Ngas Resources 10Q 2007 Q2 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 June 30, 2007


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. Yesþ Noo

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer (each as defined in Rule 12b-2) or a non-accelerated filer.

Large accelerated filero Accelerated filerþ Non-accelerated filero

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2). Yeso Noþ

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


Title of Class		Outstanding at August 3, 2007
Common Stock		21,798,981

NGAS Resources, Inc.

INDEX


		Page
Part I. Financial Information

*Item 1. Financial Statements*:

Condensed Consolidated Balance Sheets – June 30, 2007 (unaudited) and December 31, 2006		1

Condensed Consolidated Statement of Operations – Three months and six months ended June 30, 2007 and 2006		2

Condensed Consolidated Statement of Cash Flows – Three months and six months ended June 30, 2007 and 2006		3

Notes to Condensed Consolidated Financial Statements		4

*Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations*		12

*Item 3. Quantitative and Qualitative Disclosures about Market Risk*		21

*Item 4. Controls and Procedures*		21

PART II. OTHER INFORMATION

*Item 4. Submission of Matters to a Vote of Security Holders*		22

*Item 6. Exhibits*		22
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, 2006.

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.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2007			2006
	(Unaudited)
ASSETS
Current assets:
Cash	$	2,872,020		$	14,431,977
Accounts receivable		7,964,917			9,108,574
Prepaid expenses and other current assets		866,114			1,108,734
Loans to related parties		7,466			7,147

Total current assets		11,710,517			24,656,432

Bonds and deposits		570,695			533,695
Oil and gas properties		164,762,711			144,217,532
Property and equipment		3,842,173			3,342,571
Loans to related parties		253,401			257,430
Deferred financing costs		1,985,437			2,264,022
Other non-current assets		3,502,229			2,634,271
Goodwill		313,177			313,177


Total assets	$	186,940,340		$	178,219,130


LIABILITIES
Current liabilities:
Accounts payable		6,658,999			9,286,849
Accrued liabilities		3,519,817			3,998,978
Customers’ drilling deposits		4,868,133			12,173,905
Long term debt, current portion		24,000			24,000

Total current liabilities		15,070,949			25,483,732

Deferred income taxes		8,482,850			8,035,779
Long term debt		86,087,170			66,922,744
Deferred compensation		1,711,380			1,419,776


Total liabilities		111,352,349			101,862,031


SHAREHOLDERS’ EQUITY

Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
21,798,981 Common shares (2006 – 21,788,551)		84,575,142			84,531,832
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital – options and warrants		3,451,983			3,073,287
Contributed surplus		1,219,648			1,396,074
To be issued:
9,185 Common shares (2006 – 9,185)		45,925			45,925

		89,269,068			89,023,488
Deficit		(13,681,077	)		(12,666,389	)


Total shareholders’ equity		75,587,991			76,357,099


Total liabilities and shareholders’ equity	$	186,940,340		$	178,219,130

See accompanying notes.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
REVENUE
Contract drilling	$	7,459,704		$	11,029,274		$	16,704,923		$	31,440,774
Oil and gas production		6,730,947			5,935,783			13,483,179			12,139,967
Gas transmission and compression		1,887,039			1,374,585			3,834,980			2,078,156

Total revenue		16,077,690			18,339,642			34,023,082			45,658,897


DIRECT EXPENSES
Contract drilling		5,919,020			7,840,559			13,099,737			24,543,489
Oil and gas production		1,799,186			1,529,940			3,482,200			2,983,408
Gas transmission and compression		779,843			541,869			1,879,436			1,174,298
Impairment of oil and gas assets		964,000			—			964,000			—

Total direct expenses		9,462,049			9,912,368			19,425,373			28,701,195


OTHER EXPENSES (INCOME)
Selling, general and administrative		3,042,364			3,164,516			7,064,246			7,638,908
Options, warrants and deferred compensation		329,177			419,787			670,300			848,534
Depreciation, depletion and amortization		2,361,176			1,964,578			4,667,646			3,502,490
Interest expense		1,534,216			1,089,070			2,758,972			1,689,453
Interest income		(49,689	)		(101,524	)		(133,743	)		(219,884	)
Other, net		45,156			86,440			137,905			127,388

Total other expenses		7,262,400			6,622,867			15,165,326			13,586,889


INCOME (LOSS) BEFORE INCOME TAXES		(646,759	)		1,804,407			(567,617	)		3,370,813


DEFERRED INCOME TAX EXPENSE		113,665			1,081,454			447,071			2,022,123


NET INCOME (LOSS)	$	(760,424	)	$	722,953		$	(1,014,688	)	$	1,348,690


NET INCOME (LOSS) PER SHARE
Basic	$	(0.03	)	$	0.03		$	(0.05	)	$	0.06

Diluted	$	(0.03	)	$	0.03		$	(0.05	)	$	0.06


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		21,798,607			21,456,828			21,794,843			21,417,395

Diluted		21,798,607			22,919,707			21,794,843			23,072,192

See accompanying notes.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
OPERATING ACTIVITIES
Net income (loss)	$	(760,424	)	$	722,953		$	(1,014,688	)	$	1,348,690
Adjustments to reconcile net income to net cash used in operating activities:
Incentive bonus paid in common shares		3,010			—			3,010			291,032
Compensation from options and warrants		329,177			419,787			670,300			848,534
Depreciation, depletion and amortization		2,361,176			1,964,578			4,667,646			3,502,490
Impairment of oil and gas assets		964,000			—			964,000			—
Gain on sale of assets		84,061			4,015			78,141			22,973
Deferred income taxes		113,665			1,081,454			447,071			2,022,123
Changes in assets and liabilities
Accounts receivable		(1,488,709	)		(2,897,966	)		1,143,657			(3,095,607	)
Prepaid expenses and other current assets		209,907			653,388			242,620			2,262,169
Other non-current assets		(340,696	)		62,124			(867,958	)		(761,820	)
Accounts payable		427,672			1,118,653			(2,627,850	)		2,652,633
Accrued liabilities		183,012			(1,953,700	)		(479,161	)		851,056
Customers’ drilling deposits		(1,072,504	)		(4,901,949	)		(7,305,772	)		(20,730,549	)

Net cash provided by (used in) operating activities		1,013,347			(3,726,663	)		(4,078,984	)		(10,786,276	)


INVESTING ACTIVITIES

Proceeds from sale of assets		7,500			4,443			34,700			4,443
Purchase of property and equipment		(476,103	)		(164,950	)		(986,504	)		(489,692	)
Increase in bonds and deposits		(12,000	)		(10,000	)		(37,000	)		(11,000	)
Additions to oil and gas properties, net		(14,708,038	)		(9,523,333	)		(25,524,179	)		(35,044,644	)

Net cash used in investing activities		(15,188,641	)		(9,693,840	)		(26,512,983	)		(35,540,893	)


FINANCING ACTIVITIES
Decrease in loans to related parties		1,867			1,775			3,710			22,416
Proceeds from issuance of common shares		—			119,570			40,300			287,626
Payments of deferred financing costs		—			—			—			(75,000	)
Proceeds from issuance of long term debt		15,000,000			11,021,067			19,000,000			29,000,000
Payments of long term debt		(6,000	)		(6,000	)		(12,000	)		(12,000	)

Net cash provided by financing activities		14,995,867			11,136,412			19,032,010			29,223,042


Change in cash		820,573			(2,284,091	)		(11,559,957	)		(17,104,127	)
Cash, beginning of period		2,051,447			9,124,216			14,431,977			23,944,252

Cash, end of period	$	2,872,020		$	6,840,125		$	2,872,020		$	6,840,125


SUPPLEMENTAL DISCLOSURE
Interest paid	$	1,526,408		$	1,126,537		$	2,757,452		$	1,793,203
Income taxes paid		—			—			—			—

See accompanying notes.

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, 2006. Except as noted below, 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 36 drilling programs sponsored to participate in its drilling operations. 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 June 30, 2007 and results of operations and cash flows for the three months and six months ended June 30, 2007 and 2006.

(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 June 30, 2007 and December 31, 2006 are summarized below.


	June 30,			December 31,
	2007			2006
Proved oil and gas properties	$	130,278,138		$	110,169,303
Unproved oil and gas properties		3,512,312			3,000,465
Gathering facilities and well equipment		50,309,355			46,369,858

		184,099,805			159,539,626
Accumulated DD&A		(19,337,094	)		(15,322,094	)


Net oil and gas properties and equipment	$	164,762,711		$	144,217,532

(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 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 June 30, 2007, 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 June 30, 2007 and December 31, 2006.


	June 30,			December 31,
	2007			2006
Land	$	12,908		$	12,908
Building improvements		58,051			48,350
Machinery and equipment		3,368,209			2,680,174
Office furniture and fixtures		163,725			129,031
Computer and office equipment		562,328			569,877
Vehicles		1,506,080			1,607,554

		5,671,301			5,047,894
Accumulated depreciation		(1,829,128	)		(1,705,323	)


Net other property and equipment	$	3,842,173		$	3,342,571

Note 4. Deferred Financing Costs

Financing costs for our convertible note private placements and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. These costs include $354,819 incurred in the third quarter of 2006 for our new credit facility. 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 $1,985,437 at June 30, 2007 and $2,264,022 at December 31, 2006, net of accumulated amortization totaling $1,200,910 and $922,324, 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 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 June 30, 2007 and December 31, 2006, with unamortized goodwill of $313,177.

Note 6. Customer Drilling Deposits

We sponsor and manage drilling programs to participate in our drilling initiatives, in which we maintain non-promoted interests ranging from 12.5% to 75%. Historically, we conducted drilling operations under turnkey contracts with our sponsored drilling programs, requiring us to drill and complete wells at specified prices and entitling us to any surplus if the contract price exceeded our costs. In 2006, we changed the structure of our new drilling programs from turnkey pricing to cost plus, with a view to reducing our exposure to price volatility for drilling services, equipment and steel casing requirements. Under both structures, net proceeds received under drilling contracts with sponsored programs are recorded as customers’ 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 aggregating $4,868,133 as of June 30, 2007 and $12,173,905 at December 31, 2006 represent 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 issued several series of convertible notes in private placements to finance part of our drilling and acquisition activities. During 2005, the notes of all prior series were converted by their holders, either voluntarily or in response to our redemption calls, resulting in our issuance of 3,439,478 common shares during the year. In December 2005, we completed an institutional private placement of a new series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million, all of which remained outstanding at June 30, 2007, with a conversion price of $14.34, subject to adjustment for certain dilutive issuances of common stock. We also issued warrants in the transaction, which expired unexercised in August 2006. See Note 8 – Capital Stock.

The purchase agreement for our outstanding 6% notes provides holders with certain participation rights in future financing transactions. It also provides for a holder electing to convert a note before the second anniversary of the issuance date to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, unless the prevailing market price of our common stock exceeds 160% of the conversion price, payable at our option in cash or in common shares. After that date, if the prevailing market price of the common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Any notes that are neither redeemed nor converted prior to maturity will be repayable in cash or in common shares. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.

(b) Credit Facility. In September 2006, we entered into a credit agreement with KeyBank National Association, as agent and primary lender. The credit agreement provides DPI with a senior secured revolving credit facility that replaces its prior credit facility with KeyBank, which had a scheduled maturity date of July 31, 2007 and a borrowing base of $35 million. The new 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 at June 30, 2007. Under the terms of the credit agreement, outstanding borrowings 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, depending on our borrowing base utilization. The credit agreement also provides for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of June 30, 2007, outstanding borrowings under the facility aggregated $50 million, with $2 million in letters of credit. The facility is secured by liens on our interests in most of our producing wells. Obligations under the facility are guaranteed by NGAS.

(c) 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 net smelter returns or other production revenues, the property has remained inactive. The remaining acquisition debt was $330,818 at June 30, 2007 and $342,818 at December 31, 2006.

(d) Total Long Term Debt and Maturities. The following tables summarize our total long term debt at June 30, 2007 and December 31, 2006 and the principal payments due each year through 2010 and thereafter.


	Principal Amount Outstanding
	June 30,		December 31,
	2007		2006
Total long term debt (including current portion)⁽¹⁾	$	86,111,170	$	66,946,744
Less current portion		24,000		24,000


Total long term debt⁽¹⁾	$	86,087,170	$	66,922,744


(1)		Reflects allocations of $1,219,648 at June 30, 2007 and $1,396,074 at December 31, 2006 from our 6% convertible notes in the principal amount of $37,000,000 based on equity components of their conversion features and related warrants.

Maturities of Debt


Remainder of 2007	$	12,000
2008		24,000
2009		24,000
2010		35,804,352
2011 and thereafter		50,246,818

Note 8. Capital Stock

(a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at June 30, 2007 or December 31, 2006.

(b) Common Shares. The following tables reflect transactions involving our common stock during the periods presented.


	Number of
	Shares		Amount
Common Shares Issued
Balance, December 31, 2005		21,357,628	$	82,371,189
Issued to employees as incentive bonus		65,945		468,612
Issued upon exercise of stock options and warrants		336,106		1,472,026
Issued for contract settlement		28,872		220,005

Balance, December 31, 2006		21,788,551		84,531,832
Issued to employees as incentive bonus		430		3,010
Issued upon exercise of stock options and warrants		10,000		40,300

Balance, June 30, 2007		21,798,981	$	84,575,142


Paid In Capital – Options and Warrants
Balance, December 31, 2005			$	2,743,806
Recognized				975,468
Expired				(565,946	)
Accreted⁽¹⁾				(80,041	)

Balance, December 31, 2006				3,073,287
Recognized				378,696

Balance, June 30, 2007			$	3,451,983


Contributed Surplus

Balance, December 31, 2005			$	1,748,926
Accreted⁽¹⁾				(352,852	)

Balance, December 31, 2006				1,396,074
Accreted⁽¹⁾				(176,426	)

Balance, June 30, 2007				1,219,648


Common Shares to be Issued
Balance, June 30, 2007 and December 31, 2006		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, in the case of the second and third plans, certain consultants or advisors. The plans provide for the grant of options to purchase up to 3,600,000 common shares and, in the case of our most recent plan, either stock awards or options for an aggregate of up to 4,000,000 common shares. Option grants under all the plans must be at prevailing market prices and may be subject to vesting requirements over a period of up to ten years from the date of grant. Stock awards under the third plan may be subject to vesting conditions and trading restrictions specified at the time of grant. Stock awards and option grants were made under the third plan for a total of 65,945 shares during

2006 and 430 shares during the first six months of 2007. The following table shows transactions and vesting in stock options during the reported periods.


							Weighted Average
	Issued			Exercisable			Exercise Price
Balance, December 31, 2005		2,985,000			571,250		$	4.67
Vested		—			509,583			4.26
Exercised		(135,000	)		(135,000	)		4.05
Forfeited		(35,000	)		—			6.02

Balance, December 31, 2006		2,815,000			945,833			4.68
Vested		—			292,500			4.03

Balance, June 30, 2007		2,815,000			1,238,333			4.68

At June 30, 2007, the exercise prices of options outstanding under our stock option plans ranged from $1.02 to $7.04 per share, and their weighted average remaining contractual life was 2.39 years. The following table provides additional information on the terms of stock options outstanding at June 30, 2007.


Options Issued and Outstanding								Options Exercisable
				Weighted		Weighted				Weighted
Exercise				Average		Average				Average
Price				Remaining		Exercise				Exercise
or Range		Number		Life (years)		Price		Number		Price
$	1.02		145,000		0.51	$	1.02		145,000	$	1.02
	4.03 4.09		1,845,000		2.25		4.05		1,045,000		4.06
	6.02 7.04		825,000		3.06		6.74		48,333		6.02

			2,815,000						1,238,333

In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R),Share-Based Payment, which we adopted retroactively under its Canadian GAAP equivalent 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 three months to five years based on the option’s vesting provisions. This resulted in non-cash charges for options and warrants of $975,468 in 2006 and $378,696 in the first six months of 2007.

(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					Six Months Ended
	June 30,					June 30,
Diluted EPS	2007			2006		2007			2006
Numerator:
Net income (loss) as reported for basic EPS	$	(760,424	)	$	722,953	$	(1,014,688	)	$	1,348,690
Adjustments to income for diluted EPS		—			—		—			—

Net income (loss) for diluted EPS	$	(760,424	)	$	722,953	$	(1,014,688	)	$	1,348,690

Denominator:
Weighted average shares for basic EPS		21,798,607			21,456,828		21,794,843			21,417,395
Effect of dilutive securities:
Stock options		—			1,277,449		—			1,444,601
Warrants		—			185,430		—			210,196

Adjusted weighted average shares and assumed conversions for diluted EPS		21,798,607			22,919,707		21,794,843			23,072,192


Basic EPS	$	(0.03	)	$	0.03	$	(0.05	)	$	0.06

Diluted EPS	$	(0.03	)	$	0.03	$	(0.05	)	$	0.06

Note 10. Segment Information

We have two reportable segments based on management responsibility and key business operations. The following table presents summarized financial information on these business segments.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
Revenue:
Oil and gas development	$	16,077,690		$	18,339,642		$	34,023,082		$	45,658,897
Corporate		—			—			—			—

Total		16,077,690			18,339,642			34,023,082			45,658,897

DD&A:
Oil and gas development		2,194,706			1,810,080			4,337,131			3,196,825
Corporate		166,470			154,498			330,515			305,665

Total		2,361,176			1,964,578			4,667,646			3,502,490

Interest expense:
Oil and gas development		979,216			534,070			1,648,972			579,453
Corporate		555,000			555,000			1,110,000			1,110,000

Total		1,534,216			1,089,070			2,758,972			1,689,453

Net income (loss):
Oil and gas development		121,866			1,561,882			643,347			3,032,535
Corporate		(882,290	)		(838,929	)		(1,658,035	)		(1,683,845	)

Total		(760,424	)		722,953			(1,014,688	)		1,348,690

Capital expenditures:
Oil and gas development		15,065,115			9,647,046			26,264,057			35,411,913
Corporate		119,026			41,237			246,626			122,423

Total	$	15,184,141		$	9,688,283		$	26,510,683		$	35,534,336


	June 30,		December 31,
	2007		2006
Identifiable assets:
Oil and gas development	$	183,776,214	$	174,750,803
Corporate		3,164,125		3,468,327

Total	$	186,940,340	$	178,219,130

Note 11. Commitments

We incurred lease rental expenses of $1,727,982 in 2006 and $1,151,115 in the first six months of 2007. As of June 30, 2007, we have contractual obligations for periodic future payments under leases for field equipment and instruments governing our other commercial commitments in the amounts listed below.


	Commercial Commitments
	Operating		Other
Year	Leases		Commitments			Total
Remainder of 2007	$	1,018,533	$	240,000	⁽¹⁾	$	1,258,533
2008		1,920,596		100,000	⁽²⁾		2,020,596
2009		1,776,054		2,045,000	⁽²⁾		3,821,054
2010		1,706,974		—			1,706,974
2011 and thereafter		1,847,021		—			1,847,021


Total	$	8,269,178	$	2,385,000		$	10,654,178


(1)		Reflects obligations under a guaranty secured by a certificate of deposit provided for bank debt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held a minority interest.

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

Note 12. Recent Accounting Standards

EITF 6-11. In June 2007, the Financial Accounting Standards Board (FASB) ratified the consensus reached by the Emerging Issues Task Force (EITF) in 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 is not expected to have a material impact on our consolidated financial statements.

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 is not expected to 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. We will adopt SFAS No. 159 at the beginning of 2008 and do not expect its adoption to have a material impact on our consolidated financial condition or results of operations.

SAB No. 108. In September 2006, the staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108,Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year financial statement errors should be considered in quantifying a current year misstatement. Beginning in 2007, prior year errors must be quantified using both a balance sheet and income statement approach and evaluated based on relevant quantitative and qualitative factors in determining their materiality for disclosure purposes. Application of this guidance has not had a material affect on our consolidated financial statements.

SFAS No. 158. In September 2006, the FASB issued SFAS No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. SFAS No. 158 requires the employer to recognize the overfunded

or underfunded status of any defined benefit postretirement plan as an asset or liability on its balance sheet and to recognize changes in that status through adjustments to comprehensive income. It also requires an employer to measure the funded status of a plan as of the date of its year-end balance sheet. These requirements are effective for fiscal years ending after December 15, 2006. The adoption of SFAS No. 158 has not had a material impact on our consolidated financial position, results of operations or cash flows.

SFAS No. 157. In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosure requirements about fair value measurements. The guidance in SFAS No. 157 applies to fair value measurements for derivatives and other financial instruments at initial recognition and in all subsequent periods. SFAS No. 157 is generally effective for all reporting periods during fiscal years beginning after November 15, 2007. The adoption of SFAS No. 157 has not had any material impact on our consolidated financial position or results of operations.

FSP AUG AIR–1. In September 2006, the FASB issued FSP AUG AIR–1,Accounting for Planned Major Maintenance Activities. FSP AUG AIR–1 prohibits companies from accruing the future costs of periodic major overhauls and maintenance of plant and equipment as a liability. The provisions of FSP AUG AIR–1 are effective for fiscal years beginning after December 15, 2006. The implementation of these provisions has not had a material impact on our consolidated financial statements.

FIN No. 48. In July 2006, the FASB issued FASB Interpretation (FIN) No. 48,Accounting for Uncertainty in Income Taxes – Interpretation of FASB No. 109. FIN No. 48 requires us to recognize the impact of a tax position on our financial statements if that position is more likely than not to be sustained on audit, based on the technical merits of the position. The provisions of FIN No. 48 are effective at the beginning of 2007, with the cumulative effect of any resulting change in accounting principles recorded as an adjustment to opening retained earnings. The adoption of FIN No. 48 has not had a material affect on our consolidated financial position.

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 basins in the eastern United States that support multiple, repeatable drilling, principally in the southern portion of the Appalachian basin. We specialize in generating our own geological prospects in this region, where we have established expertise and recognition. We also control the gas gathering and transmission facilities for our core Appalachian properties, 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, infrastructure position and relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to achieve annual volumetric growth and strong financial returns on a long term basis.

Our principal and administrative offices are located in Lexington, Kentucky. Our common stock is traded on the Nasdaq National 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.

Strategy

Our business is structured to achieve capital appreciation through growth in our natural gas reserves, production, cash flow and earnings per share. In 2006, we had record production of 2.9 Bcfe, with a 28% increase in our total revenue to $79.8 million. We also increased our estimated proved reserves by 34% to 100.9 Bcfe at year end. We achieved these benchmarks primarily through drilling success and a larger net position in new wells on our core properties. Our strategy for continuing to realize our operational and financial objectives for 2007 and beyond emphasizes several components.

	•		Organic Growth through Drilling. Development drilling is our mainstay for production and reserve growth. As of June 30, 2007, we had interests in a total of 1,116 wells, concentrated in our core operated properties in the Appalachian basin. 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. We participated in 226 gross (65.4577 net) wells during 2006 and an additional 106 gross (45.4965 net) wells in the first six months of 2007. The increase in our net well position this year reflects our strategy for accelerating organic growth by retaining larger working interests in new wells drilled on our core operated properties and reducing our reliance on sponsored drilling programs for participation in these initiatives. A majority of our Appalachian acreage is undeveloped, providing us with a multi-year inventory of drilling locations for future development.

	•		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 for $18 million. We operated this system since October 2004 and augmented it after the acquisition through two high-pressure lateral upgrades. Ownership of these facilities compliments our field-wide Appalachian gathering systems, expanding our total gathering position to 559 miles as of June 30, 2007. We currently move production from our Leatherwood, Straight Creek and SME fields for delivery through the NGAS Gathering system, which has daily gross throughput of over 19,000 Dth, including third-party deliveries. In addition to generating gas transmission and compression revenues from third-party throughput and cost savings for our own Appalachian production, ownership of these assets gives us control over gas flow from our connected fields and enhances our competitive position in the region.

	•		Extension of Infrastructure. We construct and operate field-wide gas gathering and compression facilities for our Appalachian properties, which we continually upgrade to keep pace with our expanding production base. Because we control third-party

			access to these facilities, they provide us with competitive advantages in acquiring and developing nearby acreage. Our field-wide systems spanned 443 miles at June 30, 2007, including 103 miles of production lines installed in 2006 and 29 miles in the first two quarters this year. Recent additions to our infrastructure include facilities that have enabled us to bring a backlog of unconnected wells in our Leatherwood field on line sequentially for compression into the NGAS Gathering system. We have upgraded the main suction line for this field to enhance flow rates from new Leatherwood wells. We are also extending our infrastructure to provide deliverability from our Fonde field through a 14-mile, six-inch steel line to our midstream system. Production in Fonde has historically been limited by pipeline capacity constraints. When completed, our new system will enable us to begin connecting over 60 wells drilled in Fonde and open nearly 50,000 acres for future development in this field.

	•		Acquisition of Additional Drilling Prospects. We follow a disciplined capital allocation process in selecting opportunities to build our substantial inventory of drilling prospects that meet our criteria for predictable, long-lived reserves. During 2006, we expanded our position in several of our major Appalachian fields. We also implemented initiatives to leverage our core expertise with evolving technologies in horizontal and directional drilling, which may provide advantages in extracting tight gas from unconventional formations. The initial projects are being conducted in the Arkoma basin for coalbed methane (CBM) recovery, in the Illinois basin on acreage we acquired in western Kentucky to test the New Albany shale formation and in West Virginia on acreage controlled by a joint venture partner. We plan to continue capitalizing on opportunities to assemble or acquire interests in large tracts with significant development potential. Our goal is to consolidate our position in the Appalachian basin, while also diversifying our prospect inventory with similar unconventional plays.

	•		Purchase of Producing Properties. The purchase of third-party production offers a means in addition to drilling for accelerating our growth, while continuing to capitalize on our operating experience. 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 some of our drilling programs present attractive acquisition candidates, providing opportunities to increase our interest in producing properties meeting all of these criteria. We plan to implement a strategy to begin acquiring the assets of targeted programs based on independent reserve valuations that will give effect to our working interests and reversionary interests in these programs. In addition to increasing our reserves and cash flows, the consolidation of these assets should generate administrative efficiencies, while also simplifying our capital structure.

Regional Advantages

Geographic. Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian basin. This is one of the oldest and most prolific natural gas producing areas in the United States. Typically, natural gas wells in this part of the Appalachian basin recover between 100 to 500 Mmcf of reserves per drilling unit. Their proximity to major east coast markets generates realization premiums above Henry Hub spot prices, contributing to long term returns on investment. The natural gas production, known as sweet gas, is environmentally friendly because it is substantially free of sulfur compounds, carbon dioxide or other chemical impurities. In addition, the wells in this region generally produce no water with the gas production. This helps us minimize production (lifting) costs. Most of our Appalachian gas production also has a high energy content (Dth), ranging from 1.1 to 1.3 Dth per Mcf. Our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1 Dth per Mcf, which historically has resulted in realized premiums averaging 17% over normal pipeline quality gas. As a result of a developing trend limiting the upward range of pipeline throughput to 1.1 Dth per Mcf, we are currently designing a processing plant for liquids extraction from our Appalachian production to bring us into compliance with this standard. We expect our sales of extracted liquids to offset some of the reduction in energy-related yields from our Appalachian gas production on a long term basis.

Geological. Most of our 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 for most of these wells is the Devonian shale formation. This is considered an unconventional target due to its low permeability, and natural fracturing is often enhanced by effective acidizing or other treatments. While this typically results in modest initial volumes and pressures, it also accounts for the low annual decline rates demonstrated by our wells in the region, many of which are expected to produce for 25 years or more.

Drilling Operations

Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2006 and the first six months of 2007. 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. The wells reflected in the table as dry exploratory wells were previously reported as productive pended determination of proved reserves within one year after completion of drilling. These wells were drilled as part of a 30-well project to test the shallow New Albany shale formation, some with horizontal legs, on the eastern rim of the Illinois basin in western Kentucky. We were not encouraged by the initial test results, and we expensed the suspended well costs for three of the wells during 2006. Upon completing our evaluation of secondary test results for the remaining 27 wells in the second quarter of 2007, we expensed all of their suspended exploratory costs. Late last year, we began a second phase of this exploratory project for our own account to test the New Albany shale at greater depths through traditional vertical drilling in the central Kentucky portion of the Illinois basin. Treatment and flow testing on the first six wells have been promising, and we plan to expand this phase of the project.


	Development Wells						Exploratory Wells
	Productive				Dry		Productive				Dry
	Gross		Net		Gross		Gross		Net		Gross
Year ended December 31, 2006		193		56.3007		—		4		3.1250		29
Six months ended June 30, 2007		100		39.4965		—		6		6.000		—

Production Volumes and Sales Prices. The following table shows our total net oil and gas production volumes and average sales prices for the six months ended June 30, 2007 and 2006 and for the year ended December 31, 2006. We also had extracted liquids and condensates that contributed $122,374 to our production revenues in the first six months of 2007, $96,030 in the year-earlier period and $199,734 in 2006.


	Six Months Ended				Year Ended
	June 30,				December 31,
	2007		2006		2006
Production volumes:

Natural gas (Mcf)		1,359,650		1,282,496		2,622,474
Oil (Bbl)		31,341		18,463		40,938


Equivalents (Mcfe)		1,547,698		1,393,273		2,868,102


Average sales prices:

Natural gas (per Mcf)	$	8.58	$	8.56	$	8.23
Oil (per Bbl)		53.95		58.05		59.60

Participation Rights. The leases and farmouts for some of our acreage in the Appalachian basin, primarily the Leatherwood field, are subject to third-party participation rights for up to 50% of the working interests in new wells. We had third-party participation in our Leatherwood wells for average working interests of 25.4% in 2006 and 13.9% during the first six months of 2007.

Drilling Programs

Drilling Program Structure. Historically, we have conducted most of our drilling operations through sponsored programs. In addition to managing program operations, we invest in each drilling program on substantially the same terms as outside investors. We contribute capital to each program in proportion to our initial ownership interest, and we share program distributions in the same ratio until program distributions reach payout, which ranges from 100% to 110% of partners’ investment. After payout, we are entitled to specified increases in our distributive share, up to 15% of the total program interests. We account for our interests in drilling programs using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation.

Drilling Program Investments. In 2006 and the first half of 2007, we sponsored five drilling programs for participation in a total pf 205 wells, including 159 wells on our southern Appalachian prospects, where we maintained a 45% interest in our 2007 program and tiered interests in our 2006 programs ranging from 20% to 75% on a field-wide basis. Our 2006 initiatives also included a program for 40 natural gas wells on Appalachian acreage in West Virginia operated by a joint venture partner and a program for six horizontal CBM wells drilled by another joint venture partner in the Arkoma basin. We have a 25% stake in the West Virginia program and a 12.5% share of the Arkoma program. We plan to launch a new program in the third quarter this year for up to 100 vertical, deviated and horizontal wells under a participation agreement covering 75% of the working interests available to our joint venture partner on its Appalachian prospects in West Virginia and Virginia.

Results of Operations – Three Months Ended June 30, 2007 and 2006

Revenues. The following table shows the components of our revenues for the three months ended June 30, 2007 and 2006, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.


	Three Months Ended June 30,
			% of					%
	2007		Revenue			2006		Change
Revenue:

Contract drilling	$	7,459,704		46	%	$	11,029,274		(32	)%
Oil and gas production		6,730,947		42			5,935,783		13
Gas transmission and compression		1,887,039		12			1,374,585		37


Total	$	16,077,690		100	%	$	18,339,642		(12	)

Our revenue mix for the second quarter of 2007 reflects our ongoing strategy for transitioning to a production based business, with oil and gas sales accounting for 42% of total revenues, compared to 32% of total revenues for the year-earlier quarter and 30% for 2006 as a whole. We expect this trend to continue as we execute our initiatives for long term production growth by expanding our infrastructure, acreage position and working interests in core fields.

Contract drilling revenues reflect the size and timing of our drilling program financings, as well as our percentage interest in drilling initiatives conducted through sponsored programs. Although we receive the proceeds from program financings as customers’ drilling deposits under our drilling contracts with sponsored programs, we recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. We participated in 49 gross (21.8965 net) wells in the second quarter of 2007, compared to 49 gross (11.7244 net) wells in the same quarter last year. The contraction in third-party contract drilling revenues reflects our increased net position in current drilling initiatives.

Production revenues in the second quarter of 2007 reflect a 6% increase in production output to 769.4 Mmcfe, along with a 9% increase in our average sales price of natural gas (before certain transportation charges) to $8.54 per Mcf. We anticipate ongoing production gains as we continue to upgrade our infrastructure and bring wells on stream in Leatherwood and other key fields. Principal purchasers of our production are gas marketers and customers with transmission facilities near our producing properties. Approximately 45% of our natural gas production in the second quarter of 2007 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.

Gas transmission and compression revenues were driven by fees totaling $983,251 for moving third-party gas through our NGAS Gathering system, which we acquired in March 2006. This component of revenues also reflects additional fees for gathering and compression of third-party gas production through our field-wide facilities, together with contributions of $52,946 from gas utility sales and $89,582 from our minority interest in the gathering system that services our Arkoma CBM project.

Expenses. The following table shows the components of our direct and other expenses for the three months ended June 30, 2007 and 2006. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.


	Three Months Ended June 30,
	2007		Margin			2006		Margin
Direct Expenses:

Contract drilling	$	5,919,020		21	%	$	7,840,559		29	%
Oil and gas production		1,799,186		73			1,529,940		74
Gas transmission and compression		779,843		59			541,869		61
Impairment of oil and gas assets		964,000		N/A			—		N/A


Total direct expenses		9,462,049		41			9,912,368		46


			% Revenue					% Revenue
Other Expenses:

Selling, general and administrative		3,042,364		19	%		3,164,516		17	%
Options, warrants and deferred compensation		329,177		2			419,787		2
Depreciation, depletion and amortization		2,361,176		15			1,964,578		11
Interest expense, net of interest income		1,484,527		9			987,546		5
Other, net		45,156		—			86,440		—


Total other expenses	$	7,262,400				$	6,622,867

Contract drilling expenses reflect both the level and complexity of drilling initiatives conducted through our sponsored programs. These expenses decreased by 25% on a period-over-period basis and represented 79% of contract drilling revenues in the second quarter of 2007, compared to 71% in the same quarter last year. The contraction in this sector reflects a reduction in our reliance on sponsored programs for developing our core operated properties, and the margins reflect our transition from turnkey to cost-plus pricing, which we implemented last year to address price volatility for drilling services, equipment and steel casing requirements. We expect these margins to stabilize from ongoing cost-plus drilling program operations.

Production expenses for the current quarter were consistent with the increase in our production volumes. In addition to lifting costs, production expenses include field operating and maintenance costs, related overhead, third-party transportation fees and lease operating expenses. As a percentage of oil and gas production revenues, our production expenses were 27% in the second quarter of 2007, compared to 26% in the year-earlier period.

Gas transmission and compression expenses in the second quarter of 2007 were 41% of associated revenues, compared to 39% 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 in March 2006. Our gas transmission and compression expenses do not reflect our acquisition costs for that system or capitalized costs of approximately $1.5 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.

In the second quarter of 2007, we expensed all of the suspended exploratory well costs for the remaining 27 wells in a 30-well program we began late in 2005 to test the New Albany shale formation on the eastern rim of the Illinois basin in western Kentucky. This resulted in an impairment charge of $964,000 in the carrying value of our position during the current quarter, in addition to a charge of $178,700 recognized for the first three wells in that program during 2006.

Selling, general and administrative (SG&A) expenses are comprised primarily of promotional costs for our sponsored drilling programs and overhead costs for supporting our expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses over the last several years. We anticipate lower variable SG&A expenses in future periods from the planned reduction in our reliance on drilling programs for developing our properties.

Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options, which we adopted in 2004. 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 $145,802 for deferred compensation cost.

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, including our acquisition of the NGAS Gathering transmission system for $18 million in March 2006.

Interest expense for the second quarter of 2007 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 second quarter of 2007 represents future tax liability at the operating company level. Although we have no current tax liability due to the utilization of intangible drilling costs allocated from our active drilling programs, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level.

Net Income and EPS. We recognized a net loss of $760,424 in the second quarter of 2007, compared to net income of $722,953 in the same quarter last year, reflecting the foregoing factors. Basic earnings (loss) per share (EPS) was $(0.03) based on 21,798,607 weighted average common shares outstanding in the current quarter, compared to EPS of $0.03 based on 21,456,828 weighted average common shares outstanding in the second quarter of 2006.

Results of Operations – Six Months Ended June 30, 2007 and 2006

Revenues. The following table shows the components of our revenues for the six months ended June 30, 2007 and 2006, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.


	Six Months Ended June 30,
			% of					%
	2007		Revenue			2006		Change
Revenue:

Contract drilling	$	16,704,923		49	%	$	31,440,774		(47	)%
Oil and gas production		13,483,179		40			12,139,967		11
Gas transmission and compression		3,834,980		11			2,078,156		85

Total	$	34,023,082		100	%	$	45,658,897		(25	)

Contract drilling revenues reflect the size and timing of our drilling program financings, as well as our percentage interest in drilling initiatives conducted through sponsored programs. We participated in 106 gross (45.4965 net) wells in the first six months of 2007, compared to 128 gross (30.3779 net) wells in the same period last year. The contraction in third-party contract drilling revenues reflects our increased net position in current drilling initiatives.

Our growth in production revenues on a period-over period basis reflects an increase of 11% in production volumes to 1,547.7 Mmcfe in the first six months of 2007, along with a slight increase in our average sales price of natural gas (before certain transportation charges) to $8.58 per Mcf. Our volumetric growth was driven by added production from wells brought on line in the last twelve months. We anticipate ongoing production gains as we continue to upgrade our infrastructure and bring wells on stream in Leatherwood and other key fields. Principal purchasers of our production are gas marketers and customers with transmission facilities near our producing properties. Approximately 45% of our natural gas production in the first six months of 2007 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices.

Gas transmission and compression revenues were driven by fees totaling $1,877,331 for moving third-party gas through our NGAS Gathering system, which we acquired in March 2006. This component of revenues also reflects additional fees for gathering and compression of third-party gas production through our field-wide facilities, together with contributions of $190,942 from gas utility sales and $150,302 from our minority interest in the gathering system that services our Arkoma CBM project.

Expenses. The following table shows the components of our direct and other expenses for the six months

ended June 30, 2007 and 2006. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.


	Six Months Ended June 30,
	2007		Margin			2006		Margin
Direct Expenses:

Contract drilling	$	13,099,737		22	%	$	24,543,489		22	%
Oil and gas production		3,482,200		74			2,983,408		75
Gas transmission and compression		1,879,436		51			1,174,298		43
Impairment of oil and gas assets		964,000		N/A			—		N/A


Total direct expenses		19,425,373					28,701,195		37


			% Revenue					% Revenue
Other Expenses:

Selling, general and administrative		7,064,246		21	%		7,638,908		17	%
Options, warrants and deferred compensation		670,300		2			848,534		2
Depreciation, depletion and amortization		4,667,646		14			3,502,490		8
Interest expense, net of interest income		2,625,229		8			1,469,569		3
Other, net		137,905		—			127,388		—


Total other expenses	$	15,165,326				$	13,586,889

Contract drilling expenses reflect both the level and complexity of drilling initiatives conducted through our sponsored programs. These expenses decreased by 47% on a period-over-period basis and represented 78% of contract drilling revenues in both periods. The contraction in this sector reflects a reduction in our reliance on sponsored programs for developing our operated properties, and the margins reflect our transition from turnkey to cost-plus pricing for these programs, which reduces our exposure to price volatility for drilling services, equipment and steel casing requirements.

Production expenses for the first half of 2007 were consistent with our 11% volumetric growth. As a percentage of oil and gas production revenues, our production expenses were 26% in the first six months of 2007, compared to 25% in the year-earlier period.

Gas transmission and compression expenses in the first six months of 2007 were 49% of associated revenues, compared to 57% in the same period last year, reflecting substantial revenue growth from third-party fees generated by the NGAS Gathering system acquired in March 2006. Our gas transmission and compression expenses do not reflect our acquisition costs for that system or capitalized costs of approximately $3.5 million in the current period for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

During the current period, we expensed the suspended exploratory well costs for 27 wells in a 30-well program we began late in 2005 to test the New Albany shale formation on the eastern rim of the Illinois basin in western Kentucky. This resulted in an impairment charge of $964,000 in the carrying value of our oil and gas assets during the current period, in addition to a charge of $178,700 recognized for the first three wells in that program during 2006.

SG&A expenses primarily reflect the timing and extent of our selling and promotional costs for sponsored drilling programs, as well as higher costs for supporting expanded operations as a whole, including additions to our staff. technology infrastructure and employee related expenses over the last few years.

The increase in DD&A charges for the current period reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment, including our acquisition of the NGAS Gathering transmission system for $18 million in March 2006.

Interest expense for the first six months of 2007 increased from higher overall bank borrowings. Draws under our credit facility during the current period were used primarily to support our ongoing drilling and gas gathering initiatives.

Deferred income tax expense recognized in the first six months of 2007 represents future tax liability at the operating company level. Although we have no current tax liability due to the utilization of intangible drilling costs allocated from our active drilling programs, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level.

Net Income and EPS. We recognized a net loss of $1,014,688 in the first six months of 2007, compared to net income of $1,348,690 in the same period last year, reflecting the foregoing factors. Basic EPS was $(0.05) based on 21,794,843 weighted average common shares outstanding in the current period, compared to EPS of $0.06 based on 21,417,395 weighted average common shares outstanding in the first six months of 2006.

The results of operations for the three months and six months ended June 30, 2007 are not necessarily indicative of results to be expected for the full year.

Liquidity and Capital Resources

Liquidity. Net cash of $4,078,984 was used in operating activities for the first six months of 2007. During the period, we used $26,512,983 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 $19,032,010 from financing activities. As a result of these activities, net cash decreased from $14,431,977 at December 31, 2006 to $2,872,020 at June 30, 2007.

As of June 30, 2007, we had a working capital deficit of $3,360,432. This reflects wide fluctuations in our current assets and liabilities from the timing of customers’ deposits and expenditures under drilling contracts with our sponsored programs. Since these fluctuations are normalized over relatively short time periods, we generally do not consider working capital to be a reliable measure of liquidity. The working capital deficit at the end of the reported period 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 developing existing oil and gas reserves, but also on our ability to find or acquire additional reserves on terms that are economically and operationally advantageous. To fund our ongoing reserve development and acquisition activities, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities, as well as participation by outside investors in our sponsored drilling programs.

In December 2005, we completed an institutional private placement of our 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. We also issued warrants in the transaction, which expired unexercised in August 2006. At June 30, 2007, all of the notes remained outstanding but were recorded at $35,780,352, reflecting an initial allocation of $2,394,913 for their equity components, which was ratably accreted by $176,426 in the first six months of 2007 and $432,893 in 2006, along with $565,946 reallocated to debt upon expiration of the warrants last year.

The notes are convertible by their holders into our common stock at a conversion price of $14.34 per share, subject to adjustments for certain dilutive issuances of common stock. If a holder elects to convert a note before the second anniversary of the issuance date, unless the prevailing market price of our common stock exceeds 160% of the conversion price, the holder will be entitled to a payment equal to the difference between two years’ interest on the converted note and the interest already paid on the note, payable at our option in cash or in common shares. After that date, if the prevailing market price of our common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at a redemption price equal to their principal amount plus accrued and unpaid interest. Upon any event of default or any change of control, the notes are redeemable at the option of the holders in cash at a default rate equal to 125% of their principal amount or at a change of control rate equal to the greater of 110% of their principal amount or 110% of the consideration that would be received by the holder 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. Any common shares issued for interest payments on converted notes or upon redemption at their maturity will generally be valued for that purpose at 92.5% of their prevailing market price.

In September 2006, we entered into a credit agreement with KeyBank National Association, as agent and primary lender. The credit agreement provides us with a senior secured revolving credit facility that replaces our prior credit facility with KeyBank, which had a scheduled maturity date of July 30, 2007 and a borrowing base of $35 million. The new facility has a five-year maturity for revolving term loans and letters of credit in an aggregate amount up to $125 million. Our current borrowing base is $65 million, reflecting an increase of $15 million during the second quarter of 2007. The facility is secured by liens on our interests in most of our Appalachian wells. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from 1.5% to 2.5% above quoted LIBOR rates, depending on the amount of borrowing base utilization, plus commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As of June 30, 2007, our borrowings under the facility aggregated $50 million, plus $2 million in outstanding letters of credit.

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 continue attracting investment capital for drilling programs. 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. This dependence can be expected to increase from our plan to limit our use of future drilling programs to participation in developing non-operated properties.

Contractual Obligations and Commercial Commitments

We are parties to leases for office facilities and various types of equipment. We are also obligated to make payments at specified times and amounts under instruments governing our long term debt and other commercial commitments. The following table lists our minimum annual commitments as of June 30, 2007 under these instruments.


	Operating Leases						Other			Long Term
Year	Equipment		Premises		Total		Commitments			Debt
Remainder of 2007	$	892,484	$	126,049	$	1,018,533	$	240,000	⁽¹⁾	$	12,000
2008		1,899,588		21,008		1,920,596		100,000	⁽²⁾		24,000
2009		1,776,054		—		1,776,054		2,045,000	⁽²⁾		24,000
2010		1,706,974		—		1,706,974		—			35,804,352	⁽³⁾
2011 and thereafter		1,847,021		—		1,847,021		—			50,246,818

Total	$	8,122,121	$	147,057	$	8,269,178	$	2,385,000		$	86,111,17


(1)		Reflects obligations under a guaranty secured by a certificate of deposit provided for bank debt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held a minority interest.

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

(3)		Excludes an allocation of $1,219,648 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 make estimates and judgments

that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, management evaluates its estimates, including evaluations of any allowance for doubtful accounts and impairment of long-lived assets. Management bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. The results of these evaluations form a basis for making judgments 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 its estimates are reasonable and that actual results will not vary significantly from the estimated amounts.

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.

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.

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. Our annual report on Form 10-K for the year ended December 31, 2006 includes a discussion of these risk factors. 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

Not applicable.

Item 4. Controls and Procedures

Our management, with the participation or under the supervision of our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting for the Company in accordance with the requirements of the Securities Exchange Act of 1934. Our disclosure controls and procedures are intended to provide a framework for making sure that all information required to be disclosed in our current and periodic reports under the Exchange Act is processed and publicly reported by us within the prescribed time periods for our filing of those reports. Our internal controls over financial reporting are designed to ensure the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. They include policies and procedures for maintaining reasonably detailed records that accurately and fairly reflect all our business transactions and dispositions of assets, for ensuring that receipts and expenditures are made only in accordance with management authorizations and for preventing or timely detecting any unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of our disclosure controls and procedures and our internal control over financial reporting as of June 30, 2007. Based on their evaluation, they 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 period required under the Exchange Act. They have also concluded that our internal controls over financial reporting are effective to ensure the reliability of our financial reporting and the preparation of our publicly reported financial statements in accordance with generally accepted accounting principles. There

were no changes in our controls or procedures during the three months or six months ended June 30, 2007 that have materially affected or are reasonably likely to materially affect our internal control of financial reporting.

PART II. OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders

At our 2007 annual meeting of shareholders, all of the incumbent directors were reelected. The number of votes cast for and against each nominee is set forth below.


			Votes
Nominee	Votes For		Withheld
William S. Daugherty		17,907,787		132,531
Charles L. Cotterell		17,852,028		188,290
James K. Klyman		17,771,808		268,510
Thomas F. Miller		17,890,072		150,246

Our shareholders also voted at the meeting to approve proposals to fix the size of our board of directors for the ensuing year at four members and to ratify the board’s appointment of Hall, Kistler & Company LLP as our auditors for 2007. The number of votes cast for and against each of these proposals is set forth below.


			Votes		Broker
Proposal	Votes For		Against		Nonvotes
Fixing the size of the board of directors at four members		17,613,523		378,626		48,167
Ratification of the appointment of independent public accountants		17,944,380		—		95,938

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,


*Exhibit*
*Number*		*Description of Exhibit*

		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		Securities Purchase Agreement dated as of December 13, 2005 among NGAS Resources, Inc. and the investors named therein (incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated December 14, 2005).

10.6		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).

10.7		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).

10.8		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 March 31, 2004).

10.9		Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).

10.10		Form of Long Term Incentive Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.11 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).

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: August 7, 2007	By:	/s/ William S. Daugherty
		William S. Daugherty
		Chief Executive Officer (Duly Authorized Officer) (Principal Executive Officer)

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade V good

Ngas Resources (NGAS) Inactive 10-Q2007 Q2 Quarterly report

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