Ngas Resources 10Q 2005 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, 2005


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 (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)

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 whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months and (2) has been subject to those filing requirements for the preceding 90 days.

Yesþ Noo

Indicate by check mark whether the issuer is an accelerated filer under Rule 12b-2.

Yeso Noþ

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


Title of Class Common Stock		Outstanding at August 5, 2005 17,549,846

NGAS Resources, Inc.

INDEX


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements:

Review Engagement Report		1

Condensed Consolidated Balance Sheets – June 30, 2005 (unaudited) and December 31, 2004		2

Condensed Consolidated Statement of Operations and Deficit – Three months and six months ended June 30, 2005 and 2004 (unaudited)		3

Condensed Consolidated Statement of Cash Flows – Three months and six months ended June 30, 2005 and 2004 (unaudited)		4

Notes to Condensed Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16

Item 3. Quantitative and Qualitative Disclosures about Market Risk		25

Item 4. Controls and Procedures		25

PART II. OTHER INFORMATION

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		25

Item 4. Submission of Matters to a Vote of Security Holders		26

Item 6. Exhibits		26
EX-11.1 Computation of Earnings Per Share
EX-31.1 Certification
EX-31.2 Certification
EX-32.1 Certification
EX-32.2 Certification

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

REVIEW ENGAGEMENT REPORT

To the Directors of
NGAS RESOURCES, INC.

We have reviewed the condensed consolidated balance sheet ofNGAS RESOURCES, INC.as at June 30, 2005 and the condensed consolidated statements of operations and deficit, and cash flows for the three-month and six-month periods then ended. These interim financial statements are the responsibility of the Company’s management.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States) and with generally accepted standards for review engagements in Canada. A review of interim financial statements consists principally of applying analytical procedures and making enquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board and Canada, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modification that should be made to the accompanying interim financial statements for them to be in conformity with Canadian generally accepted accounting principles.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) and with generally accepted auditing standards in Canada, the consolidated balance sheet as at December 31, 2004 and the related consolidated statements of operations and deficit and cash flows for the year then ended (not presented herein) and, in our report dated March 14, 2005, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2004 is fairly stated in all material respects in relation to the balance sheet from which it has been derived.

KRAFT, BERGER, GRILL, SCHWARTZ, COHEN & MARCH LLP
Chartered Accountants

Toronto, Ontario
August 12, 2005

NGAS Resources, Inc.

CONDENSED CONSOLIDATED BALANCE SHEETS

(U.S. funds)


	June 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets:
Cash	$	15,446,431		$	11,849,372
Accounts receivable		4,477,097			2,281,715
Prepaid expenses and other current assets		3,087,087			2,152,174
Loans to related parties (Note 4)		119,920			142,718

Total current assets		23,130,535			16,425,979

Bonds and deposits		371,695			124,650
Oil and gas properties (Note 2)		80,379,629			68,156,790
Property and equipment (Note 3)		2,925,210			2,668,908
Loans to related parties (Note 4)		256,170			357,175
Investments (Note 5)		—			55,454
Deferred financing costs (Note 6)		1,256,566			1,024,810
Goodwill (Note 7)		313,177			313,177

Total assets	$	108,632,982		$	89,126,943


LIABILITIES
Current liabilities:
Accounts payable		4,363,208			3,381,726
Accrued liabilities		5,766,697			3,537,576
Customers’ drilling deposits (Note 8)		19,934,725			12,652,001
Long term debt, current portion (Note 9)		33,579			121,247

Total current liabilities		30,098,209			19,692,550

Future income taxes		2,661,302			2,053,432
Long term debt (Note 9)		31,342,195			25,870,498
Deferred compensation		587,011			368,935

Total liabilities		64,688,717			47,985,415


SHAREHOLDERS’ EQUITY

Capital stock (Note 10)
Authorized:
5,000,000 Preferred shares, non-cumulative, convertible
100,000,000 Common shares
Issued:
16,314,913 Common shares (December 31, 2004 – 15,605,208)		57,394,421			54,929,887
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital – options and warrants		1,937,718			1,796,504
To be issued:
9,185 Common shares (December 31, 2004 – 10,070)		45,925			50,350

		59,354,434			56,753,111
Deficit		(15,410,169	)		(15,611,583	)

Total shareholders’ equity		43,944,265			41,141,528

Total liabilities and shareholders’ equity	$	108,632,982		$	89,126,943

See Notes to Condensed Consolidated Financial Statements.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

(U.S. funds) (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
REVENUE
Contract drilling	$	7,639,000		$	7,040,250		$	24,316,000		$	21,366,375
Oil and gas production		3,507,703			986,724			6,383,491			1,778,013
Gas transmission and compression		289,016			300,195			746,474			748,663

Total revenue		11,435,719			8,327,169			31,445,965			23,893,051


DIRECT EXPENSES
Contract drilling		6,618,260			5,236,941			18,988,065			15,341,589
Oil and gas production		890,694			392,379			1,649,515			670,087
Gas transmission and compression		235,084			114,326			627,868			514,192

Total direct expenses		7,744,038			5,743,646			21,265,448			16,525,868


OTHER INCOME (EXPENSES)
Selling, general and administrative		(2,511,910	)		(1,744,546	)		(6,018,735	)		(4,930,064	)
Options, warrants and deferred compensation		(239,090	)		(202,972	)		(491,698	)		(233,046	)
Depreciation, depletion and amortization		(1,001,533	)		(255,475	)		(2,048,088	)		(508,604	)
Interest expense		(555,001	)		(107,535	)		(1,063,754	)		(196,703	)
Interest income		48,386			81,344			86,126			168,206
Other, net		21,184			104,483			164,916			112,229

Total other income (expenses)		(4,237,964	)		(2,124,701	)		(9,371,233	)		(5,587,982	)


INCOME (LOSS) BEFORE INCOME TAXES		(546,283	)		458,822			809,284			1,779,201


INCOME TAX EXPENSE (BENEFIT)
Current		—			38,743			—			149,159
Future		(10,631	)		211,696			607,870			654,418

		(10,631	)		250,439			607,870			803,577


NET INCOME (LOSS)		(535,652	)		208,383			201,414			975,624

DEFICIT, beginning of period		(14,874,517	)		(16,456,043	)		(15,611,583	)		(17,223,284	)


DEFICIT, end of period	$	(15,410,169	)	$	(16,247,660	)	$	(15,410,169	)	$	(16,247,660	)


NET INCOME (LOSS) PER SHARE
Basic	$	(0.03	)	$	0.02		$	0.01		$	0.08

Diluted	$	(0.03	)	$	0.01		$	0.01		$	0.06


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		16,005,158			13,877,212			15,848,386			12,964,698

Diluted		16,005,158			16,706,462			16,749,736			16,005,368

See Notes to Condensed Consolidated Financial Statements.

NGAS Resources, Inc.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(U.S. funds) (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
OPERATING ACTIVITIES
Net income (loss)	$	(535,652	)	$	208,383		$	201,414		$	975,624
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Incentive bonus paid in common shares		—			—			217,026			—
Options, warrants and deferred compensation		239,090			202,972			491,698			233,046
Contract settlement paid in common shares		(4,425	)		—			(4,425	)		—
Depreciation, depletion and amortization		1,001,533			255,475			2,048,088			508,604
Write-down of investment		55,454			—			55,454			—
Notes issued in kind for interest on long term debt		—			18,157			—			55,359
Gain on sale of assets		—			(348	)		(12,568	)		(4,948	)
Future income taxes (benefit)	��	(10,631	)		(45,951	)		607,870			396,771
Changes in assets and liabilities
Accounts receivable		(1,670,147	)		(176,398	)		(2,195,382	)		(432,269	)
Prepaid expenses and other current assets		(937,893	)		(183,389	)		(934,913	)		(222,676	)
Accounts payable		(276,962	)		368,697			981,482			1,180,369
Accrued liabilities		(138,397	)		(766,269	)		2,229,121			45,282
Income taxes payable		—			3,890			—			44,306
Customers’ drilling deposits		8,257,125			3,165,000			7,282,724			(4,010,000	)

Net cash provided by (used in) operating activities		5,979,095			3,050,219			10,967,589			(1,230,532	)


INVESTING ACTIVITIES
Proceeds from sale of assets		—			186,000			273,600		$	190,600
Purchase of property and equipment		(684,001	)		(107,084	)		(729,103	)		(222,230	)
Increase in bonds and deposits		(161,650	)		(25,400	)		(247,045	)		(25,400	)
Additions to oil and gas properties, net		(6,651,534	)		(2,452,882	)		(13,903,954	)		(8,719,016	)

Net cash used in investing activities		(7,497,185	)		(2,399,366	)		(14,606,502	)		(8,776,046	)


FINANCING ACTIVITIES
Decrease in loans to related parties		29,980			41,455			123,803			76,654
Proceeds from issuance of common shares		245,860			6,456,732			1,494,636			9,895,049
Payments of deferred financing costs		—			—			(451,496	)		—
Proceeds from issuance of long term debt		—			—			6,168,696			—
Payments of long term debt		(14,338	)		(23,167	)		(99,667	)		(46,037	)

Net cash provided by financing activities		261,502			6,475,020			7,235,972			9,925,666


Change in cash		(1,256,588	)		7,125,873			3,597,059			(80,912	)
Cash, beginning of period		16,703,019			15,388,208			11,849,372			22,594,993

Cash, end of period	$	15,446,431		$	22,514,081		$	15,446,431		$	22,514,081


SUPPLEMENTAL DISCLOSURE
Interest paid	$	582,097		$	98,030		$	1,107,061		$	141,344
Income taxes paid		130,000			34,853			130,000			104,853

SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Common shares issued for accounts payable		—			146,596			—			—
Common shares issued upon conversion of notes		535,464			156,250			620,464			1,613,890

See Notes to Condensed Consolidated Financial Statements.

NGAS Resources, Inc.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2005–(Unaudited)

Note 1. Summary of Significant Accounting Policies

(a) General. The accompanying unaudited condensed consolidated financial statements of NGAS Resources, Inc., a British Columbia corporation (the “Company”), have been prepared in accordance with generally accepted accounting principles in Canada. In the opinion of management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary to fairly present the Company’s condensed consolidated financial position at June 30, 2005 and its condensed consolidated results of operations and deficit and cash flows for the interim periods presented. The condensed consolidated financial statements should be read in conjunction with the Company’s consolidated financial statements and related notes included in its Annual Report on Form 10-KSB for the year ended December 31, 2004, as amended by Amendment No. 1 on Form 10-KSB/A (the “Annual Report”). The accounting policies followed by the Company and their method of application are set forth in Note 1 to the consolidated financial statements included in the Annual Report and are incorporated herein by reference. See Note 14 – United States and Canadian Accounting Principles.

(b) Basis of Consolidation. The consolidated financial statements include the accounts of the Company, its wholly owned subsidiary, Daugherty Petroleum, Inc. (“DPI”), a Kentucky corporation, and DPI’s wholly owned subsidiaries, Sentra Corporation, NGAS Securities, Inc. and NGAS Gathering, LLC. DPI conducts all of the Company’s oil and gas drilling and production operations. Sentra Corporation owns and operates natural gas distribution facilities for two communities in Kentucky. NGAS Securities. Inc. provides marketing support services for private placement financings by the Company and DPI. NGAS Gathering, LLC operates gas gathering systems. The condensed consolidated financial statements also reflect DPI’s interests in a total of 28 drilling programs that it has sponsored and managed to conduct drilling operations on its prospects (the “Drilling Programs”). DPI maintains a combined interest as both general partner and an investor in each Drilling Program ranging from 25.75% to 66.67%, subject to specified increases after certain distribution thresholds are reached. The Company accounts for those interests using the proportionate consolidation method, combining DPI’s share of assets, liabilities, income and expenses of the Drilling Programs with those of its separate operations. All material inter-company accounts and transactions for the periods presented in the condensed consolidated financial statements have been eliminated on consolidation.

(c) Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in Canada requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the balance sheet date and the reported amounts of revenues and expenses during the periods presented in the condensed consolidated financial statements. Actual results could differ from those estimates.

(d) Change in Accounting Policy. Effective January 1, 2004, the Company adopted the fair value provisions of Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3870, “Stock-Based Compensation and Other Stock-Based Payments” and related interpretations for the recognition and measurement of compensation costs associated with employee stock options. See Note 10 – Capital Stock.

(e) Reclassifications and Adjustments. Certain amounts reported in the condensed consolidated financial statements for the interim periods in 2004 have been reclassified to conform with the presentation in the current periods. In addition, the condensed consolidated statements of operations and deficit previously issued by the Company for the three months and six months ended June 30, 2004 have been adjusted to eliminate the line item for gross profit, which was previously reported before accounting for depreciation, depletion and amortization (“DD&A”) attributable to cost of sales as a component of direct expenses. The inclusion of DD&A as a direct expense would have the following effects on gross profit, as previously reported:


	Three Months			Six Months
	Ended June 30,			Ended June 30,
	2004			2004
Gross profit, as reported	$	2,583,523		$	7,367,183
Less DD&A, as a component of direct expenses		(255,475	)		(508,604	)


Gross profit, as restated	$	2,328,048		$	6,858,579

Note 2. Oil and Gas Properties

Capitalized costs and accumulated DD&A relating to the Company’s oil and gas producing activities, all of which are conducted within the continental United States, are summarized below.


	June 30, 2005							December 31,
			Accumulated					2004
	Cost		DD&A			Net		Net
Proved oil and gas properties	$	71,428,177	$	(5,278,211	)	$	66,149,966	$	59,387,998
Unproved oil and gas properties		1,986,758		—			1,986,758		1,838,038
Gathering lines and well equipment		12,825,136		(582,231	)		12,242,905		6,930,754


Total oil and gas properties	$	86,240,071	$	(5,860,442	)	$	80,379,629	$	68,156,790

Note 3. Property and Equipment

The following table presents the capitalized costs and accumulated depreciation for the Company’s property and equipment as of June 30, 2005 and December 31, 2004.


	June 30, 2005							December 31,
			Accumulated					2004
	Cost		Depreciation			Net		Net
Land	$	12,908	$	—		$	12,908	$	12,908
Building improvements		36,134		(5,151	)		30,983		16,234
Machinery and equipment		2,358,063		(467,851	)		1,890,212		1,706,238
Office furniture and fixtures		83,570		(28,488	)		55,082		59,308
Computer and office equipment		421,270		(174,723	)		246,547		257,977
Vehicles		991,383		(301,905	)		689,478		616,243


Total property and equipment	$	3,903,328	$	(978,118	)	$	2,925,210	$	2,668,908

Note 4. Loans to Related Parties

Loans to related parties represent loans receivable from certain shareholders and officers of the Company, payable monthly from production revenues for periods ranging from five to ten years, with a balloon payment at maturity. The loans receivable from shareholders aggregated $204,661 at June 30, 2005 and $328,464 at December 31, 2004. These loans bear interest at 6% per annum and are collateralized by ownership interests in Drilling Programs. The loans receivable from officers totaled $171,429 at June 30, 2005 and December 31, 2004. These loans are non-interest bearing and unsecured.

Note 5. Investments

The Company has investments of $119,081 in three series of bonds issued by the City of Galax, Virginia Industrial Development Authority, bearing interest at rates ranging from 7% to 8.25% per annum and maturing through July 1, 2010. The Company recorded a write-down of $63,627 in the carrying value of the bonds to reflect a permanent decline in value during 2004 and an additional write-down of their remaining carrying value during the second quarter of 2005.

Note 6. Deferred Financing Costs

The Company incurred financing costs for its convertible note private placements and secured bank loans aggregating $451,496 in the first six months of 2005, $986,478 in 2004 and $601,886 in 2003. See Note 9 – Long Term Debt. These financing costs are initially capitalized and amortized at rates based on the stated terms of the underlying debt instruments. Upon conversion of its convertible notes at the option of the note holders, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for outstanding notes and bank loans aggregated $1,256,566 at June 30, 2005 and $1,024,810 at December 31, 2004, net of accumulated amortization totaling $271,591 and $116,386, respectively.

Note 7. Goodwill

In connection with the acquisition of DPI in 1993, the Company recorded goodwill of $1,789,564, which was amortized over ten years on a straight-line basis. Unamortized goodwill at December 31, 2001 was $313,177. At the beginning of 2002, the Company adopted CICA Handbook Section 3062, “Goodwill and Other Intangible Assets,” which is the Canadian equivalent of SFAS No. 142 for accounting standards generally accepted in the United States. Under the adopted standard, goodwill is no longer amortized but is instead tested for impairment upon adoption and at least annually thereafter. The Company’s annual analyses indicated that no impairment charges were required. Accordingly, accumulated amortization of goodwill remained at $1,476,387 as of June 30, 2005 and December 31, 2004.

Note 8. Customer Drilling Deposits

At the commencement of operations, each Drilling Program acquires drilling rights for specified wells from DPI and enters into a turnkey drilling contract with DPI for drilling and completing the wells at specified prices. Upon the closing of Drilling Program financings, DPI receives the net proceeds from the financings as customers’ drilling deposits under the turnkey drilling contracts. These payments totaled $25,429,000 in the six months ended June 30, 2005 and $31,278,330 in 2004. The Company recognizes revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits aggregating $19,934,725 at June 30, 2005 and $12,652,001 at December 31, 2004 represent unapplied turnkey payments for wells that were not yet drilled as of the balance sheet dates.

Note 9. Long Term Debt

(a) Credit Facility. The Company maintains a credit facility for up to $20 million with KeyBank NA. The borrowing base for the facility is determined semiannually by the bank. At June 30, 2005 and December 31, 2004, both the borrowing base and total borrowings under the facility were $15,000,000. The interest rate under the facility fluctuates at 1% above the bank’s prime rate, amounting to 7.25% at June 30, 2005.

(b) Convertible Notes. The Company has issued several series of convertible notes in private placements to finance a substantial part of its drilling and acquisition activities. The notes are convertible by the holders into the Company’s common stock at fixed rates (subject to anti-dilution adjustments) and are generally redeemable by the Company at 100% of their principal amount plus accrued interest through the date of redemption. The most recent series of notes due March 31, 2010 were issued in the fourth quarter of 2004 in the aggregate principal amount of $1,831,304 and in the first quarter of 2005 in the aggregate principal amount of $6,168,696. A prior series of notes due September 5, 2008 originally issued during September 2003 in the aggregate principal amount of $5,000,000 required the payment of interest in kind through September 30, 2004, resulting in the issuance of additional paid-in-kind notes aggregating $178,924.

The terms of the Company’s convertible notes outstanding at June 30, 2005 and December 31, 2004 are summarized below.


							Shares Issuable at
	Principal Amount Outstanding at						June 30, 2005
	June 30,		December 31,		Conversion		upon
Title of Notes	2005		2004		Price		Conversion
10% Convertible Notes due May 1, 2007⁽¹⁾	$	515,500	$	560,500	$	1.50		343,666
8% Convertible Notes due April 10, 2008		705,925		745,925		1.90		371,539
8% Convertible Notes due May 1, 2008		188,750		188,750		2.25		83,888
7% Convertible Notes due September 5, 2008		1,077,202		1,077,202		4.50		239,378
7% Convertible Notes due October 4, 2009⁽²⁾		5,500,000		6,100,000		6.00		916,666
7% Convertible Notes due March 31, 2010		8,000,000		1,831,304		6.00		1,333,333


Total	$	15,987,377	$	10,503,681				3,288,470


(1)		After June 30, 2005, the Company issued a notice of redemption for these notes. See Note 16 – Subsequent Events.

(2)		Does not reflect the conversion of $4,200,000 principal amount of these notes after June 30, 2005. See Note 16 – Subsequent Events.

(c) Acquisition Debt. The Company issued a note in the principal amount of $854,818 to finance its 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 and related buildings and equipment. Although the purchase agreement for the acquisition provides for royalties at 4% of net smelter returns or other production revenues, the property has remained inactive. The acquisition debt is recorded at its remaining face value of $378,818 at June 30, 2005 and $390,818 at December 31, 2004.

(d) Miscellaneous Debt. The following table summarizes the terms of the Company’s other debt obligations outstanding at June 30, 2005 and December 31, 2004.


	Principal Amount Outstanding at
	June 30,		December 31,
Terms of Debt	2005		2004
Notes issued to finance equipment and vehicles, payable monthly in various amounts through 2005, with interest ranging from 8.68% to 9.5% per annum, collateralized by the acquired equipment and vehicles	$	—	$	4,451
Loan payable to unaffiliated company, bearing interest at 10% per annum payable quarterly, collateralized by assets of subsidiary guarantor		—		64,779
Note payable to unaffiliated individual, payable in 60 installments of $1,370, together with interest at 8% per annum, through 2005		—		4,964
Loans payable to various banks, payable monthly in various amounts, together with interest at rates ranging from 4% to 9.75% per annum, through 2005, collateralized by receivables and various vehicles		9,579		23,052


Total	$	9,579	$	97,246

(e) Maturities of Long Term Debt. The following table summarizes the Company’s total long term debt at June 30, 2005 and December 31, 2004 and the principal payments due through 2010 and thereafter.


	Principal Amount Outstanding at
	June 30,		December 31,
	2005		2004
Total long term debt (including current portion)	$	31,375,774	$	25,991,745
Less current portion		33,579		121,247


Total long term debt	$	31,342,195	$	25,870,498


Maturities of Debt
Balance of 2005	$	21,579
2006		15,024,000	⁽¹⁾
2007		539,500	⁽²⁾
2008		1,995,877	⁽³⁾
2009		5,524,000	⁽⁴⁾
2010 and thereafter		8,270,818	⁽³⁾


(1)		Primarily reflects long term debt under the Company’s revolving credit facility.

(2)		After June 30, 2005, the Company issued a notice of redemption for these notes. See Note 16 – Subsequent Events.

(3)		Primarily reflects long term debt under the Company’s convertible notes outstanding at June 30, 2005.

(4)		Does not reflect the conversion of $4,200,000 principal amount of these notes after June 30, 2005. See Note 16 – Subsequent Events.

Note 10. Capital Stock

(a) Preferred and Common Shares. The Company has 5,000,000 authorized shares of preferred stock, none of which were outstanding at June 30, 2005 or December 31, 2004. The following table reflects transactions involving the Company’s common stock during the reported periods.


	Number of
Common Shares Issued	Shares		Amount
Balance, December 31, 2003		10,676,030	$	36,244,623
Issued for cash		2,557,665		12,200,886
Issued to employees as incentive bonus		157,250		674,905
Issued upon exercise of stock options and warrants		1,520,936		3,507,493
Issued upon conversion of convertible notes		560,601		1,688,590
Issued for settlement of accounts payable		46,352		181,520
Issued for contract settlement		86,374		431,870

Balance, December 31, 2004		15,605,208		54,929,887
Issued to employees as incentive bonus		51,920		217,026
Issued upon exercise of stock options and warrants		506,733		1,627,044
Issued upon conversion of convertible notes		151,052		620,464

Balance, June 30, 2005		16,314,913	$	57,394,421


Paid In Capital – Options and Warrants	Amount
Balance, December 31, 2003	$	1,140,321
Issued		676,433
Exercised		(20,250	)

Balance, December 31, 2004		1,796,504
Issued		273,622
Exercised		(132,408	)

Balance, June 30, 2005	$	1,937,718


	Number of
Common Shares to be Issued	Shares			Amount
Balance, December 31, 2003		1,403,335		$	5,917,958
Issued in contract settlement⁽¹⁾		(86,374	)		(431,870	)
Contract settlement in cash in lieu of common shares		(3,556	)		(17,780	)
Issued in financing transaction⁽²⁾		(1,303,335	)		(5,417,958	)

Balance, December 31, 2004		10,070			50,350
Contract settlement in cash in lieu of common shares		(885	)		(4,425	)

Balance at June 30, 2005		9,185		$	45,925


(1)		Reflects shares issuable in a contract settlement, of which 3,335 shares were settled in cash during 2004 and 10,070 shares remained unissued at June 30, 2005 and December 31, 2004.

(2)		Reflects shares subscribed at the end of 2003 in an institutional private placement, part of the proceeds from which were received in January 2004, resulting in the classification of all the shares subscribed in the financing as common shares to be issued at December 31, 2003.

(b) Stock Options and Awards. The Company maintains three stock plans for the benefit of its directors, officers, employees and, in the case of the second and third plans, its consultants and advisors. The first plan, adopted in 1997, provides for the grant of options to purchase up to 600,000 common shares at prevailing market prices, vesting over a period of up to five years and expiring no later than six years from the date of grant. The second plan, adopted in 2001, provides for the grant of options to purchase up to 3,000,000 common shares at prevailing market prices, expiring no later than ten years from the date of grant. The third plan, adopted in 2003, provides for the grant of stock awards and stock options for an aggregate of up to 4,000,000 common shares. Stock awards may be subject to vesting conditions and trading restrictions specified at the time of grant. Option grants 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. During 2003, initial stock awards were made under the third plan for a total of 353,500 shares, subject to shareholder approval of the plan, which was received in June 2004. During 2004, stock awards for an additional 166,489 shares were made under the plan.

At June 30, 2005, the exercise prices of options outstanding under the Company’s stock option plans ranged from $1.02 to $4.09 per share, and their weighted average remaining contractual life was 4.10 years. The following table reflects transactions involving the Company’s stock options during 2004 and the first six months of 2005.


						Weighted Average
Stock Options	Issued			Exercisable		Exercise Price
Balance, December 31, 2003		1,119,331			1,119,331		1.10

Issued⁽¹⁾		2,015,000					4.05
Exercised		(311,480	)				1.00
Expired		(437,851	)				1.23

Balance, December 31, 2004		2,385,000			370,000		3.58

Exercised		(225,000	)				1.02

Balance, June 30, 2005		2,160,000			291,250	$	3.85


(1)		Granted to employees and directors under stock option plans at exercise prices ranging from $4.03 to $4.09 per share and vesting in increments from February 25, 2005 through February 25, 2009.

In accounting for stock options, the Company follows the retroactive method under CICA Handbook Section 3870. For fiscal years beginning after December 15, 2003, the statement requires the fair value method of accounting for stock options, consistent with the recognition and measurement provisions of SFAS Nos. 123 and 148, “Accounting for Stock-Based Compensation.” Under the fair value method, employee stock options are valued at grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. For the periods presented in the condensed consolidated financial statements, the fair value estimates for each option grant assumed a risk free interest rate of 4.5%, a dividend yield of 0%, a theoretical volatility of 0.30 and an expected life ranging from one to five years based on the option’s vesting provisions. For the six months ended June 30, 2005 and 2004, this resulted in non-cash charges for options and warrants of $273,622 and $108,482, respectively.

(c) Common Stock Purchase Warrants. The Company has issued common stock purchase warrants in various financing transactions. The exercise prices of warrants outstanding at June 30, 2005 ranged from $1.75 to $6.25 per share, and their weighted average remaining contractual life was 2.21 years. The following table reflects transactions involving the Company’s common stock purchase warrants during 2004 and the first six months of 2005.


						Weighted Average
Common Stock Purchase Warrants	Issued			Exercisable		Exercise Price
Balance, December 31, 2003		3,333,523			3,333,523	$	3.43

Issued in financing transactions⁽¹⁾		966,460					6.09
Issued for consulting services⁽²⁾		20,000					4.03
Exercised		(1,209,456	)				2.63
Expired		(689,062	)				3.06

Balance, December 31, 2004		2,421,465			2,421,465		4.96

Exercised		(281,733	)				4.49

Balance, June 30, 2005		2,139,732			2,139,732	$	5.03


(1)		Expiring from September 13, 2006 through December 31, 2008
(2)		Expiring from April 3, 2004 through April 2, 2008.

Note 11. Income (Loss) Per Share

The Company follows CICA Handbook Section 3500, “Earnings per Share.” The statement requires the presentation of both basic and diluted earnings per share (“EPS”) in the statement of operations, using the “treasury stock” method to compute the dilutive effect of stock options and warrants and the “if converted” method for the dilutive effect of convertible instruments. For the three months and six months ended June 30, 2004, the assumed exercise of outstanding stock options and warrants and conversion of outstanding convertible notes would have a dilutive effect on EPS because the exercise or conversion prices of some of these instruments were below the average market price of the common stock during the periods. For the six months ended June 30, 2005, the assumed exercise of outstanding stock options and conversion of outstanding convertible notes would have a dilutive effect on EPS, and the assumed exercise of outstanding warrants be anti-dilutive, based on the average market price of the common stock during the period. Because the Company recognized a net loss for the three months ended June 30, 2005, the assumed exercise or conversion of all these instruments would have been anti-dilutive for that period. The following table sets forth the computation of dilutive EPS for the three months and six months ended June 30, 2005 and 2004.


	Three Months Ended					Six Months Ended
	June 30,					June 30,
Diluted EPS	2005			2004		2005		2004
Numerator:
Net income (loss) as reported for basic EPS	$	(535,652	)	$	208,383	$	201,414	$	975,624
Adjustments to income for diluted EPS		—			18,496		—		46,943

Net income (loss) for diluted EPS	$	(535,652	)	$	226,879	$	201,414	$	1,022,567

Denominator:
Weighted average shares for basic EPS		16,005,158			13,877,212		15,848,386		12,964,698
Effect of dilutive securities:
Stock options		—			1,107,069		633,686		1,096,844
Warrants		—			940,813		267,664		982,953
Convertible notes		—			781,368		—		960,873

Adjusted weighted average shares and assumed conversions for dilutive EPS		16,005,158			16,706,462		16,749,736		16,005,368


Diluted EPS	$	(0.03	)	$	0.01	$	0.01	$	0.06

Note 12. Related Party Transactions

(a) General. Because the Company operates through its subsidiaries and affiliated Drilling Programs, its holding company structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. It is the Company’s policy to structure any transactions with related parties only on terms that are no less favorable to the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions not disclosed elsewhere in these notes are summarized below.

(b) Drilling Programs. DPI invests in sponsored Drilling Programs on substantially the same terms as unaffiliated investors, contributing capital in proportion to its initial partnership interest. DPI also maintains a 1% interest as general partner in each Drilling Program, resulting in a combined interest of at least 25.75% in its larger Drilling Programs and up to 66.67% in smaller Drilling Programs tailored for exploratory prospects. The agreements for both types of Drilling Programs generally provide for specified increases in DPI’s program interests, up to 15% of the total program interests, after program distributions reach “payout,” which ranges from 100% to 110% of partners’ investment. The partnership agreements also provide for each Drilling Program to enter into turnkey drilling contracts with DPI for all wells to be drilled by that Drilling Program. The portion of the profit on drilling contracts attributable to DPI’s ownership interest in the Drilling Programs has been eliminated on consolidation for the interim periods presented in the Company’s condensed consolidated financial statements. The following table sets forth the total revenues recognized from the performance of turnkey drilling contracts with sponsored Drilling Programs for the reported periods.


Reporting Period	Drilling Contract Revenue
Three months ended June 30, 2005		$ 7,639,000
Three months ended June 30, 2004		7,040,250
Six months ended June 30, 2005		24,316,000
Six months ended June 30, 2004		21,366,375

Note 13. Segment Information

The Company has two reportable segments based on management responsibility and key business operations. The following table presents summarized financial information for the Company’s business segments.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Revenue, net:
Oil and gas development	$	11,435,719		$	8,327,169		$	31,445,965		$	23,893,051
Corporate		—			—			—			—

Total		11,435,719			8,327,169			31,445,965			23,893,051

DD&A:
Oil and gas development		902,232			227,150			1,865,542			446,150
Corporate		99,301			28,325			182,546			62,454

Total		1,001,533			255,475			2,048,088			508,604

Interest expense:
Oil and gas development		259,191			54,513			525,290			67,803
Corporate		295,810			53,022			538,464			128,900

Total		555,001			107,535			1,063,754			196,703

Net income (loss):
Oil and gas development		6,591			485,099			1,155,926			1,477,295
Corporate		(542,243	)		(276,716	)		(954,512	)		(501,671	)

Total		(535,652	)		208,383			201,414			975,624

Capital expenditures:
Oil and gas development		7,164,534			2,524,271			14,450,781			8,867,169
Corporate		171,001			35,695			182,276			74,077

Total	$	7,335,535		$	2,559,966		$	14,633,057			8,941,246


	June 30,		December 31,
	2005		2004
Identifiable assets:

Oil and gas development	$	105,427,567	$	82,380,938
Corporate		3,205,415		6,746,005


Total	$	108,632,982	$	89,126,943

Note 14. United States and Canadian Accounting Principles

(a) Differences Reflected in Condensed Consolidated Financial Statements. The Company follows accounting principles generally accepted in Canada (“Canadian GAAP”), which are different in some respects than accounting principles generally accepted in the United States of America (“U.S. GAAP”). None of these differences would have any effects on the Company’s financial position, results of operations or cash flows, as reported under Canadian GAAP at and for the three months and six months ended June 30, 2005 or 2004.

(b) Recent Accounting Pronouncements – Canadian GAAP. Recent accounting pronouncements affecting the Company’s financial reporting under Canadian GAAP are summarized below.

(i)Financial Instruments. In January 2005, the CICA issued Section 3855, “Financial Instruments – Recognition and Measurement.” This Section prescribes when a financial asset, financial liability or non-financial derivative is to be recognized on the balance sheet and at what amount, proscribing fair value or cost-based measures under different circumstances. It also specifies how financial instrument gains and losses are to be presented. It applies to interim and annual financial statements for fiscal periods beginning after October 31, 2006. The Company plans to adopt this Section on January 1, 2007. Transitional provisions for this Section are complex and vary based on the type of financial instruments under consideration. The effect on the Company’s consolidated financial statements is not expected to be material.

(ii)Comprehensive Income. In January 2005, the CICA issued Section 1530, “Comprehensive Income,” which introduces new standards for reporting and presenting comprehensive income. Comprehensive income is the change in equity (net assets) of a company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except for changes resulting from investments by owners and distributions to owners. It applies to interim and annual financial statements for fiscal periods beginning after October 31, 2006. The Company plans to adopt this Section on January 1, 2007. Financial statements for prior periods will be required to be restated for certain comprehensive income items. The effect on the Company’s consolidated financial statements is not expected to be material.

(iii)Equity. In January 2005, the CICA issued Section 3251, “Equity,” which replaces Section 3250, “Surplus.” It establishes standards for the presentation of equity and changes in equity during reporting periods beginning after October 31, 2006. Financial statements of prior periods are required to be restated for certain specified adjustments. For other adjustments, the adjusted amount must be presented to the opening balance of accumulated other comprehensive income. The Company plans to adopt this Section on January 1, 2007. The effect on the Company’s consolidated financial statements is not expected to be material.

(c) Recent Accounting Pronouncements – U.S. GAAP. Recent accounting pronouncements affecting the Company’s financial reporting under U.S. GAAP are summarized below.

(i)SFAS No. 123R. SFAS No. 123R, “Share Based Payment,” was issued in December 2004 to require recognition of compensation expense for the fair value of stock options and other equity-based compensation at the date of grant. In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 107, “Share-Based Payment,” clarifying the interaction between SFAS No. 123R and certain SEC reporting requirements. The Company adopted these requirements on January 1, 2004 in accordance with CICA Handbook Section 3870. See Note 10 – Capital Stock.

(ii)SFAS No. 19 and FAS No. 19-1. In April 2005, FASB Staff Position No. FAS 19.1 (the “FSP”) was issued to amend the guidance for suspended well costs in SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” The FSP addresses circumstances that permit continued capitalization of exploratory drilling costs beyond one year. In general, the one-year limitation may be exceeded for an exploratory well only if sufficient reserves have been found to justify its completion and sufficient progress has been made in assessing the reserves as well as the economic and operating viability of the project. The FSP is effective for the first reporting period beginning after April 4, 2005. The Company has found proved reserves for all exploratory wells drilled during the periods presented in the condensed consolidated financial statements within one year after completion of drilling and therefore has not expensed any explanatory drilling costs for those wells.

(iii)SFAS No. 154. In June 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections,” to replace SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements,” and APB Opinion No. 20, “Accounting Changes.” SFAS No. 154 generally requires retrospective application for voluntary changes in accounting principles as well as changes required by accounting pronouncements. SFAS No. 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on January 1, 2005. In August 2005, the Company amended its Annual Report on Form 10-KSB for the year ended December 31, 2004 and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 to reflect two adjustments to the consolidated financial statements included in the reports. In the consolidated statements of operations, the Company eliminated the line item for gross profit, and in the consolidated statements of cash flows, reported changes in subscriptions receivable during 2004 and 2003 were eliminated from operating activities and added to financing activities as proceeds from issuance of common stock during those years in proportion to the subscription amounts received at the beginning of 2004 and the end of 2003, respectively. The annual consolidated financial statements were also expanded to add consolidated statements of changes in shareholders’ equity for each of the years in the three-year period ended December 31, 2004.

Note 15. Commitments

The Company has contractual obligations to make payments at specified times and amounts under leases for office facilities and field equipment and instruments governing its other commercial commitments. The following table lists the Company’s minimum annual obligations as of June 30, 2005 under non-cancelable operating leases and other commercial commitments.


	Commercial Commitments
	Operating		Other
Year	Leases		Commitments			Total
Balance of 2005	$	275,432	$	240,000	⁽¹⁾	$	515,432
2006		547,048		—			547,048
2007		547,732		—			547,732
2008		287,809		100,000	⁽²⁾		387,809
2009		195,000		2,045,000	⁽²⁾		2,240,000
2010 and thereafter		97,500		—			97,500


Total	$	1,950,521	$	2,385,000		$	4,335,521


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

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

Note 16. Subsequent Events

(a) Conversion of 10% Convertible Notes due May 1, 2007. On July 11, 2005, the Company issued a notice of redemption to holders of its 10% convertible notes due May 1, 2007. The notes were convertible into common shares prior to redemption at a conversion price of $1.50 per share and were redeemable at 100% of their principal amount, plus accrued interest through the redemption date. At June 30, 2005, notes of this series in the aggregate principal amount of $515,500 were outstanding. All of the notes were converted by their holders prior to the redemption date.

(b) Conversion of 7% Convertible Notes due October 4, 2009. During July and the first half of August 2005, an institutional holder of the Company’s 7% convertible notes due October 4, 2009 elected to convert $4,200,000 principal amount of the notes at the conversion price of $6.00 per share.

NGAS Resources, Inc.


Item 2.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF
		FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

NGAS Resources, Inc. (the “Company”) is an independent energy company focused on natural gas development and production in the Appalachian Basin, primarily in eastern Kentucky. Through our wholly owned subsidiary, Daugherty Petroleum, Inc. (“DPI”), and DPI’s interests in sponsored drilling partnerships (“Drilling Programs”), we actively acquire and develop natural gas interests in our core operating areas. Directly and through its subsidiaries, DPI also constructs and maintains gas gathering systems for our wells, operates natural gas distribution facilities for two communities in Kentucky, operates a gas gathering system connecting major natural gas supply basins, coordinates our private placement financings and owns inactive gold and silver prospects in Alaska. Our principal and administrative offices are located at 120 Prosperous Place, Suite 201, Lexington, Kentucky 40509. Our common stock is traded on the Nasdaq SmallCap Market under the symbol “NGAS,” and we maintain a website with information about us at www.ngas.com.

We commenced oil and gas operations in 1993 with the acquisition of DPI and have sponsored 28 separate Drilling Programs through the date of this report. In June 2004, we changed our corporate name from Daugherty Resources, Inc. to NGAS Resources, Inc. The name change reflects our focus on natural gas development and production and reinforces our association with the NGAS acronym from its use as the Nasdaq trading symbol for our common stock and the Internet address of our website. Unless otherwise indicated, references in this report to “we,” “our” or “us” include the Company as well as DPI, its subsidiaries and its interests in Drilling Programs. As used in this report, “Mcf” means thousand cubic feet, “Bcf” means billion cubic feet and “Mcfe” means thousand cubic feet of gas equivalents.

Strategy

We have structured our business to achieve capital appreciation through growth in our natural gas reserves, production, cash flow and earnings per share. Our strategy for continuing to realize our operational and financial objectives emphasizes several components. Each is aimed at positioning us to capitalize on natural gas development opportunities and long range pricing expectations for this commodity.

	•		Acceleration of Drilling Operations. Development drilling is our mainstay for production and reserve growth, heavily concentrated on geographic areas of the Appalachian Basin where we have established expertise and recognition. To help finance our drilling initiatives, we sponsor and manage Drilling Programs for private investors, contributing between 25% to 66.67% of total program capital and maintaining a proportionate working interest in program wells. Since 2000, we drilled 401 gross (120.7688 net) gas wells through our Drilling Programs. This includes 84 gross (23.9210 net) wells in the first six months of 2005 and 155 gross (49.7149 net) wells during 2004. We are sponsoring Drilling Programs for up to 170 new wells in 2005 and maintaining initial working interest in program wells ranging from 30.7% to 40.9%.

	•		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 experience as a regional operator. 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. During the second half of 2004, we completed three separate acquisitions of oil and gas interests covering a total of 89,737 acres in the Appalachian Basin, adding over 29.7 Bcf of gas equivalents to our estimated proved reserves at an acquisition price averaging $1.17 per Mcfe. We plan to continue pursuing acquisition opportunities for our own account and may begin sponsoring production programs with private investors to acquire producing oil and gas wells, primarily in the Appalachian Basin.

	•		Acquisition of Additional Drilling Prospects. We focus on expanding our substantial inventory of drilling prospects that meet our criteria for building predictable, long-lived reserves. Over the last several years, we acquired oil and gas drilling rights covering approximately 100,000 acres on the southwestern edge of the

			Big Sandy Gas Field in eastern Kentucky (the “Leatherwood Field”), as well as leases for 26,500 acres on the north side of the Pine Mountain Fault System near the Leatherwood Field (the “Straight Creek Field”). Our property acquisitions in 2004 also included substantial additional development prospects, primarily on acreage positions we acquired from Stone Mountain Energy Company (“SME”) during October 2004 in the Martin’s Fork and Amvest Fields, which span portions of Harlan County, Kentucky and Lee County, Virginia. We plan to continue capitalizing on opportunities to acquire large tracts with significant unproved gas development potential as well as established infrastructure, further expanding our inventory of drilling prospects and our stake in Appalachian Basin gas reserves and production.

	•		Disciplined Approach to Drilling. As of June 30, 2005, we had interests in a total of 692 wells, primarily in the Appalachian Basin. Most of our wells are drilled to relatively shallow total depths up to 5,000 feet, usually encountering five distinct and predictable natural gas pay zones. This disciplined approach helps reduce drilling risks, as reflected in our success rate. Historically, over 99% of our wells have been completed as producers. We complete and produce our wells from multiple pay zones whenever possible, eliminating the costs and complexities of deferred completions with behind-pipe gas. While our wells typically produce at modest initial volumes and pressures, they also demonstrate low annual decline rates and are expected to produce for 25 years or more.

	•		Extension of Gas Gathering Systems. We construct and operate gas gathering facilities to connect our wells to interstate pipelines with access to major natural gas markets. As of June 30, 2005, our gas gathering facilities aggregated approximately 247 miles. In addition to generating gas transmission and compression revenues, our 100% ownership of these systems gives us control over third-party access, providing competitive advantages in acquiring and developing nearby acreage. During the first six months of 2005, we extended our gathering systems by 76 miles, including part of a 23-mile, eight-inch steel gathering line for connecting our wells in the Leatherwood Field. As of the date of this report, we have installed all of the eight-inch line for the Leatherwood system and have started to set compressors and lateral lines for 80 wells awaiting connection in the Leatherwood Field. During the balance of the year, we expect to bring most of these wells on line as our Leatherwood system is put in service.

	•		Operation of Third-Party Gathering System. Gas production from the properties we acquired from SME in October 2004 is delivered through a 150-mile gathering system owned by Duke Energy and previously operated by SME in southeastern Kentucky, southwestern Virginia and northeastern Tennessee. The Stone Mountain system interconnects with Duke Energy’s East Tennessee natural gas pipeline at Rogersville, Tennessee, connecting major natural gas supply basins to growing markets in the eastern United States. Following the SME acquisition, we expanded our arrangements with Duke Energy to operate and maintain the Stone Mountain gas gathering system and to dedicate our SME production and part of our Straight Creek production for delivery through the system. Gas production from our Leatherwood Field can also move through the Stone Mountain system when our 8-inch gathering system is completed for that area. By integrating operations on the acquired acreage with our existing field activities in the region, we expect to expand our throughput to major natural gas markets serviced through Duke’s system and strengthen our competitive position in the region.

Drilling Operations

Drilling Program Structure. Most of our Drilling Programs are structured to minimize drilling risks and optimize tax advantages for retail investors. To develop exploratory prospects with higher risk profiles, we generally rely on smaller, specialized partnerships with strategic and industry partners or other suitable investors. At the commencement of operations, drilling rights for specified wells are assigned by DPI to each Drilling Program, which enters into turnkey drilling contracts with DPI for drilling and completing the wells at specified prices. We are responsible for any drilling and completion costs exceeding the contract price, and we are entitled to any surplus if the contract price exceeds our costs.

In addition to managing program operations, we invest in each Drilling Program on substantially the same terms as unaffiliated investors. We contribute capital to each Drilling 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 increased our contribution to our 2005 development

Drilling Programs from 25% to 30% of total program capital, and we have a 40% stake in a specialized Drilling Program sponsored in the second quarter this year to drill 18 development wells and two exploratory wells on our acquired SME properties. We also maintain a 1% interest as general partner of those programs. We bear all selling costs for Drilling Program financings and all direct overhead and administrative costs for program operations. The return on our investment is limited to our share of program distributions and any profits we realize under our turnkey drilling contracts, net of our proportionate share of those profits. We also receive customary fees for well operating and gas gathering, dehydration and compression services.

Drilling Program Benefits. Our structure for sharing Drilling Program costs, risks and returns helps us attract outside capital from private investors. This addresses the high capital costs of our business, enabling us to accelerate the development of our properties without relinquishing control over drilling and operating decisions. The structure also provides economies of scale with operational benefits at several levels.

	•		Based on outside capital of 70% to 75% invested in our development Drilling Programs, we control a drilling budget up to four times greater than we could support on our own. This helps us compete for attractive properties by increasing our drilling commitments. It also increases our buying power for drilling services and materials, contributing to lower overall development costs.

	•		Aggregating our capital with private investors in our Drilling Programs enables us to maintain a larger and more capable staff than we could otherwise support if we were operating solely for our own account.

	•		Accelerating the pace of development activities through our Drilling Programs expands the production capacity we can make available to gas purchasers, contributing to higher and more stable sales prices for our production.

	•		By conducting drilling operations on our undeveloped prospects through smaller, specialized Drilling Programs and retaining ownership interests ranging from 40% to 67%, we expand our inventory of developmental locations with lower risk profiles for larger, subsequent Drilling Programs, while adding to our proved reserves, both developed and undeveloped.

	•		Our Drilling Program strategy substantially increases the number of wells we could drill solely for our own account, diversifying the risks inherent in drilling operations.

Drilling Program Financings. In the first quarter of 2005, we completed a private placement of interests in our first Drilling Program for the year, with contributed capital aggregating $12,250,000 from outside investors. We have a 30.7% interest in the program, which has entered into turnkey drilling contracts for a total of 50 development wells. In the second quarter, we raised $5,400,000 from outside investors and contributed 40% of total capital for a specialized Drilling Program that will drill 18 development wells and two exploratory wells on our acquired SME properties. We are currently sponsoring a third Drilling Program for 2005 to drill up to 100 development wells.

Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2004 and the first six months of 2005. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests in wells drilled through our Drilling Programs, without giving effect to any reversionary interest we may subsequently earn in those programs. Productive wells listed below include wells that were drilled and successfully tested in at least one primary pay zone but were awaiting construction of gathering systems prior to completion at the end of the reported periods.


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

Year ended December 31, 2004		140		39.7149		—		15		10.0000		—
Six months ended June 30, 2005		84		23.9210		—		—		—		—

Well Characteristics. Our proved reserves, both developed and undeveloped, are concentrated in the Appalachian Basin in eastern Kentucky, one of the oldest and most prolific natural gas producing areas in the United States. Historically, wells in this area generally produce between 200 to 450 Mmcf of natural gas over a reserve life of up to 25 years. The natural gas in this area is also known for being environmentally friendly in the sense that wells produce small amounts of water or other impurities with the gas production. This helps us minimize production (lifting) costs. In addition, the average energy (or Dth) value of the natural gas produced in this area is substantially higher than normal pipeline quality gas, ranging from 1.1 to 1.3 Dth per Mcf of gas production. Our gas sales contracts generally provide upward adjustments to index based pricing for our natural gas with an energy value above 1 Dth per Mcf, enhancing cash flows and long term returns on our investments in these properties.

Results of Operations – Three Months Ended June 30, 2005 and 2004

Revenues. Total revenues for the quarter ended June 30, 2005 were $11,435,719, an increase of 37% from $8,327,169 in the same quarter last year. Our revenue mix for the second quarter of 2005 was 67% contract drilling, 31% oil and gas production and 3% natural gas transmission and compression. For the second quarter of 2004, our total revenues were derived 84% from contract drilling, 12% from oil and gas production and 4% from natural gas transmission and compression activities.

Contract drilling revenues were $7,639,000 for the second quarter of 2005, up 9% from $7,040,250 in the second quarter of 2004. This reflects both the size and the timing of Drilling Program financings, from which we derive substantially all our contract drilling revenues. Upon the closing of Drilling Program financings, DPI receives the net proceeds from these financings as customers’ drilling deposits under turnkey drilling contracts with the programs. We recognize revenues from drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Drilling operations for our initial 2005 Drilling Programs were ongoing during the second quarter of 2005, when we drilled 27 gross (7.1661 net) natural gas wells.

Production revenues for the three months ended June 30, 2005 were $3,507,703, an increase of 255% from $986,724 in the second quarter of 2004. This reflects an increase of 140% in our production volumes to 437.0 Mmcfe in the second quarter of 2005 from 182.3 Mmcfe in the same quarter last year. Our growth in production volumes resulted from new wells brought on line since June 30, 2004 and wells added from property acquisitions in the second half of 2004. The growth in production revenues also reflects a 45% increase in our average sales price of natural gas (before certain transportation charges) to $7.97 per Mcf in the second quarter of 2005 from $5.50 per Mcf in same quarter last year, reflecting continued strength in natural gas prices. Principal purchasers of our natural gas production are gas marketers and customers with transmission facilities near our producing properties. During the second quarter of 2005, approximately 35% of our natural gas production 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 $289,016 during the second quarter of 2005, down 4% from $300,195 in the second quarter of 2004. This reflects continued reliance by sponsored Drilling Programs on our own gathering systems. During the second quarter of 2005, we extended our natural gas gathering systems for new wells by approximately 47 miles. Our gas transmission and compression revenues for the second quarter of 2005 also reflect a contribution of $37,024 from gas utility sales, compared to $42,998 in the same quarter last year.

Expenses. Total direct expenses increased by 35% to $7,744,038 for the three months ended June 30, 2005, compared to $5,743,646 for the second quarter of 2004. Our direct expense mix for the current reported quarter was 85% contract drilling, 12% oil and gas production and 3% natural gas transmission and compression. For the second quarter of 2004, our total direct expenses were incurred 91% in contract drilling, 7% in oil and gas production and 2% in natural gas transmission and compression.

Contract drilling expenses of $6,618,260 during the second quarter of 2005 increased 26% from $5,236,941 in the year-earlier quarter. As a percentage of contract drilling revenues, these expenses increased from 74% in the second quarter of 2004 to 87% in the current reported quarter. This primarily reflects the substantial level and complexity of recent drilling activities under our turnkey drilling contracts with sponsored Drilling Programs. We are entitled to any surplus if the contract price exceeds our costs, and are responsible for any drilling and completion costs exceeding the contract price. See “Drilling Operations” above. During the second quarter of 2005, we

incurred substantial costs for downhole problems on three program wells. We also incurred the costs for adding lifting equipment and surface facilities to handle oil produced from a number of recently completed wells, primarily in our Straight Creek Field.

Production expenses were $890,694 in the second quarter of 2005, compared to $392,379 in the same quarter last year, reflecting our substantial growth in 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, production expenses decreased to 25% in the second quarter of 2005 from 40% in the same quarter last year.

Gas transmission and compression expenses in the second quarter of 2005 were $235,084, compared to $114,326 in the same quarter last year. Gas transmission and compression expenses do not reflect capitalized costs of $4,025,289 in the second quarter of 2005 for extensions of our gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

Selling, general and administrative (“SG&A”) expenses were $2,511,910 in the second quarter of 2005, an increase of 44% from $1,744,546 in the same quarter last year, primarily reflecting the timing and extent of our selling and promotional costs for sponsored Drilling Programs. The higher SG&A expenses for the second quarter of 2005 also reflect costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses. As a percentage of total revenues, SG&A expenses remained consistent at 22% in the current reported quarter compared to 21% in the second quarter of 2004.

Beginning in 2004, we adopted the fair value method of accounting for employee stock options. Under the new 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. In addition to an accrual of $109,038 for deferred compensation costs, we recognized $130,052 in the second quarter of 2005 from fair value accounting for employee stock options, compared to $78,408 in the same quarter last year.

Depreciation, depletion and amortization (“DD&A”) was $1,001,533 in the second quarter of 2005, compared to $255,475 in the same quarter of 2004. The increase in DD&A reflects additions of $48.7 million to oil and gas properties and $9.8 million to gas gathering systems and well equipment since June 30, 2004.

Interest expense for the second quarter of 2005 was $555,001, compared to $107,535 in the second quarter of 2004. This reflects higher total debt to support our SME acquisition in October 2004, when we added $14.7 million of bank debt and $6.1 million of convertible debt, together with our most recent convertible note financing of $8.0 million to support ongoing drilling and gas gathering initiatives. See “Liquidity and Capital Resources” below.

Net Income (Loss). We recognized a net loss of $535,652 for the three months ended June 30, 2005, compared to net income of $208,383 realized in the second quarter of 2004, reflecting the foregoing factors. Basic earnings (loss) per share were ($0.03) based on 16,005,158 weighted average common shares outstanding in the second quarter of 2005, compared to $0.02 per share based on 13,877,212 weighted average common shares outstanding in the same quarter last year.

Results of Operations – Six Months Ended June 30, 2005 and 2004

Revenues. Total revenues for the six months ended June 30, 2005 were $31,445,965, an increase of 32% from $23,893,051 in the same period last year. Our revenue mix for the first six months of 2005 was 77% contract drilling, 20% oil and gas production and 3% natural gas transmission and compression. For the first six months of 2004, our total revenues were derived 89% from contract drilling, 8% from oil and gas production and 3% from natural gas transmission and compression activities.

Contract drilling revenues were $24,316,000 for the first six months of 2005, up 14% from $21,366,375 in the year-earlier period. This reflects both the size and the timing of Drilling Program financings, from which we derive substantially all our contract drilling revenues. Drilling operations for our 2004 year-end and initial 2005 Drilling Programs were ongoing during the first six months of 2005, when we drilled 84 gross (23.9210 net) natural gas wells.

Production revenues for the six months ended June 30, 2005 were $6,383,491, an increase of 259% from $1,778,013 the same period of 2004. This reflects an increase of 155% in our production volumes to 833.9 Mmcfe in the first half of 2005 from 326.4 Mmcfe in the same period last year. Our growth in production volumes resulted from new wells brought on line since June 30, 2004 and wells added from property acquisitions in the second half of 2004. The growth in production revenues also reflects a 39% increase in our average sales price of natural gas (before certain transportation charges) to $7.63 per Mcf in the first half of 2005 from $5.50 per Mcf in same period last year, reflecting continued strength in natural gas prices. During the current reported period, approximately 35% of our natural gas production 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 $746,474 during the first six months of 2005, compared to $748,663 in the year-earlier period. This reflects continued reliance by sponsored Drilling Programs on our own gathering systems. During the first half of 2005, we extended our natural gas gathering systems for new wells by approximately 76 miles. Our gas transmission and compression revenues for the current period also reflect a contribution of $186,165 from gas utility sales, compared to $183,969 in the prior period.

Expenses. Total direct expenses increased by 29% to $21,265,448 for the six months ended June 30, 2005, compared to $16,525,868 for the first six months of 2004. Our direct expense mix for the current reported quarter was 89% contract drilling, 8% oil and gas production and 3% natural gas transmission and compression. For the first six months of 2004, our total direct expenses were incurred 93% in contract drilling, 4% in oil and gas production and 3% in natural gas transmission and compression.

Contract drilling expenses during the first six months of 2005 were $18,988,065, or 78% of contract drilling revenues, compared to $15,341,589, or 72% of contract drilling revenues, in the same period last year. This primarily reflects the substantial level and complexity of recent drilling activities under our turnkey drilling contracts with sponsored Drilling Programs. During the current reported period, we incurred substantial costs for downhole problems on three program wells. We also added lifting equipment and surface facilities at considerable expense for handling oil produced from a number of recently completed wells, primarily in our Straight Creek Field.

Production expenses were $1,649,515 in the first half of 2005, compared to $670,087 in the same period last year, reflecting our substantial growth in 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, production expenses decreased to 26% in the current reported period from 38% in the prior period.

Gas transmission and compression expenses in the first six months of 2005 were $627,868, compared to $514,192 in the same period last year. Gas transmission and compression expenses do not reflect capitalized costs of $5,531,716 in the first six months of 2005 for extensions of our gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line.

SG&A expenses were $6,018,735 in the first half of 2005, an increase of 22% from $4,930,064 in the same period last year, primarily reflecting the timing and extent of our selling and promotional costs for sponsored Drilling Programs. The higher SG&A expenses for the current period also reflect costs for supporting expanded operations as a whole, including additions to our staff and technology infrastructure as well as increased salary and other employee related expenses. As a percentage of total revenues, SG&A expenses decreased to 19% in the current reported period compared to 21% in the first half of 2004.

For the first six months of 2005, in addition to an accrual of $218,076 for deferred compensation costs, we recognized a non-cash charge of $273,622 from fair value accounting for employee stock options, compared to $108,483 in the same period last year.

DD&A was $2,048,088 in the first half of 2005, compared to $508,604 in the same period of 2004. The increase in DD&A reflects substantial additions to our oil and gas properties and gas gathering systems since June 30, 2004.

Interest expense for the first six months of 2005 was $1,063,754, compared to $196,703 in the year-earlier period. This reflects higher total debt to support our SME acquisition in October 2004, when we added $14.7 million of bank debt and $6.1 million of convertible debt, together with our most recent convertible note financing of $8.0 million to support ongoing drilling and gas gathering initiatives. See “Liquidity and Capital Resources” below.

We recognized income tax expense of $607,870 in the first half of 2005, all of which was recorded as a future tax liability. This primarily reflects a 15% allocation of intangible drilling costs from our retail Drilling Programs, which reduces our cash outlays that would otherwise be required for current income taxes.

Net Income. We realized net income of $201,414 for the six months ended June 30, 2005, compared to $975,624 in the first six months of 2004, reflecting the foregoing factors. Basic earnings per share were $0.01 based on 15,848,386 weighted average common shares outstanding in the first six months of 2005, compared to $0.08 per share based on 12,964,698 weighted average common shares outstanding in the same quarter last year.

The results of operations for the quarter and six months ended June 30, 2005 are not necessarily indicative of results to be expected for the full year.

Liquidity and Capital Resources

Liquidity. Net cash provided by our operating activities in the first six months of 2005 was $10,967,589. Our cash position during the current reported period was decreased by the use of $14,606,502 in investing activities, reflecting net additions of $13,903,954 to our oil and gas properties. These investments were funded in part with net cash of $7,235,972 from financing activities, comprised primarily of proceeds from a convertible note financing received in the first quarter of 2005. See “Capital Resources” below. As a result of these activities, net cash increased to $15,446,431 at June 30, 2005 from $11,849,372 at December 31, 2004.

As of June 30, 2005, we had a working capital deficit of $6,967,674. This reflects wide fluctuations in our current assets and liabilities from the timing of customers’ deposits and expenditures under turnkey drilling contracts with our Drilling 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 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 generally 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.

We completed two institutional private placements of common stock during 2004. The proceeds from these equity financings and from convertible note financings described below have been allocated primarily to construction of gas gathering lines and our investments in sponsored Drilling Programs. See “Drilling Operations” above. The terms of the equity financings are summarized in the following table:


			Per Share
	Number of		Subscription
Closing Date	Shares Issued		Price		Proceeds
April 28, 2004		975,000	$	5.98	$	5,832,450
November 2, 2004		279,330		5.37		1,500,000

Total		1,254,330			$	7,332,450

We issued convertible notes in the aggregate principal amounts of $6,168,696 in the first quarter of 2005 and $7,931,304 in 2004. The notes bear interest at 7% per annum and are convertible at the option of the holders into our common stock at $6.00 per share. Several prior series of convertible notes have been partially converted by the holders, reducing their total principal amount outstanding at June 30, 2005 to $2,487,377. The prior series of notes bear interest at rates ranging from 7% to 10% per annum and are convertible at the option of the holders into our common stock at prices ranging from $1.50 to $6.00 per share. Notes of one prior series issued in September 2003 required the payment of interest in kind through September 30, 2004, resulting in the issuance of addition paid-in-kind notes aggregating $178,924.

On July 11, 2005, we issued a notice of redemption to holders of our 10% convertible notes due May 1, 2007. The notes were convertible into our common shares prior to redemption at a conversion price of $1.50 per share and were redeemable at 100% of their principal amount, plus accrued interest through the redemption date. At June 30, 2005, notes of this series in the aggregate principal amount of $515,500 were outstanding. All of the notes were converted by their holders prior to the redemption date. We may elect to call other series of our outstanding convertible notes for redemption, depending on market conditions. All of the common shares issuable upon conversion of these notes are registered for resale by their holders under the Securities Act of 1933.

In addition to our remaining outstanding convertible notes, we maintain a credit facility with KeyBank NA. The facility is secured by liens on all corporate assets, including a first mortgage on oil and gas interests and pipelines, as well as an assignment of major production and transportation contracts. During the fourth quarter of 2004, the credit limit for the facility was increased from $10 million to $20 million, subject to semi-annual borrowing base determinations by the bank. In connection with our SME acquisition in October 2004, the borrowing base for the facility was established at $15 million, of which $14.7 million was applied to fund part of the $27 purchase price for the SME assets. See “Strategy – Purchase of Producing Properties” above. Borrowings under the facility bear interest payable monthly at 1% above the bank’s prime rate, amounting to 7.25% at June 30, 2005. As of that date, borrowings under the facility totaled $15 million.

Our remaining long term debt outstanding at June 30, 2005 aggregated $378,818 on a secured note issued in 1986 for the acquisition of our mineral property in Alaska and $9,579 on miscellaneous obligations incurred to finance various property and equipment acquisitions. Our ability to repay this acquisition debt as well as our bank debt and any convertible notes that are not converted prior to maturity will be subject to our future performance and prospects as well as market and general economic conditions. We may 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 to 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 and cash flow from operations to provide adequate working capital to meet our capital expenditure objectives through the fourth quarter of 2005, including our anticipated contributions to Drilling Programs. See “Drilling Operation” above. 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 as well as continued participation by investors in future Drilling Programs.

Forward Looking Statements

This report includes forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) relating to anticipated operating and financial performance, business and financing prospects, developments and results of our operations. Actual performance, prospects, developments and results may differ materially from anticipated results due to economic conditions and other risks, uncertainties and circumstances partly or totally outside our control, including operating risks inherent in oil and gas development and producing activities, fluctuations in market prices of oil and natural gas, changes in future development and production costs and uncertainties in the availability and cost of capital. Words such as “anticipated,” “expect,” “intend,” “plan” and similar expressions are intended to identify forward looking statements, all of which are subject to these risks and uncertainties.

Related Party Transactions

Because we operate through subsidiaries and affiliated Drilling Programs, our holding company structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. It is our policy to structure any transactions with related parties only on terms that are no less favorable to the Company than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions are summarized in Notes 4 and 12 of the footnotes to the accompanying condensed consolidated financial statements.

Contractual Obligations and Commercial Commitments

The Company has contractual obligations to make payments at specified times and amounts under leases for office facilities and field equipment and instruments governing its long term debt and other commercial commitments. The following table lists the Company’s minimum annual obligations as of June 30, 2005 under non-cancelable operating leases, debt instruments and other commercial commitments.


	Operating		Long Term			Other
Year	Leases		Debt			Commitments			Total
Balance of 2005	$	275,432	$	21,579		$	240,000	⁽¹⁾	$	539,011
2006		547,048		15,024,000			—			15,571,048
2007		547,732		539,500	⁽²⁾		—			1,087,232
2008		287,809		1,995,877			100,000	⁽³⁾		2,383,686
2009		195,000		5,524,000	⁽⁴⁾		2,045,000	⁽³⁾		7,764,000
2010 and thereafter		97,500		8,270,818			—			8,368,319


Total	$	1,950,521	$	31,375,774		$	2,385,000		$	35,711,295


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

(2)		Includes $515,500 principal amount of the Company’s 10% convertible notes due May 1, 2007, all of which were converted after June 30, 2005. See “Capital Resources” above.

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

(4)		Does not reflect the conversion during July and the first half of August 2005 of $4,200,000 principal amount of the Company’s 7% convertible notes due October 4, 2009.

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. The following critical accounting policies relate to the more significant judgments and estimates used in the preparation of the condensed consolidated financial statements.

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, 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 their carrying values are not recoverable.

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 Exchange Act. 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, 2005. 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 first quarter of 2005 that have materially affected or are reasonably likely to materially affect our internal control of financial reporting.

PART II. OTHER INFORMATION

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

In the first quarter of 2005, we issued $6,168,696 principal amount of our 7% convertible notes due March 31, 2010. The notes are convertible at the option of the holders into the Company’s common stock at a conversion price of $6.00 per share and are redeemable by the Company at 100% of their principal amount plus accrued interest through the date of redemption. The notes were issued in the private placement in accordance with Regulation D under the Securities Act of 1933. Proceeds from the sale of notes, including an additional $1,831,304 principal amount of the same series of notes issued in the fourth quarter of 2004, have been allocated primarily to construction of gas gathering lines and our investments in sponsored Drilling Programs.

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

On June 9, 2005, we held our annual meeting of shareholders. All of the incumbent directors listed in our proxy statement for the meeting were reelected. The number of votes cast for and against each nominee is set forth below.


			Votes
Nominee	Votes For		Withheld
William S. Daugherty		13,642,621		255,883
James K. Klyman		13,643,108		255,396
Charles L. Cotterell		13,643,108		255,396
Thomas F. Miller		13,643,108		255,396

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 Kraft, Berger, Grill, Schwartz, Cohen & March, LLP as our auditors for 2005. The number of votes cast for and against each of these proposals is set forth below.


			Votes		Votes
Proposal	Votes For		Against		Withheld
Fixing the size of the board of directors at four members		13,490,187		452,379		255,396
Ratification of the appointment of independent public accountants		13,694,591		—		203,311

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).

4.1		Form of 7% Convertible Promissory Note due September 5, 2008 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K [File No. 0-12185] dated September 10, 2003).

4.1		7% Convertible Promissory Note in the principal amount of $6,100,000 due October 4, 2009 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K [File No. 0-12185] dated October 4, 2004).

4.3		Note Purchase Agreement for 7% Convertible Promissory Notes in the principal amount of $8,000,000 due March 31, 2010 (incorporated by reference to Exhibit 10.13 to Registration Statement on Form S-3 (File No. 333-125053) filed May 19, 2005).

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).


*Exhibit*
*Number*		*Description of Exhibit*
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		Form of Common Stock Purchase Warrant dated September 10, 2003 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K [File No. 0-12185] dated September 10, 2003).

10.5		Form of Common Stock Purchase Warrant dated December 31, 2003 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K [File No. 0-12185] dated January 2, 2003).

10.6		Form of Common Stock Purchase Warrant dated April 29, 2004 (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K [File No. 0-12185] dated September 29, 2003).

10.7		Form of Common Stock Purchase Warrant dated October 4, 2004 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K [File No. 0-12185] dated October 4, 2004).

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

21.1		Subsidiaries (incorporated by reference to Exhibit 21.1 to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2004).

31.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended.

31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended.

32.1		Certification of Chief Executive Officer pursuant to Rule 13a-14(b) under the Securities Exchange Act of 1934, as amended.

32.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(b) under the Securities Exchange Act of 1934, as amended.

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 15, 2005	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 Good

Ngas Resources (NGAS) Inactive 10-Q2005 Q2 Quarterly report

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Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents