repeatable drilling. It is considered an unconventional target due to its low permeability, requiring effective treatment to enhance gas flows. Estimated ultimately recoverable volumes (EURs) of natural gas for our vertical Devonian shale wells reflect modest initial volumes offset by low annual decline rates. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

     Horizontal Air Drilling. Air-driven horizontal drilling and staged completion technologies have dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. Our laterals are drilled at a slight angle from the bottom to the top of the formation, guided by real-time data on the drill bit location. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation. We perform a staged treatment process on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally one-million standard cubic feet for each of eight or more stages. While approximately three times more expensive than vertical shale wells, horizontal drilling has substantially increased our recovery volumes and rates at lower overall finding costs. Extending the lateral legs up to 4,500 feet and adding more completion stages has further improved our performance this year, with anticipated EURs over 1 Bcfe. In addition, by stacking multiple horizontals on a single drill site, we have continued 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 quarter of 2010.

	Development Wells						Exploratory Wells
	Productive				Dry		Productive				Dry
	Gross		Net		Gross		Gross		Net		Gross
Year ended December 31, 2009
Vertical		10		1.6972		—		—		—		—
Horizontal		24		5.0588		—		—		—		—
Subtotal(1)		34		6.7560		—		—		—		—
Quarter ended March 31, 2010
Vertical		1		1.0000		—						—
Horizontal(2)		12		1.6250		—		—		—		—
Subtotal		13		2.6250		—				—		—
Total		47		9.3810		—				—		—

(1)	Includes 9 gross (1.9560 net) non-operated wells.
(2)	Includes 8 wells to be included in our 2010 drilling partnership.

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     Participation Rights. The interests in some of our operated properties in the Appalachian Basin, primarily our Leatherwood field, are subject to participation rights retained by the mineral interest owners, 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 the first quarter of 2010.

Drilling Partnerships

     Benefits. Since 1996, we have sponsored 37 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 reduce our finding costs by leveraging our buying power for drilling services and materials, capture higher and more stable sales prices by expanding the production capacity we can provide to gas purchasers and diversify drilling risks by increasing the number of wells we could drill on a stand-alone basis. 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 our current horizontal drilling initiatives.

     Structure. Our drilling partnerships are structured to optimize tax advantages for private investors and share development costs and returns. Under this structure, proceeds from the private placement of interests in each investment partnership, together with our capital contribution, are contributed to a separate joint venture or “program” that we form to conduct operations. Interests in each program are initially shared in proportion to the partners’ contributions, except for functional allocations of intangible drilling costs to investors. After program payout, typically set at 110% of the partners’ investment, we earn specified increases in our distributive share, up to 15% of the total program interests. We conduct program drilling operations 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, both developed and undeveloped, are concentrated in the southern Appalachian Basin. The proximity of this region to major east coast gas markets generates realization premiums above Henry Hub spot prices. Our Appalachian gas production also has the advantage of a high energy content, ranging from 1.1 to 1.3 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput above 1 Dth per Mcf, this resulted in additional energy related premiums over normal pipeline quality gas.

     Liquids Extraction. In response to a 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 venue 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 ended March 31, 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				Year Ended
	March 31,				December 31,
	2010		2009		2009
Production volumes:
Natural gas (Mcf)		666,148		868,548		3,321,146
Oil (Bbl)		11,179		17,277		48,737
Natural gas liquids (gallons)		966,980		1,201,181		4,858,044
Equivalents (Mcfe)		805,746		1,038,297		3,977,920
Average sales prices:
Natural gas (per Mcf)	$	6.76	$	6.74	$	6.17
Oil (per Bbl)		71.08		33.09		52.63
Natural gas liquids (per gallon)		1.15		0.64		0.73

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     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 the date of this report, we have contracts in place for the following portions of our anticipated quarterly natural gas production through the middle of 2011.

Fixed price contracts for	2010									2011
natural gas production:	Q2			Q3			Q4			Q1			Q2
Percentage of gas contracted		52	%		57	%		54	%		53	%		22	%
Average price per Mcf	$	6.47		$	6.54		$	6.60		$	6.63		$	6.66

Results of Operations — Three Months Ended March 31, 2010 and 2009

     Revenues. The following table shows the components of our revenues for the three months ended March 31, 2010 and 2009, 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					%
Revenue:	2010		Revenue			2009		Change
Contract drilling	$	3,578,431		32	%	$	7,323,752		(51	)%
Oil and gas production		6,407,566		57			7,067,219		(9	)
Gas transmission, compression and processing		1,279,129		11			2,804,982		(54	)
Total	$	11,265,126		100	%	$	17,195,953		(34	)%

     Our total revenues for the first three months of 2010 reflect the impact of reduced drilling activity and third-party ownership of the Appalachian Gathering System, which eliminated both our revenues and cost savings from ownership of these facilities. In view of our current business model for maintaining our capital budget in line with operating cash flows, we do not expect this trend to reverse without significant improvement in commodity prices or increased participation by sponsored partnerships in our drilling activities.

     Contract drilling revenues reflect the size and timing of our drilling partnership initiatives. Although we receive the proceeds from private placements in sponsored partnerships as prepayments under our drilling contracts, revenues from the interests of outside investors are recognized on the completed contract method as the wells are drilled, rather than when funds are received. During the first quarter of 2010, we drilled the last four wells for our 2009 partnership, completing its portfolio of 22 horizontal wells. We also drilled eight horizontals to be included in our 2010 partnership, which was launched in April 2010. We expect to be reimbursed for the partnership’s share of drilling costs for those wells with proceeds of its pending private placement, at which time the related revenues will be recognized.

     Production revenues for the first quarter of 2010 reflect the substantial reduction in our drilling activity, contributing to a 22% decrease in production output year-over-year. During the current quarter, realized natural gas prices averaged $7.50 per Mcf for our Appalachian production and $6.76 per Mcf overall, compared to an average overall realization of $6.74 per Mcf in first quarter of 2009. Approximately 58% 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 and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.

     Expenses. The following table shows the components of our direct and other expenses for the three months ended March 31, 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.

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	Three Months Ended March 31,
Direct Expenses:	2010		Margin			2009		Margin
Contract drilling	$	2,688,919		25	%	$	5,541,426		24	%
Oil and gas production		3,315,067		48			2,324,965		67
Gas transmission, compression and processing		277,104		78			968,917		65
Total direct expenses		6,281,090		44			8,835,308		49

	Three Months Ended March 31,
Other Expenses (Income):	2010			% Revenue			2009			% Revenue
Selling, general and administrative	$	2,152,868			19	%	$	3,250,265			19	%
Options, warrants and deferred compensation		266,149			2			418,273			2
Depreciation, depletion and amortization		3,236,393			29			3,618,870			21
Interest expense, net of interest income		1,488,261			13			2,272,192			13
Fair value loss (gain) on derivative financial instruments		2,433,131			22			(14,319	)		N/A
Refinancing costs		625,344			6			—			N/A
Other, net		(105,499	)		N/A			79,541			—
Total other expenses	$	10,096,647					$	9,624,822

     Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses represented 75% 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.

     Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. Historically, our ownership of the Appalachian Gathering System eliminated transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system. The increase in production expenses on a period-over-period basis primarily reflects higher transportation costs following our sale of the system during the third quarter last year.

     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 is comprised of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses 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 34% from the same period last year, primarily due to the timing of partnership sales, and represented 19% of revenues in both periods.

     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 decreased 27% from the year-earlier period, reflecting the reduction of debt levels under our revolving credit facility from proceeds of our Appalachian Gathering System sale and equity raise in the third quarter of 2009 and our convertible note restructuring in January 2010. Non-cash interest expense of $747,251 in the current quarter reflects the application of the effective interest method for accretion of the debt discount on the 2010 notes.

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     In connection with our convertible debt restructuring, we recognized a fair value loss on derivative financial instruments of $2,433,131 under mark-to-market accounting for the change in fair values of the embedded conversion features of the convertible debt and the warrants issued in the transaction. We also recognized related refinancing costs of $625,344 in the current quarter. The accounting treatment of the note restructuring is discussed in Note 10 to the consolidated financial statements included in this report.

     Net Loss and EPS. We recognized net losses of $4,829,716 in the first three months of 2010 and $1,431,339 in the same period last year, reflecting the foregoing factors. Loss per share (EPS) was $(0.15) on 33,150,305 weighted average common shares outstanding in the current quarter, compared to $(0.05) on 26,671,146 weighted average shares in the first quarter of 2009. The fair value loss on derivative financial instruments, non-cash interest charge and refinancing costs in connection with our convertible debt restructuring accounted for $3,805,726 or $(0.11) per share of our reported net loss in the current quarter.

     The results of operations for the three months ended March 31, 2010 are not necessarily indicative of results to be expected for the full year.

Liquidity and Capital Resources

     Liquidity. In the first quarter of 2010, we used net cash of $1,962,508 in operating activities, primarily reflecting the reported net loss and a $4,163,308 reduction in customer drilling deposits. We also used $6,507,884 in investing activities, of which approximately $2.4 million represents capital expenditures recorded as additions to oil and gas properties and $5.6 million was used to purchase the building that houses our principal and administrative offices. See “Related Party Transactions.” During the current quarter, net cash of $4,586,309 was provided by financing activities, primarily from advances under our revolving credit facility to fund the cash component of our convertible debt restructuring and an installment loan for part of the office building acquisition. As a result of these activities and related cash management, our net cash decreased from $4,332,650 at December 31, 2009 to $448,567 at March 31, 2010.

     As of March 31, 2010, we had a working capital deficit of $3,593,931. This reflects wide fluctuations from the timing of customer deposits and expenditures under drilling contracts with sponsored partnerships, draws and payments under our revolving credit facility and future amortization requirements under the 2010 notes. Since most of these fluctuations are expected to be normalized over relatively short time periods, we do not consider working capital to be a reliable measure of our liquidity.

     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, limiting our use of these partnerships to non-operated initiatives. While we remain committed to expanding our reserves and production through the drill bit, we have addressed the challenging economic environment by monetizing our Appalachian Gathering System, restructuring our convertible debt, reducing our capital expenditures and returning to our successful partnership model for sharing development costs on operated properties.

     We raised $19.25 million last year for our 2009 drilling partnership. This enabled us to meet our near-term commitments and objectives with a reduced drilling budget of $12 million, reflecting a 75% reduction from our 2008 capital expenditures allocated to drilling. We have a 20% interest before payout and a 35% interest after payout in our 2009 program, which participated with us in a total of 22 horizontal wells. We have retained this structure for participation by our 2010 drilling partnership in up to 57 horizontal wells on our core properties. With our critical infrastructure in place to provide deliverability with strong market access for our production, this will allow us to maintain capital expenditures in line with our anticipated cash flow from operations and continue delivering organic growth, although at lower rates than we could achieve by retaining more of our available working interest in new wells. If market conditions improve, we would expect to raise additional capital to advance our long-term resource development objectives.

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     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 3,037,151 shares of our common stock, five-year warrants to purchase 1,285,038 common shares (2010 warrants) and cash payments of approximately $2.7 million. The 2010 notes bear interest at 6% per annum, payable in cash at the beginning of each calendar quarter. They are convertible at the option of the holders into our common stock at $2.18 per share, and the 2010 warrants 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. Under certain conditions, we may call the 2010 notes for redemption to force their conversion.

     During the period from June 1, 2010 through the maturity date, we will be obligated to make 24 equal monthly principal amortization payments on outstanding 2010 notes. Subject to certain volume limitations, true-up adjustments and other conditions, we may elect to pay all or part of each 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. Each holder may elect to defer any installment payment to maturity. Holders also have the right to require us to redeem their 2010 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. 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, with a scheduled maturity in September 2011. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 1.0% above that rate, depending on the amount of borrowing base utilization. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties. Outstanding borrowings under the facility aggregated $41.5 million at March 31, 2010, with a borrowing base of $53 million and a 5% interest rate. We are in compliance with our financial and other covenants under the credit agreement covering the facility.

     In January 2010, we entered into an amendment to the credit agreement that permitted us to consummate our convertible note restructuring, 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 provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend we used for repurchasing 2005 notes in the exchange transaction, unless recontributed for debt reduction under the credit facility by June 30, 2010.

     Our ability 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.”

     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 renewed 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.

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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 were to occur, our actual results could differ materially from future results expressed or implied by the forward-looking statements in this report. Risks that could affect forward-looking statements include the following:

• uncertainty about estimates of future natural gas production and required capital expenditures;

• commodity price volatility;

• increases in the cost of developing and producing our reserves;

• unavailability of drilling rigs and services;

• drilling, operational and environmental risks;

• regulatory changes and litigation risks; and

• uncertainties in estimating 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 office facilities and various types of equipment. The following summarizes our contractual financial obligations at March 31, 2010 and their future maturities. The table does not include commitments under our gas gathering and sales agreements described below.

	Operating		Long-Term
Year	Leases		Debt(1)
Remainder of 2010	$	1,739,586	$	6,818,531
2011		1,853,837		54,595,457
2012		616,087		8,114,273
2013		77,495		182,029
2014		31,959		189,907
2015 and thereafter		—		3,892,714
Total	$	4,318,964	$	73,792,911

(1) Excludes an allocation of $3,393,262 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 $850,000, with annual escalations at the rate of 1.5%;

• Base monthly operating fees of $175,000, 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, our corporate structure causes various agreements and transactions in the normal course of business to 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 in Notes 6 and 13 to the consolidated financial statements included in this report.

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     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 five-year installment loan secured by a mortgage on the property, as described in Note 10 to the consolidated financial statements included in this report. The terms of the transaction were negotiated on our behalf by one of our independent directors appointed for that purpose by our board. The negotiations were conducted at arm’s length with the management company for the building, and our purchase price was approximately the same as the sale price for the building in 2006. The fairness of the consideration was supported by an independent appraisal based on recent sales of comparable office buildings in our locale.

Critical Accounting Policies and Estimates

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

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

     Impairment of Long-Lived Assets.Our long-lived assets include property, equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable.

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

Off-Balance Sheet Arrangements

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

Item 3Quantitative 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.

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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 March 31, 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 March 31, 2010 in connection with the filing of this report, 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, 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

Part II — Item 6

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).

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Exhibit
Number	Description of Exhibit
4.1	Form of Amortizing Convertible Note of NGAS Resources, Inc. due May 1, 2012 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).
4.2	Form of Warrant issued by NGAS Resources, Inc. on August 13, 2009 (incorporated by reference to Exhibit C to Underwriting Agreement dated August 10, 2009 between NGAS Resources, Inc. and BMO Capital Markets Corp., filed as Exhibit 1.1 to Current Report on Form 8-K [File No. 0-12185] filed August 11, 2009).
4.3	Form of Warrant issued by NGAS Resources, Inc. on January 12, 2010 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).
10.1	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).
10.2	2003 Incentive Stock and Stock Option Plan (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).
10.3	Amended and Restated Credit Agreement dated as of May 30, 2008 (“ARCA”) among NGAS Resources, Inc., NGAS Production Co. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.6 to Quarterly Report on Form 10-Q [File No. 0-12185] for the quarter ended June 30, 2008).
10.4	Third Amendment to ARCA dated as of June 2, 2009 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K [File No. 0-12185] filed June 5, 2009).
10.5	Fourth Amendment to ARCA dated as of January 11, 2010 (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).
10.6	Form of Exchange Agreement dated January 11, 2010 (“Exchange Agreements”) between NGAS Resources, Inc. and each holder of its 6% Convertible Notes due December 15, 2010 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).
10.7	NAESB Gas Purchase Agreement dated as of July 15, 2009 between NGAS Production Co. and Seminole Energy Services, LLC (incorporated by reference to Exhibit 10.5 to current report on Form 8-K [File No. 0-12185] dated July 17, 2009).
10.8	Form of Change of Control Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.9 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).
10.9	Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).
10.10	Form of Long-Term Incentive Agreement dated as of December 9, 2008 (incorporated by reference to Exhibit 10.11 to annual report on Form 10-K [File No. 0-12185] for the year ended December 31, 2008).
10.11	Form of general partnership agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.11 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.12	Form of limited partnership agreement with sponsored investment partnerships (incorporated by reference to Exhibit 10.12 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.13	Form of assignment of drilling rights with sponsored drilling programs (incorporated by reference to Exhibit 10.13 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
10.14	Form of drilling and operating agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.14 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).
11.1	Computation of Loss Per Share (included in Note 12 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).

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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.

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 6, 2010	By:	/s/William S. Daugherty
		William S. Daugherty
		Chief Executive Officer (Duly Authorized Officer) (Principal Executive Officer)

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