UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 1 TO

FORM 10-Q

þ		QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

NGAS Resources, Inc.

(Exact name of registrant as specified in its charter)

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

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

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

     Indicate by check mark if the registrant has submitted electronically and posted on its corporate website every indicative data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

     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 under the Exchange Act).

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

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

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

Title of Class		Outstanding at November 1, 2009
Common Stock		30,484,361

 

 

NGAS Resources, Inc.

INDEX TO FORM 10-Q/A

Part I. Financial Information

		Page
Item 1. Financial Statements:
Condensed Consolidated Balance Sheets — September 30, 2009 (unaudited) and December 31, 2008			1
Condensed Consolidated Statement of Operations — Three months and nine months ended September 30, 2009 (restated) and 2008			2
Condensed Consolidated Statement of Cash Flows — Three months and nine months ended September 30, 2009 (restated) and 2008			3
Notes to Condensed Consolidated Financial Statements			4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			11
Item 3. Quantitative and Qualitative Disclosures about Market Risk			22
Item 4. Controls and Procedures			22
EX-31.1
EX-31.2
EX-32.1

Additional Information

     We file annual, quarterly and other reports and information with the Securities Exchange Commission. Promptly after their filing, we provide access to these reports without charge on our website at www.ngas.com. Our principal and administrative offices are located in Lexington, Kentucky. Our common stock is traded on the Nasdaq Global Select Market under the symbol NGAS. Unless otherwise indicated, references in this report to the company or to we, our or us include NGAS Resources, Inc., our direct and indirect wholly owned subsidiaries and our interests in sponsored drilling partnerships. As used in this report, Dth means decatherm, MMBtu means million British thermal units, Mcf means thousand cubic feet, Mcfe means thousand cubic feet of natural gas equivalents, Mmcf means million cubic feet, Bcf means billion cubic feet and EUR means estimated ultimately recoverable volumes of natural gas or oil.

Explanatory Note

     This amended report (10-Q/A) modifies some of the disclosures in our quarterly report on Form 10-Q for the quarter ended September 30, 2009 (10-Q) in response to review comments by the staff of the SEC. The 10-Q/A restates Part I of the 10-Q in its entirety but does not change any disclosures except as noted below, and it does not update the 10-Q to reflect any other developments or events after the date of the original filing.

•

Condensed Consolidated Financial Statements – The condensed consolidated financial statements have been restated to account for the embedded conversion feature of our 6% convertible notes as a derivative liability under ASC 815-40-15 (formerly EITF 07-5), which became effective as of January 1, 2009. The impact of the change in accounting principles is set forth in Note 2 — Restatement Adjustments.

•

MD&A – The recognition of non-cash interest expense for accretion of the debt discount and related adjustments from the change in accounting principles are reflected under the caption “Results of Operations.”

•

Certifications – The certifications in the exhibits to the 10-Q have been updated as the date of this 10-Q/A.

NGAS Resources, Inc.

		September 30,				December 31,
		2009				2008
		(Unaudited)
ASSETS
Current assets:
Cash		$	970,467			$	981,899
Accounts receivable			5,372,800				10,450,173
Note receivable			6,124,570				—
Prepaid expenses and other current assets			869,224				540,253
Loans to related parties			76,024				79,188
Total current assets			13,413,085				12,051,513
Bonds and deposits			258,695				623,898
Note receivable			8,375,430				—
Oil and gas properties			181,158,605				229,218,344
Property and equipment			5,278,048				3,285,925
Loans to related parties			171,429				171,429
Deferred financing costs			1,439,399				1,689,580
Goodwill			313,177				313,177
Total assets		$	210,407,868			$	247,353,866
LIABILITIES
Current liabilities:
Accounts payable		$	5,092,604			$	12,362,092
Accrued liabilities			619,117				675,141
Deferred compensation			—				2,246,439
Customer drilling deposits			2,621,671				2,262,955
Long-term debt			88,643				24,000
Total current liabilities			8,422,035				17,570,627
Deferred compensation			497,650				—
Deferred income taxes			13,520,833				12,949,476
Long-term debt			68,860,828				109,270,818
Fair value of derivative financial instruments			10,360				—
Other long-term liabilities			4,163,766				3,685,849
Total liabilities			95,475,472				143,476,770
SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
30,484,361 Common shares (2008 — 26,543,646)			117,142,639				110,626,912
21,100 Common shares held in treasury, at cost			(23,630	)			(23,630	)
Paid-in capital — options and warrants			4,336,463				3,774,600
To be issued:
9,185 Common shares (2008 — 9,185)			45,925				45,925
			121,501,397				114,423,807
Deficit			(6,569,001	)			(10,546,711	)
Total shareholders’ equity			114,932,396				103,877,096
Total liabilities and shareholders’ equity		$	210,407,868			$	247,353,866

See accompanying notes.

NGAS Resources, Inc.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
REVENUE
Contract drilling		$	3,831,250			$	9,799,561			$	16,328,000			$	24,027,035
Oil and gas production			6,239,324				11,222,879				20,198,187				30,891,933
Gas transmission, compression and processing			1,123,921				2,567,852				6,528,132				7,662,504
Total revenue			11,194,495				23,590,292				43,054,319				62,581,472
DIRECT EXPENSES
Contract drilling			2,913,418				7,570,698				12,328,110				18,447,544
Oil and gas production			2,658,985				3,922,629				7,598,044				9,794,679
Gas transmission, compression and processing			960,879				1,039,597				2,955,204				3,087,391
Total direct expenses			6,533,282				12,532,924				22,881,358				31,329,614
OTHER EXPENSES (INCOME)
Selling, general and administrative			2,601,514				3,551,908				8,404,519				10,282,485
Options, warrants and deferred compensation			285,309				229,209				1,022,774				601,691
Depreciation, depletion and amortization			3,304,139				3,318,320				10,610,630				9,451,272
Bad debt expense			—				342,195				—				749,035
Interest expense			2,196,091				1,457,300				6,892,550				4,138,913
Interest income			(52,698	)			(10,774	)			(67,708	)			(89,577	)
Gain on sale of assets			(3,356,177	)			—				(3,369,082	)			—
Fair value (gain) loss on derivative financial instruments			4,847				—				(4,477	)			—
Other, net			292,073				87,584				600,896				115,939
Total other expenses			5,275,098				8,975,742				24,090,102				25,249,758
INCOME (LOSS) BEFORE INCOME TAXES			(613,885	)			2,081,626				(3,917,141	)			6,002,100
INCOME TAX EXPENSE			508,116				1,136,441				571,357				3,372,464
NET INCOME (LOSS)		$	(1,122,001	)		$	945,185			$	(4,488,498	)		$	2,629,636
NET INCOME (LOSS) PER SHARE
Basic		$	(0.04	)		$	0.04			$	(0.16	)		$	0.10
Diluted		$	(0.04	)		$	0.04			$	(0.16	)		$	0.10
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic			28,873,105				26,508,570				27,508,925				26,364,158
Diluted			28,873,105				26,977,438				27,508,925				27,019,313

See accompanying notes.

NGAS Resources, Inc.

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
OPERATING ACTIVITIES
Net income (loss)		$	(1,122,001	)		$	945,185			$	(4,488,498	)		$	2,629,636
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Incentive bonus paid in common shares			65,001				228,120				426,251				259,690
Options, warrants and deferred compensation			285,309				229,209				1,022,774				601,691
Depreciation, depletion and amortization			3,304,139				3,318,320				10,610,630				9,451,272
Bad debt expense			—				342,195				—				749,035
Gain on sale of assets			(3,356,177	)			(10,761	)			(3,369,082	)			(11,116	)
Fair value (gain) loss on derivative financial instruments			4,847				—				(4,477	)			—
Accretion of debt discount			1,004,682				—				2,869,276				—
Deferred income taxes			508,116				1,136,441				571,357				3,372,464
Changes in assets and liabilities:
Accounts receivable			311,360				(1,840,648	)			5,077,373				(5,983,968	)
Prepaid expenses and other current assets			(353,376	)			(345,152	)			(328,971	)			(227,538	)
Other non-current assets			—				—				—				3,242,790
Accounts payable			(144,533	)			2,979,900				(7,269,488	)			3,684,584
Accrued liabilities			(46,040	)			261,981				(56,024	)			469,599
Deferred compensation			(2,094,700	)			—				(2,209,700	)			—
Customers’ drilling deposits			1,923,271				(1,630,304	)			358,716				(2,857,806	)
Other long-term liabilities			155,091				—				477,917				—
Net cash provided by operating activities			444,989				5,614,486				3,688,054				15,380,333
INVESTING ACTIVITIES
Proceeds from sale of assets			35,857,613				15,855				35,911,646				54,555
Purchase of property and equipment			(195,261	)			(155,170	)			(2,683,061	)			(459,671	)
Change in bonds and deposits			5,000				(95,250	)			15,203				(130,750	)
Additions to oil and gas properties, net			(3,841,799	)			(11,615,165	)			(7,918,894	)			(37,940,322	)
Net cash provided by (used in) investing activities			31,825,553				(11,849,730	)			25,324,894				(38,476,188	)
FINANCING ACTIVITIES
Decrease in loans to related parties			890				1,861				3,164				4,538
Proceeds from issuance of common shares			6,089,476				81,200				6,089,476				1,190,006
Payments of deferred financing costs			(10,882	)			(297,440	)			(383,442	)			(440,983	)
Proceeds from issuance of long-term debt			—				5,500,000				—				22,240,000
Payments of long-term debt			(45,021,578	)			(6,000	)			(34,733,578	)			(2,032,175	)
Net cash provided by (used in) financing activities			(38,942,094	)			5,279,621				(29,024,380	)			20,961,386
Change in cash			(6,671,552	)			(955,623	)			(11,432	)			(2,134,469	)
Cash, beginning of period			7,642,019				1,637,832				981,899				2,816,678
Cash, end of period		$	970,467			$	682,209			$	970,467			$	682,209
SUPPLEMENTAL DISCLOSURE
Interest paid		$	1,204,354			$	1,456,786			$	4,026,548			$	4,138,104
Income taxes paid			—				—				—				—

See accompanying notes.

NGAS Resources, Inc.

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 (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, 2008. 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 39 drilling partnerships sponsored to participate in many of our drilling initiatives. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References to the company, we, our or us include DPI, its subsidiaries and interests in sponsored drilling partnerships. These interim consolidated financial statements are unaudited and have been restated for the three months and nine months ended September 30, 2009 to reflect the adoption of Accounting Standards Codification (ASC) Topic 815-40-15, Contracts in Entity’s Own Equity (formerly EITF 07-5), which became effective as of January 1, 2009. See Note 2 — Restatement Adjustments. In the opinion of our management, the accompanying condensed consolidated financial statements reflect all normal recurring adjustments that, in the opinion of our management, are necessary to fairly present our financial position at September 30, 2009 and results of operations and cash flows for the three months and nine months ended September 30, 2009 and 2008.

     (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 appropriate to reflect losses that could result from payment failures by our customers or counterparties. The evaluations required for these estimates involve significant uncertainties, and actual results could differ from the estimates.

Note 2. Restatement Adjustments

     (a) Change in Accounting Principle. Effective as of January 1, 2009, we adopted the revised guidance for equity-linked financial instruments now codified in ASC 815-40-15, which requires the embedded conversion feature of our 6% convertible notes to be bifurcated and treated as a derivative liability based on its fair value as a stand-alone instrument. The notes were issued in December 2005 in the principal amount of $37 million. See Note 8 — Long-Term Debt. Under the revised guidance, the notes are no longer considered to be linked to our own stock due to the weighted average antidilution provisions in their embedded conversion feature. As a result, the notes no longer qualify for the scope exception from derivative fair value accounting under ASC 815-15, Derivatives and Hedging — Embedded Derivatives (formerly contained in SFAS 133).

     (b) Cumulative Effect Adjustments. The transition provisions of ASC 815-40-15 require cumulative effect adjustments as of January 1, 2009 to reflect the amounts that would have been recognized if derivative fair value accounting had been applied from the original issuance date of an equity-linked financial instrument through the implementation date of the revised guidance. Our fair value analysis of the notes reflects an initial derivative liability of $16,575,445 for their embedded conversion feature, primarily reflecting their five-year maturity and 10% conversion premium at issuance. From the note issuance date through the end of 2008, we would have recorded fair value gains on derivative financial instruments of $16,560,608, offset by non-cash interest expenses totaling $8,094,400, reflecting accretion of the debt discount under the effective interest method. The following table shows the cumulative effect adjustment to retained deficit at January 1, 2009.

		Retained Deficit
Cumulative Effect Adjustment:
As previously reported, December, 31, 2008		$	(10,546,711	)
Cumulative effect adjustment			8,466,208
As adjusted, January 1, 2009		$	(2,080,503	)

     (c) Impact on Interim Financial Statements. As restated at September 30, 2009, the carrying amount of our convertible notes has been recorded at $31,388,231. This reflects the unaccreted debt discount to their face amount of $37 million. In addition, a derivative liability has been established at $10,360, representing the fair value of the embedded conversion feature at the balance sheet date. The following table shows the adjustments on restatement of the condensed consolidated statements of operations previously reported for the three months and nine months ended September 30, 2009. The adjustments to interest expense reflect accretion of the debt discount under the effective interest method. The fair value gains on derivative financial instruments reflect mark-to market changes in the fair value of the embedded derivative.

		As Previously				Restatement				As
		Reported				Adjustments				Restated
Three Months Ended September 30, 2009:
Total revenue		$	11,194,495			$	—			$	11,194,495
Total direct expenses			6,533,282				—				6,533,282
Other expenses (income)
Selling, general and administrative			2,601,514				—				2,601,514
Options, warrants and deferred compensation			285,309				—				285,309
Depreciation, depletion and amortization			3,304,139				—				3,304,139
Interest expense			1,191,409				1,004,682				2,196,091
Interest income			(52,698	)			—				(52,698	)
Gain on sale of assets			(3,356,177	)			—				(3,356,177	)
Fair value loss on derivative financial instruments			—				4,847				4,847
Other, net			292,073				—				292,073
Total other expenses			4,265,569				1,009,529				5,275,098
Income (loss) before income taxes			395,644				—				(613,885	)
Income tax expense			508,116				—				508,116
Net loss		$	(112,472	)		$	(1,009,529	)		$	(1,122,001	)
EPS — basic and diluted		$	(0.00	)		$	(0.04	)		$	(0.04	)

		As Previously				Restatement				As
		Reported				Adjustments				Restated
Nine Months Ended September 30, 2009:
Total revenue		$	43,054,319			$	—			$	43,054,319
Total direct expenses			22,881,358				—				22,881,358
Other expenses (income)
Selling, general and administrative			8,404,519				—				8,404,519
Options, warrants and deferred compensation			1,022,774				—				1,022,774
Depreciation, depletion and amortization			10,610,630				—				10,610,630
Interest expense			4,023,274				2,869,276				6,892,550
Interest income			(67,708	)			—				(67,708	)
Gain on sale of assets			(3,369,082	)			—				(3,369,082	)
Fair value (gain) loss on derivative financial instruments			—				(4,477	)			(4,477	)
Other, net			600,896				—				600,896
Total other expenses			21,225,303				2,864,799				24,090,102
Loss before income taxes			1,052,342				(2,864,799	)			3,917,141
Income tax expense			571,357				—				571,357
Net loss		$	(1,623,699	)		$	(2,864,799	)		$	(4,488,498	)
EPS — basic and diluted		$	(0.06	)		$	(0.10	)		$	(0.16	)

Note 3. Oil and Gas Properties

     (a) Sale of Appalachian Gas Gathering Facilities. On July 15, 2009, we sold a 50% undivided interest in 485 miles of our Appalachian gas gathering facilities (Gathering System) to Seminole Gas Company, L.L.C. (Seminole) for $28 million. As part of the transaction, we entered into various joint ownership, gas marketing and gas sales arrangements with Seminole and its parent company, Seminole Energy Services, LLC (Seminole Energy). Under these arrangements, we retained operating rights for the Gathering System and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas through the system. We also granted Seminole Energy a six-month option to purchase our retained 50% interest in the Gathering System for $22 million, payable $7.5 million at closing and the balance over 30 months under a promissory note bearing interest at 8% per annum. See Note 5 — Note Receivable. We reserved the right to require Seminole Energy to exercise its purchase option, conditioned on our completion of an equity offering for at least $5 million. On August 17, 2009, after satisfying that condition, we closed the sale of our remaining interest in the Gathering System to Seminole Energy under the terms of its purchase option. See Note 10 - Capital Stock. All of our proceeds from the Gathering System sale were applied to debt reduction. See Note 9 — Long-Term Debt.

     (b) 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 September 30, 2009 and December 31, 2008 are summarized below. Capitalized costs and accumulated DD&A for our gathering system and well equipment at September 30, 2009 were reduced by $51,571,070 and $5,301,027, respectively, from our sale of the Gathering System during the third quarter of 2009.

		September 30,				December 31,
		2009				2008
Proved oil and gas properties		$	197,922,674			$	192,186,676
Unproved oil and gas properties			5,209,182				5,065,835
Gathering facilities and well equipment			17,421,334				67,326,445
			220,553,190				264,578,956
Accumulated DD&A			(39,394,585	)			(35,360,612	)
Net oil and gas properties and equipment		$	181,158,605			$	229,218,344

     (c) Suspended Well Costs. We had no suspended exploratory wells costs that were required to be expensed during 2008 or the first nine months of 2009 based on the criteria of FSP No. 19-1, Accounting for Suspended Well Costs.

Note 4. Property and Equipment

     The following table presents the capitalized costs and accumulated depreciation for our other property and equipment as of September 30, 2009 and December 31, 2008.

		September 30,				December 31,
		2009				2008
Land		$	12,908			$	12,908
Building improvements			64,265				64,265
Machinery and equipment			5,839,686				3,333,981
Office furniture and fixtures			175,862				175,862
Computer and office equipment			690,905				670,349
Vehicles			1,811,276				1,951,279
			8,594,902				6,208,644
Accumulated depreciation			(3,316,854	)			(2,922,719	)
Net other property and equipment		$	5,278,048			$	3,285,925

Note 5. Note Receivable

     As part of the purchase price for the Gathering System, we received a promissory note issued by Seminole Energy on August 17, 2009 in the original principal amount of $14.5 million. See Note 3 — Oil and Gas Properties. The note is payable in equal monthly installments through December 2011, with interest at 8% per annum. Performance of the note is secured by a second mortgage lien on Seminole Energy’s 50% interest in the Gathering System assets. We have assigned the note as part of the collateral package under our revolving credit facility and will apply all payments of principal and interest under the note to reduce our credit facility debt. See Note 9 — Long-Term Debt.

Note 6. Deferred Financing Costs

     Financing costs for our convertible notes and revolving credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 9 — 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 $1,439,399 at September 30, 2009 and $1,689,580 at December 31, 2008.

Note 7. Goodwill

     Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and was amortized over ten years on a straight-line basis until 2002, when we adopted the Canadian equivalent of Financial Accounting Standards (SFAS) No. 142, Goodwill and Other Intangible Assets. Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment at least annually. Our annual analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of September 30, 2009 and December 31, 2008, with unamortized goodwill of $313,177.

Note 8. Customer Drilling Deposits

     Net proceeds received under drilling contracts with sponsored partnerships and joint ventures are recorded as customer drilling deposits at the time of receipt. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. We had customer drilling deposits of $2,621,671 at September 30, 2009 and $2,262,955 at December 31, 2008, representing unapplied drilling contract payments for wells that were not yet drilled as of the balance sheet dates.

Note 9. Long-Term Debt

     (a) Convertible Notes. We have an outstanding series of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37 million. The notes are convertible into our common shares at a conversion price of $11.16, reflecting an anti-dilution adjustment from our registered direct placement in August 2009. See Note 10 — Capital Stock. Upon any event of default under the notes or any change of control, we may be required to redeem the notes at specified premiums above their face amount. Notes that are neither redeemed nor converted prior to maturity will be repayable in cash or common shares, valued for that purpose at 92.5% of their market price.

     (b) Credit Facility. We have a revolving credit facility maintained by DPI under a credit agreement with KeyBank National Association, as administrative agent. The facility provides for loans and letters of credit in an aggregate amount up to $125 million, with a scheduled maturity in September 2011. Credit availability under the facility is subject to borrowing base limits, as determined semi-annually by the lenders. Interest is payable at fluctuating rates ranging from the agent’s prime rate to 2.25% above that rate, 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 DPI’s oil and gas properties.

     As of September 30, 2009, we had outstanding borrowings of $35 million under the facility, with a borrowing base of $55 million. This reflects debt reductions totaling $41.5 million from proceeds of our Gathering System sale and equity raise in the third quarter of 2009 and a borrowing base reduction of $25 million in July 2009 from lower commodity prices and the release of our Gathering System assets from the collateral package. See Note 10 — Capital Stock. A related amendment to the credit agreement provides for the further debt reduction from payments under our note receivable issued by Seminole Energy as part of the purchase price for our Gathering System. See Note 5 — Note Receivable.

     (c) Installment Loan. In June 2009, DPI 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 the end of the term, unless extended by the bank. The loan is secured by a lien on the airplane and had an outstanding balance of $2,284,422 at September 30, 2009.

     (d) Acquisition Debt. We issued a note for $854,818 in 1986 to finance our 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. The outstanding acquisition debt was $276,818 at September 30, 2009.

     (e) Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at September 30, 2009, as restated, and December 31, 2008 and the principal payments due each year through 2013 and thereafter.

		Restated
		September 30,				December 31,
		2009				2008
Principal Amount Outstanding
Total long-term debt (including current portion)(1)		$	68,949,471			$	109,294,818
Less current portion			88,643				24,000
Total long-term debt		$	68,860,828			$	109,270,818

Maturities of Debt
Remainder of 2009		$	27,807
2010			31,477,828	(1)
2011			35,093,557
2012			2,157,461
2013 and thereafter			192,818

Note 10. Capital Stock

     (a) Preferred Shares. We have 5,000,000 authorized shares of preferred stock, none of which were outstanding at September 30, 2009 or December 31, 2008.

     (b) Common Shares. On August 13, 2009, we completed a registered direct placement of 3.48 million units under our existing shelf registration statement at $1.90 per unit. Each unit consists of one share of our common stock and a warrant to buy 0.5 common share. The following table reflects the direct placement and other transactions involving our equity securities during the reported periods.

		Number of
		Shares				Amount
Common Shares Issued
Balance, December 31, 2007			26,136,064			$	108,842,526
Issued to employees as incentive bonus			50,000				259,690
Issued upon exercise of stock options			357,582				1,524,696
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, September 30, 2009			30,484,361			$	117,142,639
Paid In Capital — Options and Warrants
Balance, December 31, 2007							3,484,148
Recognized							625,142
Exercised							(334,690	)
Balance, December 31, 2008							3,774,600
Recognized							561,863
Balance, September 30, 2009						$	4,336,463
Common Shares to be Issued
Balance, September 30, 2009 and December 31, 2008			9,185			$	45,925

     (c) Stock Options and Awards. We maintain three equity incentive plans for the benefit of our directors, officers, employees and certain consultants. The plans provide for the grant of options to purchase up to 3.6 million common shares and, in the case of our most recent plan, either stock awards or options for an aggregate of up to 4 million common shares. Stock awards under the third plan may be subject to restrictions, and option grants under all three plans must be at prevailing market prices and may be subject to vesting requirements. Stock awards were made for a total of 460,715 shares during the first nine months of 2009 and 50,000 shares during 2008. Transactions in stock options during those periods are shown in the following table.

										Weighted Average
		Issued				Exercisable				Exercise Price
Balance, December 31, 2007			2,681,250				1,739,583			$	4.75
Granted			2,300,000				—				2.93
Vested			—				41,667				6.02
Exercised			(357,582	)			(357,582	)			3.33
Forfeited			(10,000	)			(10,000	)			7.04
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, September 30, 2009			3,873,668				1,898,668				3.92

     At September 30, 2009, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, and their weighted average remaining contractual life was 3.06 years. The following table provides additional information on the terms of stock options outstanding at September 30, 2009.

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				1,650,000				5.61			$	1.51				—			$	—
	4.03				800,000				0.41				4.03				800,000				4.03
	6.02     7.64				1,423,668				1.61				6.66				1,098,668				6.70
					3,873,668												1,898,668

     In accounting for stock options, we apply the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment. 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 0.03% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from three months to six years based on the vesting provisions of the options. This resulted in non-cash charges for options and warrants of $625,142 in 2008 and $561,863 in the first nine months of 2009.

     (d) Common Stock Purchase Warrants. As part of our registered direct equity placement on August 13, 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 will be exercisable for four years, beginning six months after issuance.

Note 11. 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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
		Restated								Restated
Numerator:
Net income (loss) as reported for basic EPS		$	(1,122,001	)		$	945,185			$	(4,488,498	)		$	2,629,636
Adjustments to income (loss) for diluted EPS			—				—				—				—
Net income (loss) for diluted EPS		$	(1,122,001	)		$	945,185			$	(4,488,498	)		$	2,629,636
Denominator:
Weighted average shares for basic EPS			28,873,105				26,508,570				27,508,925				26,364,158
Effect of dilutive securities — options/warrants			—				468,868				—				655,155
Adjusted weighted average shares and assumed conversions for diluted EPS			28,873,105				26,977,438				27,508,925				27,019,313
Basic EPS		$	(0.04	)		$	0.04			$	(0.16	)		$	0.10
Diluted EPS		$	(0.04	)		$	0.04			$	(0.16	)		$	0.10

Note 12. Segment Information

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

Note 13. Commitments

     (a) General. We incurred operating lease expenses of $2,583,417 in 2008 and $2,024,745 in the first nine months of 2009. As of September 30, 2009, we had future obligations under operating leases in the amounts listed below.

Maturities of Lease Obligations
Remainder of 2009		$	604,704
2010			2,350,495
2011			2,095,224
2012			847,442
2013 and thereafter			73,284
Total		$	5,971,149

     (b) Gas Gathering and Sales Commitments. We have various long-term commitments under our gas gathering and sales agreements entered with Seminole and Seminole Energy in connection with our sale of the Gathering System during the third quarter of 2009. 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 Gathering System by Seminole and Seminole Energy. These agreements have an initial term of fifteen years with extension rights.

Note 13. Recent Accounting Standards

     SFAS No. 168. In July 2009, the FASB issued SFAS No. 168, Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. Effective for financial statements covering periods ending after September 15, 2009, the Codification changes the references to existing accounting pronouncements, superseding all prior accounting standards under U.S. GAAP, aside from those issued by the SEC. The guidance currently provided in the Codification has not had any impact on our consolidated financial statements.

     Oil and Gas Reporting Requirements. In December 2008, the SEC amended its oil and gas reporting rules under the Exchange Act and Industry Guides. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by aligning the oil and gas disclosure requirements with current industry practices and technology. The amendments will be effective for fiscal years ending on or after December 31, 2009 and will significantly impact reserve and resource reporting for all E&P companies.

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 portion of the Appalachian Basin. We have specialized for over 20 years in generating our own geological prospects in this region, where we have established expertise and recognition. During the last two years, we have successfully transitioned to horizontal drilling and extended 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 achieve sustained volumetric growth and strong financial returns on a long-term basis.

Recent Developments

          Liquidity from Gathering System Sale and Equity Raise. On July 15, 2009, we sold a 50% undivided interest in 485 miles of our Appalachian gas gathering facilities (Gathering System) to Seminole Gas Company, L.L.C. (Seminole) for $28 million. As part of the transaction, we entered into various gas marketing and gas sales arrangements with Seminole and its parent company, Seminole Energy Services, LLC (Seminole Energy). Under these arrangements, we retained operating rights for the Gathering System and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas, ensuring long-term deliverability for our Appalachian production through the system. We also granted Seminole Energy a six-month option to purchase our retained 50% interest in the Gathering System for $22 million, payable $7.5 million in cash and the balance over 30 months under a promissory note bearing interest at 8% per annum. We reserved the right to trigger the exercise of the purchase option, conditioned on our completion of a qualifying equity offering. On August 17, 2009, after satisfying that condition, we closed the sale of our remaining interest in the Gathering System to Seminole Energy under the terms of its purchase option. Proceeds of $35.5 million from the Gathering System sale and approximately $6.1 million from the equity raise were applied to debt reduction under our revolving credit facility. Liquidity from these transactions has provided us with greater flexibility to take advantage of our development opportunities.

          Expansion of Leatherwood Position. In October 2009, we expanded our position in our key Leatherwood field with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with participation rights for up to 50% of the working interest in wells drilled on the covered acreage and requires us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment. Combined with the farmout we acquired earlier in the year from Chesapeake Appalachia, LLC for a significant tract next to the Amvest portion of our Stone Mountain field in Letcher and Harlan Counties, Kentucky, this brings our holdings in the Appalachian Basin to a total of 339,000 gross (241,000 net) acres.

Business Strategy

          Over 70% of our properties in the Appalachian Basin are undeveloped, along with most of our assembled acreage in the Illinois Basin. Our business is structured for efficient development of these unconventional resource plays, which have been transformed by our use of horizontal drilling throughout our operating areas. We began this transition early in 2008 and had 20 horizontal wells on line at year-end, with an additional five horizontals producing to sales at the end of September 2009. Our success with these initiatives contributed to growth in our production volumes to 3.7 Bcfe in 2008, up 13% over 2007. Despite substantially reduced drilling activity this year, we produced 997 Mmcf of natural gas equivalents in the third quarter of 2009. This represents a 5% increase from the same quarter last year, but a 4% decline from record production volumes in the 2009 first quarter. Having strengthened our balance sheet with added liquidity in the third quarter, our extensive inventory of horizontal drilling locations positions us for future growth under a sustainable, low-cost structure with several components.

•

Organic Growth through Drilling with Reduced Capital Spending. While we are committed to a long-term strategy of developing our reserves through the drillbit and retaining most of our available working interest in new wells, we have addressed the challenging conditions in our industry by reducing our 2009 capital spending budget to $15 million and returning to our successful partnership structure for sharing development costs on operated properties. We raised over $34 million for a non-operated program last year through our established sales network. To meet our near-term drilling commitments and objectives, we are currently sponsoring a partnership to participate in up to 53 horizontal wells throughout our operated

		properties. The partnership commenced operations following an initial closing of its private placement in June 2009. We are maintaining a 20% interest in this year’s program and will earn an additional 15% reversionary interest after program payout.
•		Horizontal Drilling Initiatives. Recent advances in horizontal drilling and completion technology have enhanced the value proposition for our operated properties by substantially increasing our recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or challenging terrain. We focused these initiatives during 2008 in our Leatherwood field, where we completed 20 horizontal wells last year. Each well has a single lateral leg up to 3,500 feet through the Devonian shale formation, which is present throughout our Appalachian operating areas. Initial 30-day flow rates for our Leatherwood horizontals averaged 309 Mcf per day. We achieved comparable results for our first two New Albany shale horizontals drilled late in 2008 on our Illinois Basin acreage and our initial Devonian shale horizontals completed this year in our Straight Creek, Fonde and Martin’s Fork fields. We plan to continue this transition throughout our operated properties, including 25 horizontal wells planned this year in Leatherwood.
•		Advantages from Restructured Infrastructure Position. Although the sale of our Gathering System during the third quarter of 2009 eliminated the closed-access status for most of our field-wide infrastructure, we retained long-term capacity rights for the system, currently established at 30,000 Mcf per day. This ensures continued deliverability from our operated Appalachian properties serviced by these facilities. We also retained operating rights for the Gathering System, which provides deliverability from 90% of our Appalachian properties directly from the wellhead to major east coast natural gas markets through an interconnect with Spectra Energy Partners’ East Tennessee Interstate pipeline network. Our operating and capacity rights also preserve our competitive advantages from control of regional gas flow, enhancing our opportunities to acquire undeveloped acreage near our core producing fields upon completion of coal mining activities. We continue to own a 50% interest in a liquids extraction plant for production serviced by the Gathering System, located in Rogersville, Tennessee. This is within 5.5 miles of the proposed site for a 880-megawatt gas-fired power plant to be constructed by the Tennessee Valley Authority, which may provide us with opportunities for long-term gas sales arrangements.

Drilling Operations

          General. As of September 30, 2009, we had interests in over 1,400 wells, concentrated on our Appalachian properties. We believe our long and successful operating history and proven ability to drill a large number of wells year after year have positioned us as a leading producer in this region. Historically, we conducted most of our drilling operations through sponsored drilling partnerships with outside investors, enabling us to assemble our acreage positions on the strength of our drilling commitments, while also funding infrastructure development on acquired acreage for our own account. Beginning in the second half of 2007, with our core Appalachian infrastructure in place, we changed our business model to limit our use of drilling partnerships to participation in non-operated plays, retaining all of our available working interest in wells drilled on operated properties through the end of 2008. To address part of the capital requirements for meeting this year’s drilling commitments and objectives, we are sponsoring a drilling partnership for up to $53.1 million to participate in our horizontal wells during 2009 and the first quarter of 2010. The partnership commenced operations in June 2009 following the initial closing of its private placement.

          Geological Factors. 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. Most of our vertical wells in this region were drilled to relatively shallow total depths averaging 4,500 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout our Appalachian acreage is the Devonian shale formation. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance natural fracturing in these reservoirs. Estimated ultimately recoverable volumes (EURs) of natural gas reported for vertical gas wells in this part of Appalachia range between 100 to 450 Mmcf, with modest initial volumes offset by low annual decline rates, resulting in a reserve life index of over 25 years. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

          Horizontal Drilling. Air-driven horizontal drilling advances and staged completion technology optimized for our operating areas have dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. In general, our horizontal wells use directional air drilling to create a lateral leg up to 3,500 feet through the target formation. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation than conventional vertical wells. While up to four times more expensive than vertical wells, horizontal drilling is improving overall performance by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells. Typically, one horizontal well replaces between three to four vertical locations, reducing the total footprint by drilling fewer wells. Additional economies are being achieved with multiple horizontal wells on a single drilling location. In addition to these operational advantages, the initial recovery rates for our horizontals are averaging six to eight times the rates for vertical Devonian shale wells in the same fields. Although not fully reflected in our 2008 year-end reserve estimates, we anticipate substantial upside in both production and EURs from our ongoing transition to horizontal drilling.

          Staged Completion Technology. Upon completion of drilling the lateral leg of our horizontal wells, we run 4.5-inch casing and packers to the end of the leg. The packers are set at intervals, allowing the well to be completed in up to eight separate stages within the horizontal leg. A staged treatment process is then performed on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally over one-million standard cubic feet per stage. After the well is blown back for approximately seven days, it is connected to our existing field-wide gathering facilities to commence gas sales.

          New Albany Shale Play. In addition to the recent expansion of our Leatherwood acreage and our Chesapeake farmout, we are continuing to develop our New Albany shale play within the southcentral portion of the Illinois Basin in western Kentucky. We began producing this project to sales in September 2008 upon completion of our gas gathering and processing infrastructure for the acreage, with a total of 33 wells on line at September 30, 2009. Based on encouraging results from our New Albany shale horizontals, we have expanded our lease position and plan to drill up to five horizontal wells on this acreage through our 2009 drilling partnership.

          Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2008 and the first nine months of 2009. Drilling results shown in the table for 2008 include 55 gross (24.18 net) wells that were drilled by year-end but were awaiting installation of gathering lines or extensions prior to completion, primarily on non-operated properties. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may subsequently earn in wells drilled through our sponsored drilling programs.

		Development Wells												Exploratory Wells
		Productive								Dry				Productive								Dry
		Gross				Net				Gross				Gross				Net				Gross
Year Ended December 31, 2008
Vertical			137				58.8522				—				9				8.8125				—
Horizontal			47				15.7254				—				—				—				—
Total			184				74.5776				—				9				8.8125				—
Nine Months Ended September 30, 2009
Vertical			10				1.6972				—				—				—				—
Horizontal			14				2.7588				—				—				—				—
Total			24				4.4560				—				—				—				—

Producing Activities

          Regional Advantages. Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian Basin. The proximity of this region to major east coast gas markets reduces our transportation costs, generating realization premiums above Henry Hub spot prices and contributing to long-term returns on investment. Our Appalachian gas production also has the advantage of a high energy content (Dth), ranging from 1.1 to 1.3 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1 Dth per Mcf, this resulted in realized premiums averaging 17% over normal pipeline quality gas.

          Liquids Extraction. During 2007, in response to regulatory tariffs limiting the upward range of pipeline throughput to 1.1 Dth per Mcf, we constructed a processing plant with Seminole Energy in Rogersville, Tennessee for liquids extraction from our Appalachian production delivered through the Gathering System. The plant was brought on line in February 2008, ensuring our compliance with the new energy content standard. Sales of extracted natural gas liquids (NGL) have partially offset the reduction in energy-related yields from our Appalachian gas production. In addition, our margins for sales of extracted NGL have benefited from lower hauling costs achieved through recently implemented rail shipping arrangements.

          Oil and Gas Production. Our production revenues and estimated oil and gas reserves are substantially dependent on prevailing market prices for natural gas, which comprised 78% of our proved reserves on an energy equivalent basis at the end of 2008. The following table shows the average sales prices for our natural gas, crude oil and NGL production during 2008 and the interim reporting periods.

		Three Months Ended								Nine Months Ended								Year Ended
		September 30,								September 30,								December 31,
		2009				2008				2009				2008				2008
Production volumes:
Natural gas (Mcf)			816,393				760,401				2,521,223				2,268,929				3,087,596
Oil (Bbl)			11,887				16,235				37,313				44,718				57,291
Natural gas liquids (gallons)			1,458,541				1,202,292				3,895,199				2,930,974				3,895,649
Equivalents (Mcfe)			997,103				947,986				3,037,238				2,778,668				3,745,124
Average sales prices:
Natural gas (per Mcf)		$	5.67			$	9.80			$	6.31			$	9.40			$	8.89
Oil (per Bbl)			60.76				110.26				48.03				106.06				95.07
Natural gas liquids (per gallon)			0.61				1.65				0.64				1.64				1.41

          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 hedging activities 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 natural gas production for each quarter of 2010 and the fourth quarter of 2009.

Fixed-Price Contracts for Natural Gas Production

		2009				2010
		Q4				Q1				Q2				Q3				Q4
Percentage of gas contracted			54	%			58	%			46	%			51	%			47	%
Average price per Mcf		$	7.83			$	7.54			$	6.42			$	6.51			$	6.56

Results of Operations — Three Months Ended September 30, 2009 and 2008

          Revenues. The following table shows the components of our revenues for the three months ended September 30, 2009 and 2008, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.

		Three Months Ended September 30,
						% of								%
		2009				Revenue				2008				Change
Revenue:
Contract drilling		$	3,831,250				34	%		$	9,799,561				(61	)%
Oil and gas production			6,239,324				56				11,222,879				(44	)
Gas transmission, compression and processing			1,123,921				10				2,567,852				(56	)
Total		$	11,194,495				100	%		$	23,590,292				(53	)

          Our total revenues for the third quarter of 2009 reflect the impact of declining commodity prices, reduced drilling activity and our sale of the Gathering System. In view of our reduction in capital expenditures for 2009, we do not expect this trend to reverse without a significant recovery in commodity prices and an increase in the level of drilling activity, which is directly linked to partnership sales under our current business model. Although sales of partnership interests are typically concentrated in the fourth quarter, they may continue to be impacted this year by the challenging economic environment.

          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 customers’ drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. Our contract drilling revenues in the third quarter of 2009 reflect continued operations of our 2009 drilling partnership, which participated in six horizontal wells during the quarter. We plan to drill a total of up to 53 horizontals on our operated properties though that program, depending on the level of partnership participation.

          Production revenues for the third quarter of 2009 reflect an increase of 5% in production output to 997 Mmcfe, compared to 948 Mmcfe in the year-earlier period, offset by declines of 42% in natural gas prices, 45% in oil prices and 63% for sales of natural gas liquids. Our volumetric growth reflects strong performance from our horizontal wells and the commencement of production from our Haley’s Mill field in western Kentucky during August 2008, along with our share of production from non-operated wells drilled for our 2008 drilling partnership. Approximately 50% of our natural gas production in the current quarter was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in the 2009 third quarter averaged $6.53 per Mcf for our Appalachian production and $5.67 per Mcf overall, compared to an average overall realization of $9.80 per Mcf in the third quarter of 2008.

          The contraction of gas transmission, compression and processing revenues for the current quarter was driven our sale of a 50% interest in the Gathering System in mid-July and the balance in mid-August 2009. See “Recent Developments.” Following the sale, our gas transmission, compression and processing revenues were limited primarily to gas utility sales and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.

          Expenses. The following table shows the components of our direct and other expenses for the three months ended September 30, 2009 and 2008. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses. Certain non-cash expenses for the 2009 interim periods reflect adjustments for the adoption of derivative fair value accounting for our 6% convertible notes as of January 1, 2009. The impact of these adjustments is discussed below and in Note 2 to the accompanying condensed consolidated financial statements.

		Three Months Ended September 30,
		2009				Margin				2008				Margin
Direct Expenses:
Contract drilling		$	2,913,418				24	%		$	7,570,698				23	%
Oil and gas production			2,658,985				57				3,922,629				65
Gas transmission, compression and processing			960,879				15				1,039,597				60
Total direct expenses			6,533,282				42				12,532,924				47

		(Restated)				% Revenue								% Revenue
Other Expenses (Income):
Selling, general and administrative			2,601,514				23	%			3,551,908				15	%
Options, warrants and deferred compensation			285,309				3				229,209				1
Depreciation, depletion and amortization			3,304,139				30				3,318,320				14
Bad debt expense			—				N/A				342,195				1
Interest expense, net of interest income			2,143,393				19				1,446,526				6
Gain on sale of assets			(3,356,177	)			N/A				—				N/A
Fair value loss on derivative financial instruments			4,847								—				N/A
Other, net			292,073				3				87,584				—
Total other expenses		$	5,275,098							$	8,975,742

          Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses represented 76% of contract drilling revenues in the current quarter, compared to 77% 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 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 Gathering System, which will further impact these costs in future periods. See “Recent Developments.” As a percentage of revenues, overall production expenses in the current quarter benefitted from lower severance taxes and various cost-cutting measures for our field operations.

          Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, were substantially reduced in the third quarter of 2009 following our sale of the Gathering System. Our remaining infrastructure position is comprised of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses in future periods will reflect this 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 27% from the same period last year, primarily due to the timing of partnership sales, and represented 23% of revenues in the current quarter, compared to 15% in the third quarter of 2008.

          Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $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 our Gathering System following its sale, partially offset by additions to our oil and gas properties.

          Cash interest expense for the 2009 third quarter decreased 18% from the year-earlier period, reflecting the reduction of debt levels under our revolving credit facility from proceeds of our Gathering System sale and equity raise. In addition to improving our liquidity, the reduction in our credit facility debt from these transactions will provide ongoing savings on future interest expense. Non-cash interest expense of $1,004,682 for the third quarter of 2009 reflects the application of the effective interest method for accretion of the debt discount attributable to the embedded conversion feature of our 6% notes, which have of face amount of $37,000,000. See “Liquidity and Capital Resources.”

          We recognized a pre-tax gain of $3,356,367 during the third quarter of 2009 from the sale of our interests in the Gathering System. See “Recent Developments.” We acquired the open-access portion of the Gathering System from Duke Energy in March 2006 for $18 million and built out the field-wide portions of the facilities at historical costs totaling approximately $33.5 million.

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

          Net Income (Loss) and EPS. We recognized a net loss of $1,122,001 in the third quarter of 2009, as restated, reflecting the foregoing factors. Earnings (loss) per share (EPS) was $(0.04) on 28,873,105 weighted average common shares outstanding. Before giving effect to the after-tax gain from our sale of the Gathering System, we had a net loss of $3,135,821 or $(0.11) per share in the third quarter of 2009, compared to net income of $945,185 realized in the same quarter last year, with EPS of $0.04 on 26,977,438 fully diluted shares. Adjustments for derivative treatment of our 6% convertible notes accounted for $960,622 of our restated net loss, or $(0.03) per share, for the third quarter of 2009.

Results of Operations — Nine Months Ended September 30, 2009 and 2008

          Revenues. The following table shows the components of our revenues for the nine months ended September 30, 2009 and 2008, together with their percentages of total revenue in the current period and percentage change on a period-over-period basis.

		Nine Months Ended September 30,
						% of								%
		2009				Revenue				2008				Change
Revenue:
Contract drilling		$	16,328,000				38	%		$	24,027,035				(32	)%
Oil and gas production			20,198,187				47				30,891,933				(35	)
Gas transmission, compression and processing			6,528,132				15				7,662,504				(15	)
Total		$	43,054,319				100	%		$	62,581,472				(31	)

          Our contract drilling revenues in the first nine months of 2009 reflect the completion of drilling operations for our 2008 drilling partnership, which participated in 89 wells on non-operated properties in West Virginia and Virginia, as well as the commencement of operations for our 2009 drilling partnership, which participated in nine horizontal wells through the end of the third quarter.

          Production revenues for the first nine months of 2009 reflect a 9% increase in production output to 3,037 Mmcfe, compared to 2,779 Mmcfe in the year-earlier period, offset by declines of 33% in natural gas prices, 55% in oil prices and 61% for NGL sales. Our volumetric growth, while negatively impacted by the reduction in drilling activity in the current period, reflects strong performance from horizontal drilling initiatives beginning in February 2008 and the commencement of production from our Haley’s Mill field later in the year and non-operated wells in West Virginia. Approximately 50% of our natural gas production in the first nine months of 2009 was sold under fixed-price contracts, and the balance at index-based pricing. Realized natural gas prices in the current period averaged $7.44 per Mcf for our Appalachian production and $6.31 per Mcf overall, compared to an average overall realization of $8.25 per Mcf in the first nine months of 2008.

          Gas transmission, compression and processing revenues for the current period were driven by fees for moving our drilling program investors’ share of gas through the Gathering System prior to its sale and processing fees for liquids extraction through our Rogersville plant. This component of revenues also includes contributions from gas utility sales.

          Expenses. The following table shows the components of our direct and other expenses for the nine months ended September 30, 2009 and 2008. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

		Nine Months Ended September 30,
		2009				Margin				2008				Margin
Direct Expenses:
Contract drilling		$	12,328,110				24	%		$	18,447,544				23	%
Oil and gas production			7,598,044				62				9,794,679				68
Gas transmission, compression and processing			2,955,204				55				3,087,391				60
Total direct expenses			22,881,358				47				31,329,614				50

		(Restated)				% Revenue								% Revenue
Other Expenses (Income):
Selling, general and administrative			8,404,519				20	%			10,282,485				16	%
Options, warrants and deferred compensation			1,022,774				2				601,691				1
Depreciation, depletion and amortization			10,610,630				25				9,451,272				15
Bad debt expense			—				N/A				749,035				1
Interest expense, net of interest income			6,824,842				16				4,049,336				6
Gain on sale of assets			(3,369,082	)			N/A				—				N/A
Fair value gain on derivative financial instruments			(4,477	)			N/A				—				N/A
Other, net			600,896				1				115,939				—
Total other expenses		$	24,090,102							$	25,249,758