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  **UNITED STATES SECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549****FORM 10-Q**   þ **QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934******For the Quarter Ended March 31, 2007****   o **TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF EXCHANGE ACT****Commission File No. 0-12185****NGAS Resources, Inc.****(Exact name of registrant as specified in its charter)**   **Province of British Columbia** **Not Applicable****(State or other jurisdiction of** **(I.R.S. Employer****incorporation or organization)** **Identification No.)**   **120 Prosperous Place, Suite 201**  **Lexington, Kentucky** **40509-1844****(Address of principal executive offices)** **(Zip Code)****Registrant’s telephone number, including area code: (859) 263-3948**(Former name or former address, if changed since the last report)     Indicate by check mark if the registrant (1) filed all reports required to be filed bySection 13 or 15(d) of the Act during the past 12 months and (2) has been subject to those filingrequirements for the past 90 days. Yes þ No o     Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer(each as defined in Rule 12b-2) or a non-accelerated filer.Large accelerated filer o       Accelerated filer þ       Non-accelerated filer o     Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2). Yes o No þNumber of shares outstanding of each of the registrant’s classes of common equity, as of thelatest practicable date.   **Title of Class** **Outstanding at May 8, 2007****Common Stock** **21,798,551**  
 

 
 **NGAS Resources, Inc.****INDEX**       **Page****Part I. Financial Information**    ***Item 1. Financial Statements*****:**    Condensed Consolidated Balance Sheets – March 31, 2007 (unaudited) and December 31, 2006   1 Condensed Consolidated Statement of Operations – Three months ended March 31, 2007 and 2006   2 Condensed Consolidated Statement of Cash Flows – Three months ended March 31, 2007 and 2006   3 Notes to Condensed Consolidated Financial Statements   4 ***Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations***  12 ***Item 3. Quantitative and Qualitative Disclosures about Market Risk***  20 ***Item 4. Controls and Procedures***  20 **PART II. OTHER INFORMATION**    ***Item 6. Exhibits***  20  EX-31.1 EX-31.2 EX-32.1 EX-32.2 **Forward-Looking Statements**     Some matters discussed in this report are prospective and constitute forward-lookingstatements within the meaning of the Private Litigation Reform Act of 1995. Other than statementsof historical fact, all statements that address our future activities, events, outcomes and othermatters we plan, expect, budget, intend or estimate (and other similar expressions) areforward-looking statements. While we believe these forward-looking statements are based onreasonable assumptions, they involve known and unknown risks, uncertainties and other factors thatmay cause future results to differ materially from those discussed or implied in this report.Additional information about issues that could cause actual results to differ from ourforward-looking statements is provided in our annual report on Form 10-K for the year endedDecember 31, 2006. **Additional Information**     We file annual, quarterly and other reports and information with the Securities ExchangeCommission. Promptly after their filing, we provide access to these reports without charge on ourwebsite at www.ngas.com. 
 

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**NGAS Resources, Inc.****CONDENSED CONSOLIDATED BALANCE SHEETS**           **March 31,**  **December 31,**   **2007**  **2006**   **(Unaudited)**     ASSETS        Current assets:        Cash  $2,051,447  $14,431,977 Accounts receivable   6,476,208   9,108,574 Prepaid expenses and other current assets   1,076,021   1,108,734 Loans to related parties   7,373   7,147        Total current assets   9,611,049   24,656,432          Bonds and deposits   558,695   533,695 Oil and gas properties   153,048,673   144,217,532 Property and equipment   3,649,515   3,342,571 Loans to related parties   255,361   257,430 Deferred financing costs   2,124,729   2,264,022 Other non-current assets   3,161,533   2,634,271 Goodwill   313,177   313,177                 Total assets $172,722,732  $178,219,130                 LIABILITIES        Current liabilities:        Accounts payable   6,231,327   9,286,849 Accrued liabilities   3,336,805   3,998,978 Customers’ drilling deposits   5,940,637   12,173,905 Long term debt, current portion   24,000   24,000        Total current liabilities   15,532,769   25,483,732          Deferred income taxes   8,369,185   8,035,779 Long term debt   71,004,957   66,922,744 Deferred compensation   1,565,578   1,419,776                 Total liabilities   96,472,489   101,862,031                 SHAREHOLDERS’ EQUITY                 Capital stock        *Authorized*:        5,000,000     Preferred shares         100,000,000 Common shares        *Issued*:        21,798,551   Common shares (2006 – 21,788,551)   84,572,132   84,531,832 21,100         Common shares held in treasury, at cost   (23,630)  (23,630)Paid-in capital – options and warrants   3,268,608   3,073,287 *Contributed surplus*  1,307,861   1,396,074 *To be issued*:        9,185            Common shares (2006 – 9,185)   45,925   45,925           89,170,896   89,023,488 Deficit   (12,920,653)  (12,666,389)                Total shareholders’ equity   76,250,243   76,357,099                 Total liabilities and shareholders’ equity $172,722,732  $178,219,130        *See accompanying notes.*
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**NGAS Resources, Inc.****CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS****(Unaudited)**           **Three Months Ended**   **March 31,**   **2007**  **2006** REVENUE        Contract drilling  $9,245,219  $20,411,500 Oil and gas production   6,752,232   6,204,184 Gas transmission and compression   1,947,941   703,571        Total revenue   17,945,392   27,319,255                 DIRECT EXPENSES        Contract drilling   7,180,717   16,702,930 Oil and gas production   1,683,014   1,453,468 Gas transmission and compression   1,099,593   632,429        Total direct expenses   9,963,324   18,788,827                 OTHER EXPENSES (INCOME)        Selling, general and administrative   4,021,882   4,474,392 Options, warrants and deferred compensation   341,123   428,747 Depreciation, depletion and amortization   2,306,470   1,537,912 Interest expense   1,224,756   600,383 Interest income   (84,054)  (118,360)Other, net   92,749   40,948        Total other expenses   7,902,926   6,964,022                 INCOME BEFORE INCOME TAXES   79,142   1,566,406                 DEFERRED INCOME TAX EXPENSE   333,406   940,669                 NET INCOME (LOSS)  $(254,264) $625,737                 Basic  $(0.01) $0.03        Diluted  $(0.01) $0.03                 WEIGHTED AVERAGE COMMONSHARES OUTSTANDING        Basic   21,791,107   21,377,525        Diluted   21,791,107   23,177,078        *See accompanying notes.*
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**NGAS Resources, Inc.****CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS****(Unaudited)**           **Three Months Ended**   **March 31,**   **2007**  **2006** OPERATING ACTIVITIES        Net income (loss)  $(254,264) $625,737 Adjustments to reconcile net income (loss) tonet cash used in operating activities:        Incentive bonus paid in common shares   —   291,032 Compensation from options and warrants   341,123   428,747 Depreciation, depletion and amortization   2,306,470   1,537,912 Gain (loss) on sale of assets   (5,920)  18,958 Deferred income taxes   333,406   940,669 Changes in assets and liabilities:        Accounts receivable   2,632,366   (197,641)Prepaid expenses and other current assets   32,713   1,608,781 Other non-current assets   (527,262)  (823,944)Accounts payable   (3,055,522)  1,533,980 Accrued liabilities   (662,173)  2,804,756 Customers’ drilling deposits   (6,233,268)  (15,828,600)       Net cash used in operating activities   (5,092,331)  (7,059,613)                INVESTING ACTIVITIES        Proceeds from sale of assets   27,200   — Purchase of property and equipment   (510,401)  (324,742)Increase in bonds and deposits   (25,000)  (1,000)Additions to oil and gas properties, net   (10,816,141)  (25,521,311)       Net cash used in investing activities   (11,324,342)  (25,847,053)                FINANCING ACTIVITIES        Decrease in loans to related parties   1,843   20,641 Proceeds from issuance of common shares   40,300   168,056 Payments of deferred financing costs   —   (75,000)Proceeds from issuance of long term debt   4,000,000   17,978,933 Payments of long term debt   (6,000)  (6,000)       Net cash provided by financing activities   4,036,143   18,086,630                 Change in cash   (12,380,530)  (14,820,036)Cash, beginning of period   14,431,977   23,944,252        Cash, end of period  $2,051,447  $9,124,216                 SUPPLEMENTAL DISCLOSURE        Interest paid  $1,231,044  $666,000 Income taxes paid   —   — *See accompanying notes.*
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**NGAS Resources, Inc.****NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS****(Unaudited)*****Note 1. Summary of Significant Accounting Policies***     (a) *General*. The accompanying condensed consolidated financial statements of NGASResources, Inc. (*NGAS*) have been prepared in accordance with accounting principles generallyaccepted in the United States of America (*U.S. GAAP*). Our accounting policies are described inNote 1 to the consolidated financial statements in our annual report on Form 10-K for the yearended December 31, 2006. Except as noted below, our accounting policies and their method ofapplication in the accompanying condensed consolidated financial statements are consistent withthose described in the annual report.     (b) *Basis of Presentation*. The accompanying condensed consolidated financialstatements include the accounts of NGAS, our wholly owned subsidiary, Daugherty Petroleum, Inc.(*DPI*), and its wholly owned subsidiaries. The condensed consolidated financial statements alsoreflect DPI’s interests in a total of 35 drilling programs sponsored to participate in its drillingoperations. We account for those interests using the proportionate consolidation method, with allmaterial inter-company accounts and transactions eliminated on consolidation. References to the*Company*, *we*, *our*or *us*include DPI, its subsidiaries and interests in sponsored drilling programs.These interim consolidated financial statements are unaudited but reflect all normal recurringadjustments that, in the opinion of our management, are necessary to fairly present our financialposition at March 31, 2007 and results of operations and cash flows for the three months endedMarch 31, 2007 and 2006.     (c) *Estimates**.*The preparation of financial statements in conformity with U.S. GAAPrequires us to make estimates and assumptions that affect the reported amounts of assets andliabilities and the disclosure of contingent assets and liabilities as of the date of theconsolidated financial statements and the reported amounts of revenues and expenses during thereporting periods. The most significant estimates pertain to proved oil and gas reserves andrelated cash flow estimates used in impairment tests of goodwill and other long-lived assets,estimates of future development, dismantlement and abandonment costs and estimates relating tofuture oil and gas revenues and expenses. We also make estimates andassumptions in maintaining allowances for doubtful accounts whendeemed appropriate to reflect losses that could result from failuresby customers or other parties to make payments on our tradereceivables. The evaluations requiredfor all of these estimates involvesignificant uncertainties, and actual results could differ from the estimates.***Note 2. Oil and Gas Properties***     All of our oil and gas development and producing activities are conducted within thecontinental United States. Capitalized costs and accumulated depreciation, depletion andamortization (*DD&A*) for our oil and gas properties, gathering facilities and well equipment as ofMarch 31, 2007 and December 31, 2006 are summarized below.           **March 31,**  **December 31,**   **2007**  **2006** Proved oil and gas properties $118,693,664  $110,169,303 Unproved oil and gas properties   3,325,397   3,000,465 Gathering facilities and well equipment   48,336,706   46,369,858           170,355,767   159,539,626 Accumulated DD&A   (17,307,094)  (15,322,094)                Net oil and gas properties and equipment $153,048,673  $144,217,532        
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***Note 3. Property and Equipment***     The following table presents the capitalized costs and accumulated depreciation for our otherproperty and equipment as of March 31, 2007 and December 31, 2006.           **March 31,**  **December 31,**   **2007**  **2006** Land  $12,908  $12,908 Building improvements   60,731   48,350 Machinery and equipment   2,980,384   2,680,174 Office furniture and fixtures   160,802   129,031 Computer and office equipment   598,194   569,877 Vehicles   1,699,714   1,607,554           5,512,733   5,047,894 Accumulated depreciation   (1,863,218)  (1,705,323)                Net other property and equipment  $3,649,515  $3,342,571        ***Note 4. Deferred Financing Costs***     Financing costs for our convertible note private placements and secured credit facility areinitially capitalized and amortized at rates based on the terms of the underlying debt instruments.These costs include $354,819 incurred in the third quarter of 2006 for our new credit facility.See Note 7 – Long Term Debt. Upon conversion of convertible notes, the principal amount convertedis added to equity, net of a proportionate amount of the original financing costs. Unamortizeddeferred financing costs for our outstanding notes and credit facility aggregated $2,124,729 atMarch 31, 2007 and $2,264,022 at December 31, 2006, net of accumulated amortization totaling$1,061,617 and $922,324, respectively.***Note 5. Goodwill***     Goodwill of $1,789,564 was recorded in connection with our acquisition of DPI in 1993 and wasamortized over ten years on a straight-line basis until 2002, when we adopted the Canadianequivalent of SFAS No. 142, *Goodwill and Other Intangible Assets*. Under the adopted standard,goodwill is no longer amortized but is instead tested for impairment at least annually. Our annualanalyses indicated that no impairment charges were required. Accordingly, accumulated amortizationof goodwill remained at $1,476,387 as of March 31, 2007 and December 31, 2006, with unamortizedgoodwill of $313,177.***Note 6. Customer Drilling Deposits***     We sponsor and manage drilling programs to participate in our drilling initiatives, in whichwe maintain non-promoted interests ranging from 12.5% to 75%. Historically, we conducted drillingoperations under turnkey contracts with our sponsored drilling programs, requiring us to drill andcomplete wells at specified prices and entitling us to any surplus if the contract price exceededour costs. In 2006, we changed the structure of our new drilling programs from turnkey pricing tocost plus, with a view to reducing our exposure to price volatility for drilling services,equipment and steel casing requirements. Under both structures, net proceeds received underdrilling contracts with sponsored programs are recorded as customers’ drilling deposits at the timeof receipt. We recognize revenues from drilling operations on the completed contract method as thewells are drilled, rather than when funds are received. Customer drilling deposits aggregating$5,940,637 as of March 31, 2007 and $12,173,905 at December 31, 2006 represent unapplied drillingcontract payments for wells that were not yet drilled as of the balance sheet dates.***Note 7. Long Term Debt***     (a) *Convertible Notes*. We issued several series of convertible notes in privateplacements to finance part of our drilling and acquisition activities. During 2005, the notes ofall prior series were converted by their holders, either voluntarily or in response to ourredemption calls, resulting in our issuance of 3,439,478 common shares
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during the year. In December 2005, we completed an institutional private placement of a newseries of 6% convertible notes due December 15, 2010 in the aggregate principal amount of $37million, all of which remained outstanding at March 31, 2007, with a conversion price of $14.34,subject to adjustment for certain dilutive issuances of common stock. We also issued warrants inthe transaction, which expired unexercised in August 2006. See Note 8 – Capital Stock.     The purchase agreement for our outstanding 6% notes provides holders with certainparticipation rights in future financing transactions. It also provides for a holder electing toconvert a note before the second anniversary of the issuance date to a payment equal to thedifference between two years’ interest on the converted note and the interest already paid on thenote, unless the prevailing market price of our common stock exceeds 160% of the conversion price,payable at our option in cash or in common shares. After that date, if the prevailing market priceof the common stock exceeds 160% of the conversion price, we may redeem any unconverted notes at aredemption price equal to their principal amount plus accrued and unpaid interest. Any notes thatare neither redeemed nor converted prior to maturity will be repayable in cash or in common shares.Any common shares issued for interest payments on converted notes or upon redemption at theirmaturity will generally be valued for that purpose at 92.5% of their prevailing market price.     (b) *Credit Facility*. In September 2006, we entered into a credit agreement withKeyBank National Association, as agent and primary lender. The credit agreement provides DPI witha senior secured revolving credit facility that replaces its prior credit facility with KeyBank,which had a scheduled maturity date of July 31, 2007 and a borrowing base of $35 million. The newfacility has a five-year maturity for revolving term loans and letters of credit in an aggregateamount up to $125 million, with a borrowing base of $50 million at March 31, 2007. Under the termsof the credit agreement, outstanding borrowings bear interest at fluctuating rates ranging from theagent’s prime rate to 0.75% above that rate, depending on the amount of borrowing base utilization.Alternatively, we may elect Eurodollar based pricing from 1.5% to 2.5% above quoted LIBOR rates,depending on our borrowing base utilization. The credit agreement also provides for commitmentfees ranging from 0.375% to 0.5% of the unused borrowing base. As of March 31, 2007, outstandingborrowings under the facility aggregated $35 million, with $2 million in letters of credit. Thefacility is secured by liens on our interests in most of our producing wells. Obligations underthe facility are guaranteed by NGAS.     (c) *Acquisition Debt*. We issued a note for $854,818 to finance our 1986 acquisitionof mineral property on Unga Island, Alaska. The debt is repayable without interest in monthlyinstallments of $2,000 and is secured by liens on the acquired property, buildings and equipment.Although the acquisition agreement provides for royalties at 4% of net smelter returns or otherproduction revenues, the property has remained inactive. The remaining acquisition debt was$336,818 at March 31, 2007 and $342,818 at December 31, 2006.     (d) *Total Long Term Debt and Maturities*. The following tables summarize our totallong term debt at March 31, 2007 and December 31, 2006 and the principal payments due each yearthrough 2010 and thereafter.           **Principal Amount Outstanding**   **March 31,**  **December 31,**   **2007**  **2006** Total long term debt (including current portion)(1) $71,028,957  $66,946,744 Less current portion   24,000   24,000                 Total long term debt(1) $71,004,957  $66,922,744                 **Maturities of Debt**                 Remainder of 2007  $18,000     2008   24,000     2009   24,000     2010   35,716,139     2011 and thereafter   35,246,818      (1) Reflects allocations of $1,307,861 at March 31, 2007 and $1,396,074 at December 31, 2006from our 6% convertible notes in the principal amount of $37,000,000 based on equitycomponents of their conversion features and related warrants.
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***Note 8. Capital Stock***     (a) *Preferred Shares*. We have 5,000,000 authorized shares of preferred stock, none ofwhich were outstanding at March 31, 2007 or December 31, 2006.     (b) *Common Shares*. The following tables reflect transactions involving our commonstock during the periods presented.           **Number of**      **Shares**  **Amount** Common Shares Issued        Balance, December 31, 2005   21,357,628  $82,371,189 Issued to employees as incentive bonus   65,945   468,612 Issued upon exercise of stock options and warrants   336,106   1,472,026 Issued for contract settlement   28,872   220,005        Balance, December 31, 2006   21,788,551   84,531,832 Issued upon exercise of stock options and warrants   10,000   40,300        Balance, March 31, 2007   21,798,551  $84,572,132                 Paid In Capital – Options and Warrants        Balance, December 31, 2005      $2,743,806 Recognized       975,468 Expired       (565,946)Accreted(1)      (80,041)        Balance, December 31, 2006       3,073,287 Recognized       195,321         Balance, March 31, 2007      $3,268,608                  Contributed Surplus                 Balance, December 31, 2005      $1,748,926 Accreted(1)      (352,852)        Balance, December 31, 2006       1,396,074 Accreted(1)      (88,213)        Balance, March 31, 2007       1,307,861                  Common Shares to be Issued        Balance, March 31, 2007 and December 31, 2006   9,185  $45,925         (1) Reflects accretion of the equity components allocated to our 6% convertible notes andrelated warrants issued in 2005.     (c) *Stock Options and Awards*. We maintain three stock plans for the benefit ofour directors, officers, employees and, in the case of the second and third plans, certainconsultants or advisors. The plans provide for the grant of options to purchase up to 3,600,000common shares and, in the case of our most recent plan, either stock awards or options for anaggregate of up to 4,000,000 common shares. Option grants under all the plans must be atprevailing market prices and may be subject to vesting requirements over a period of up to tenyears from the date of grant. Stock awards under the third plan may be subject to vestingconditions and trading restrictions specified at the time of grant. During 2006, stock awards andoption grants were made under the third plan for a total of 65,945 shares. There were no awards orgrants in the first quarter of 2007. The following table shows transactions and vesting in stockoptions during the reported periods.
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                       **Weighted Average**  **Issued** **Exercisable** **Exercise Price**Balance, December 31, 2005   2,985,000   571,250  $4.67 Vested   —   509,583   4.26 Exercised   (135,000)  (135,000)  4.05 Forfeited   (35,000)  —   6.02              Balance, December 31, 2006   2,815,000   945,833   4.68 Vested   —   292,500   4.03              Balance, March 31, 2007   2,815,000   1,238,333   4.68                   At March 31, 2007, the exercise prices of options outstanding under our stock option plansranged from $1.02 to $7.04 per share, and their weighted average remaining contractual life was2.64 years. The following table provides additional information on the terms of stock optionsoutstanding at March 31, 2007.                         **Options Issued and Outstanding** **Options Exercisable**          **Weighted** **Weighted**     **Weighted****Exercise**     **Average** **Average**     **Average****Price**     **Remaining** **Exercise**     **Exercise****or Range** **Number** **Life (years)** **Price** **Number** **Price**$1.02      145,000   0.76  $1.02   145,000  $1.02 4.034.09     1,845,000   2.50   4.05   1,045,000   4.06 6.027.04     825,000   3.31   6.74   48,333   6.02                                 2,815,000           1,238,333                                   In accounting for stock options, we apply the fair value recognition provisions of SFAS No.123(R), *Share-Based Payment*, which we adopted retroactively under its Canadian GAAP equivalent in2004. We use the Black-Scholes pricing model to determine the fair value of each stock option atthe grant date, and we recognize the compensation cost ratably over the vesting period. For theperiods presented in the interim consolidated financial statements, the fair value estimates foreach option grant assumed a risk free interest rate ranging from 4.5% to 6%, no dividend yield, atheoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months tofive years based on the option’s vesting provisions. This resulted in non-cash charges for optionsand warrants of $975,468 in 2006 and $195,321 in the first three months of 2007.     (d) *Common Stock Purchase Warrants*. We have issued common stock purchase warrants invarious financing transactions. At December 31, 2006, we had outstanding warrants for the purchaseof 10,000 common shares at $4.03 per share, which were fully exercised in the first quarter of2007.***Note 9. Income (Loss) Per Share***     The following table shows the computation of basic and diluted earnings (loss) per share (*EPS*)for the reporting periods.
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           **Three Months Ended**   **March 31,**   **2007**  **2006** **Numerator:**        Net income (loss) as reported for basic EPS $(254,264) $625,737 Adjustments to income (loss) for diluted EPS  —   —        Net income (loss) for diluted EPS $(254,264) $625,737                 **Denominator:**        Weighted average shares for basic EPS  21,791,107   21,377,525 Effect of dilutive securities:        Stock options  —   1,584,900 Warrants  —   214,653        Adjusted weighted average shares for dilutive EPS  21,791,107   23,177,078                 Basic EPS  $(0.01) $0.03        Diluted EPS  $(0.01) $0.03        ***Note 10. Segment Information***     We have two reportable segments based on management responsibility and key businessoperations. The following table presents summarized financial information on these businesssegments.           **Three Months Ended**   **March 31,**   **2007**  **2006** **Revenue:**        Oil and gas development  $17,945,392  $27,319,255 Corporate   —   —        Total   17,945,392   27,319,255        **DD&A:**        Oil and gas development   2,142,426   1,386,745 Corporate   164,044   151,167        Total   2,306,470   1,537,912        **Interest expense:**        Oil and gas development   669,756   45,383 Corporate   555,000   555,000        Total   1,224,756   600,383        **Net income (loss):**        Oil and gas development   521,481   1,470,653 Corporate   (775,745)  (844,916)       Total   (254,264)  625,737        **Capital expenditures:**        Oil and gas development   11,198,942   25,764,868 Corporate   127,600   81,185        Total  $11,326,542  $25,846,053                   **March 31,**  **December 31,** **Identifiable assets:** **2007**  **2006** Oil and gas development $169,397,604  $174,750,803 Corporate  3,325,128   3,468,327        Total $172,722,732  $178,219,130        
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***Note 11. Commitments***     We incurred lease rental expenses of $1,727,982 in 2006 and $565,538 in the first three monthsof 2007. As of March 31, 2007, we have contractual obligations for periodic future payments underleases for field equipment and instruments governing its other commercial commitments in theamounts listed below.               **Commercial Commitments**   **Operating**  **Other**    **Year** **Leases**  **Commitments**  **Total** Remainder of 2007  $1,244,800  $240,000(1) $1,484,800 2008   1,410,410   100,000(2)  1,510,410 2009   1,310,502   2,045,000(2)  3,355,502 2010   1,211,834   —   1,211,834 2011 and thereafter   1,112,654   —   1,112,654                        Total  $6,290,200  $2,385,000  $8,675,200            (1) Reflects obligations under a guaranty secured by a certificate of deposit provided for bankdebt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held aminority interest. (2) Reflects commitments under a purchase contract for an airplane.***Note 12. Recent Accounting Standards***     SFAS No. 159. In February 2007, the Financial Accounting Standards Board (*FASB*)issued SFAS No. 159, *The Fair Value Option for Financial Assets and Financial Liabilities*. SFASNo. 159 permits fair value accounting for many financial instruments and related items that are notcurrently required to be measured at fair value. The objective is to mitigate volatility inreported earnings caused by measuring related assets and liabilities differently without having toapply complex hedge accounting provisions. We will adopt SFAS No. 159 at the beginning of 2008 anddo not expect its adoption to have a material impact on our consolidated financial condition orresults of operations.     SAB No. 108. In September 2006, the staff of the Securities and Exchange Commissionissued Staff Accounting Bulletin (*SAB*) No. 108, *Considering the Effects of Prior Year Misstatementswhen Quantifying Misstatements in Current Year Financial Statements*. SAB No. 108 providesinterpretive guidance on how the effects of the carryover or reversal of prior year financialstatement errors should be considered in quantifying a current year misstatement. Beginning in2007, prior year errors must be quantified using both a balance sheet and income statement approachand evaluated based on relevant quantitative and qualitative factors in determining theirmateriality for disclosure purposes. Application of this guidance has not had a material affect onour consolidated financial statements.     SFAS No. 158. In September 2006, the FASB issued SFAS No. 158, *Employers’ Accountingfor Defined Benefit Pension and Other Postretirement Plans*. SFAS No. 158 requires the employer torecognize the overfunded or underfunded status of any defined benefit postretirement plan as anasset or liability on its balance sheet and to recognize changes in that status through adjustmentsto comprehensive income. It also requires an employer to measure the funded status of a plan as ofthe date of its year-end balance sheet. These requirements are effective for fiscal years endingafter December 15, 2006. The adoption of SFAS No. 158 has not had a material impact on ourconsolidated financial position, results of operations or cash flows.     SFAS No. 157. In September 2006, the FASB issued SFAS No. 157, *Fair ValueMeasurements*, which defines fair value, establishes a framework for measuring fair value andexpands disclosure requirements about fair value measurements. The guidance in SFAS No. 157applies to fair value measurements for derivatives and other financial instruments at initialrecognition and in all subsequent periods. SFAS No. 157 is generally effective for all reportingperiods during fiscal years beginning after November 15, 2007. We do not expect any materialimpact on our consolidated financial position or results of operations from adoption of this newstandard.
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     FSP AUG AIR–1. In September 2006, the FASB issued FSP AUG AIR–1, *Accounting forPlanned Major Maintenance Activities*. FSP AUG AIR–1 prohibits companies from accruing the futurecosts of periodic major overhauls and maintenance of plant and equipment as a liability. Theprovisions of FSP AUG AIR–1 are effective for fiscal years beginning after December 15, 2006. Theimplementation of these provisions has not had a material impact on our consolidated financialstatements.     FIN No. 48. In July 2006, the FASB issued FASB Interpretation (*FIN*) No. 48,*Accounting for Uncertainty in Income Taxes – Interpretation of FASB No. 109*. FIN No. 48 requiresus to recognize the impact of a tax position on our financial statements if that position is morelikely than not to be sustained on audit, based on the technical merits of the position. Theprovisions of FIN No. 48 are effective at the beginning of 2007, with the cumulative effect of anyresulting change in accounting principles recorded as an adjustment to opening retained earnings.The adoption of FIN No. 48 has not had a material affect on our consolidated financial position.
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**NGAS Resources, Inc.****Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS*****General***          We are an independent exploration and production company focused on unconventional natural gasbasins in the eastern United States that support multiple, repeatable drilling, principally in thesouthern portion of the Appalachian basin. We specialize in generating our own geologicalprospects in this region, where we have established expertise and recognition. We also control thegas gathering and transmission facilities for our core Appalachian properties, providingdeliverability directly from the wellhead to interstate pipelines serving major east coast naturalgas markets. We believe our extensive geological, geophysical, engineering and operatingexperience in this region, coupled with our midstream assets, infrastructure position andrelationships with partners, suppliers and mineral interest owners, gives us competitive advantagesin developing these resources to achieve annual volumetric growth and strong financial returns on along term basis.          We develop our prospects through our operating subsidiaries and our interests in sponsoreddrilling programs. Our combined interest as both general partner and an investor in these programsranges from 12.5% to 75%, and we earn additional reversionary interests after targeted distributionthresholds are reached. Our principal and administrative offices are located in Lexington,Kentucky. Our common stock is traded on the Nasdaq National Market under the symbol *NGAS*. Unlessotherwise indicated, references in this report to *we*, *our*or *us*include NGAS Resources, Inc., ourdirect and indirect wholly owned subsidiaries and our interests in sponsored drilling programs. Asused in this report, *Dth*means decatherm, *Mcf*means thousand cubic feet, *Bcf*means billion cubicfeet, *Mcfe*means thousand cubic feet of gas equivalents, and*Bcfe* means billion cubic feet of gas equivalents.***Strategy***          Our business is structured to achieve capital appreciation through growth in our natural gasreserves, production, cash flow and earnings per share. During 2006, we achieved record productionof 2.9 Bcfe, up 57% from 2005, contributing to 28% growth in our total revenue to $79.8 million.We also increased our estimated proved reserves by 34% to 100.9 Bcfe at the end of 2006, of which42% are proved developed, with a reserve life index over 32 years based on annualized fourthquarter production. We achieved these benchmarks primarily through drilling success and a largernet position in new wells on our core properties. Our strategy for continuing to realize ouroperational and financial objectives for 2007 and beyond emphasizes several components. **•** *Acceleration of Drilling Operations*. Development drilling is our mainstay forproduction and reserve growth. We believe our long and successful operating history in theAppalachian basin and proven ability to drill a large number of wells year after year havepositioned us as a leading player in this region. We participated in 226 gross (65.4577net) wells during 2006 and an additional 57 gross (23.6000 net) wells in the first quarterof 2007. We have identified over 1,100 additional drilling locations on our Appalachianproperties for future development, including 550 locations in our key Leatherwood field,where we plan to continue our focus over the next few years. We are also acceleratingdevelopment of our Fonde field and other complementary Appalachian plays to consolidate ourposition in the region, while diversifying our asset base through targeted expansion inother unconventional natural gas basins.  **•** *Investment in Midstream Assets*. We operate a strategically located open-accessgas gathering system spanning 116 miles in southeastern Kentucky and southwestern Virginia.We acquired these midstream assets in March 2006 through our NGAS Gathering subsidiary for$18 million. We operated this system since October 2004 and augmented it after theacquisition through two high-pressure lateral upgrades. Ownership of these facilitiescompliments our field-wide Appalachian gathering systems, expanding our total gatheringposition to 544 miles as of March 31, 2007. We currently move production from ourLeatherwood, Straight Creek and SME fields for delivery through the NGAS Gathering system,with daily gross throughput of over 19,000 Dth. In addition to generating gas transmissionand compression revenues from third-party throughput and cost savings for our ownAppalachian production, ownership of these assets gives us control over gas flow from ourconnected fields and enhances our competitive position in the region.
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 **•** *Extension of Infrastructure*. We construct and operate field-wide gas gatheringand compression facilities for our Appalachian properties, which we continually upgrade tokeep pace with our expanding production base. Because we control third-party access tothese facilities, our 100% ownership of this infrastructure provides us with competitiveadvantages in acquiring and developing nearby acreage. Our field-wide systems spanned 428miles at March 31, 2007, including 103 miles of production lines installed in 2006 and 14miles in the first quarter this year. Recent additions to our infrastructure includefacilities that enabled us to bring a backlog of unconnected wells in our Leatherwood fieldon line sequentially for compression into the NGAS Gathering system. We are currentlyupgrading the main suction line for this field to enhance flow rates from new Leatherwoodwells. We are also extending our infrastructure to provide deliverability from our Fondefield through a 17-mile, six-inch steel line to our midstream system. Production in Fondehas historically been limited by pipeline capacity constraints. Our new system, scheduledfor completion in the third quarter of 2007, will connect over 60 Fonde wells and opennearly 50,000 acres to development in this field.  **•** *Repeatable Drilling*. As of March 31, 2007, we had interests in a total of1,067 wells. Most of our wells are drilled to relatively shallow total depths up to 5,000feet, generally encountering several predictable natural gas pay zones. We focus onrepeatable prospects to reduce drilling risks, as reflected in our success rate.Historically, over 99% of our Appalachian development wells have been completed asproducers. The primary pay zone for most of these wells is the Devonian shale formation.This is considered an unconventional target due to its low permeability, and naturalfracturing is often enhanced by effective acidizing or other treatments. While thistypically results in modest initial volumes and pressures, it also accounts for the lowannual decline rates demonstrated by our wells in the region, many of which are expected toproduce for 25 years or more.  **•** *Drilling Program Financings*. Our ability to attract outside capital throughour sponsored drilling programs has enabled us to capitalize on natural gas developmentopportunities and long range pricing expectations for this commodity. Beginning in 2006,we changed the structure of our new drilling programs from turnkey to cost-plus pricing,with a view to reducing our exposure to price volatility for drilling services, equipmentand steel casing requirements. We also tailored our new drilling programs for tieredparticipation on a field-wide basis, retaining program interests between 45% to 75% inLeatherwood development and from 12.5% to 60% in our other drilling initiatives.  **•** *Acquisition of Additional Drilling Prospects*. We follow a disciplined capitalallocation process in selecting opportunities to build our substantial inventory ofdrilling prospects that meet our criteria for predictable, long-lived reserves. During2006, we expanded our position in several of our major Appalachian fields. We alsoimplemented initiatives to leverage our core expertise with evolving technologies inhorizontal and directional drilling, which may provide advantages in extracting tight gasfrom unconventional formations. The initial programs are being conducted in the Arkomabasin on a coalbed methane (*CBM*) project, in the Illinois basin on acreage we acquired inwestern Kentucky to test the New Albany shale formation and in West Virginia on acreagecontrolled by a joint venture partner. We plan to continue capitalizing on opportunitiesto assemble or acquire interests in large tracts with significant development potential.Our goal is to consolidate our position in the Appalachian basin, while also diversifyingour prospect inventory with similar unconventional plays.***Regional Advantages***          Our proved reserves, both developed and undeveloped, are concentrated in the southern portionof the Appalachian basin. This is one of the oldest and most prolific natural gas producing areasin the United States. Typically, natural gas wells in this part of the Appalachian basin recoverbetween 100 to 500 Mmcf of reserves per drilling unit. The natural gas production, known as sweetgas, is environmentally friendly because it is substantially free of sulfur compounds, carbondioxide or other chemical impurities. In addition, most of these wells produce no water with thegas production. This helps us minimize production (lifting) costs. Appalachian gas also has theadvantage of high energy (Dth) content, ranging from 1.1 to 1.3 Dth per Mcf. Our gas salescontracts provide upward adjustments to index based pricing for throughput with an energy contentabove 1 Dth per Mcf, resulting in realized premiums averaging 17% over normal pipeline quality gas.Our proximity to major east coast markets generates further realization premiums above Henry Hubspot prices, contributing to enhanced cash flows and long term returns on investment.
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***Drilling Programs***          *Drilling Program Structure*. Most of our drilling operations are conducted throughsponsored programs structured to share development costs, risks and returns on repeatable prospectsand optimize tax advantages for private investors. To develop exploratory prospects with higherrisk profiles, we generally rely on smaller, specialized drilling programs with strategic andindustry partners or other suitable investors. Historically, we have conducted program operationsunder turnkey drilling contracts, requiring us to bear any drilling and completion costs exceedingthe contract price. In response to increased demand and price volatility for drilling services andequipment, we changed the structure of our drilling programs to cost-plus pricing, beginning in2006, with a view to sharing this exposure with our outside investors and stabilizing our marginsfor contract drilling operations.          *Drilling Program Benefits*. Our structure for drilling program participation in ourdevelopment initiatives helps us attract outside capital from private investors. This addressesthe high capital costs of our business, enabling us to accelerate the development of ourproperties, generally without relinquishing control over drilling and operating decisions. Thestructure also provides economies of scale with operational benefits at several levels. **•** Expanding our drilling budget with outside capital from program investors enables us tocompete for attractive properties by increasing our drilling commitments and to maintain alarger and more capable staff than we could otherwise support if we were operating solelyfor our own account. It also leverages our buying power for drilling services andmaterials, resulting in lower overall development costs.  **•** Accelerating the pace of development activities through our drilling programs expandsthe production capacity we can make available to gas purchasers, contributing to higher andmore stable sales prices for our production.  **•** By conducting exploratory operations through specially tailored programs, we expand ourinventory of developmental locations with lower risk profiles for subsequent programs,while adding to our proved reserves, both developed and undeveloped.  **•** Our drilling program strategy substantially increases the number of wells we coulddrill solely for our own account, diversifying the risks of drilling operations.          *Drilling Program Investments*. In addition to managing program operations, we investin each drilling program on substantially the same terms as outside investors. We contributecapital to each program in proportion to our initial ownership interest, and we share programdistributions in the same ratio until program distributions reach payout, which ranges from 100% to110% of partners’ investment. After payout, we are entitled to specified increases in ourdistributive share, up to 15% of the total program interests. In 2006 and the first quarter of2007, we sponsored a total of five new drilling programs under our cost-plus pricing structure.They include three programs for up to 184 wells in our major Appalachian fields, including 83 wellsin Leatherwood, where we maintained a 75% interest in our 2006 programs and 45% in our firstprogram this year. Our 2006 initiatives also included programs for 40 natural gas wells on acreagecontrolled by a joint venture partner in West Virginia and six horizontal CBM wells drilled byanother joint venture partner in the Arkoma basin. We have a 25% stake in the West Virginiaprogram and a 12.5% share of the Arkoma program.***Drilling Operations***          *Exploratory Initiatives*. We sponsored a specialized exploratory drilling program latein 2005 on acquired tracts in the Illinois basin spanning approximately 15,500 acres in westernKentucky to test the New Albany shale formation, which has similar geologic characteristics to theDevonian shale in the Appalachian basin. The initial phase of the project targeted the shallow NewAlbany shale on the eastern rim of the basin. There were 30 test wells for this phase, includingfive wells drilled with horizontal legs averaging 2,500 feet. Although we drilled and tested allthe wells in this phase below budget, we were not encouraged by the results, and we expensed thesuspended well costs for three of the wells during 2006. Late in the year, we began a five-welltest phase for our own account in the central portion of the Illinois basin, targeting the NewAlbany shale at greater depths through traditional vertical drilling. Treatment and flow testingon these wells were promising, and we plan to continue this phase of the central Illinois basinproject at a pace determined by ongoing results.
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          *Participation Rights*. The leases and farmouts for some of our acreage in theAppalachian basin, primarily the Leatherwood field, are subject to third-party participation rightsfor up to 50% of the working interests in new wells. We had third-party participation in ourLeatherwood wells for average working interests of 25.4% in 2006 and 10.9% during the first quarterof 2007.          *Drilling Results*. The following table shows the number of gross and net developmentand exploratory wells we drilled during 2006 and the first three months of 2007. Gross wells arethe total number of wells in which we have a working interest. Net wells reflect our workinginterests in wells, without giving effect to any reversionary interest we may subsequently earn inwells drilled through our drilling programs.                           **Development Wells** **Exploratory Wells**  **Productive** **Dry** **Productive** **Dry**  **Gross** **Net** **Gross** **Gross** **Net** **Gross**Year ended December 31, 2006   193   56.3007   —   30   8.5330   3 Three months endedMarch 31, 2007   52   18.6000   —   5   5.0000   —           *Production Volumes and Sales Prices*. The following table shows our total net oil andgas production volumes and average sales prices for the three months ended March 31, 2007 and 2006and for the year ended December 31, 2006. We also had extracted liquids and condensates thatcontributed $44,560 to our production revenues in the first three months of 2007 and $44,832 in2006.               **Three Months Ended**  **Year Ended**   **March 31,**  **December 31,**   **2007**  **2006**  **2006** Production volumes:            Oil (Bbl)   15,611   9,211   40,938 Natural gas (Mcf)   684,649   608,898   2,622,474                        Equivalents (Mcfe)   778,312   664,164   2,868,102                        Average sales price:            Natural gas (per Mcf)  $8.62  $9.35  $8.23 Oil (per Bbl)   51.44   50.73   59.60 ***Resultsof Operations — Three Months Ended March 31, 2007 and 2006***          *Revenues*. The following table shows the components of our revenues for the threemonths ended March 31, 2007 and 2006, together with their percentages of total revenue in thecurrent period and percentage change on a period-over-period basis.                   **Three Months Ended March 31,**       **% of**      **%**   **2007**  **Revenue**  **2006**  **Change** Contract drilling  $9,245,219   51% $20,411,500   (55)%Oil and gas production   6,752,232   38   6,204,184   9 Gas transmission and compression   1,947,941   11   703,571   177               Total  $17,945,392   100% $27,319,255   (34)              
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     Our revenue mix for the first quarter of 2007 reflects our ongoing strategy for transitioningto a production based business, with oil and gas sales accounting for 38% of total revenues,compared to 23% of total revenues for the year-earlier quarter and 30% for 2006 as a whole. Weexpect this trend to continue as we execute our initiatives for long term production growth byexpanding our infrastructure and acreage position in core fields and accelerating our developmentof these properties.     Contract drilling revenues reflect the size and timing of our drilling program financing, aswell as our percentage interest in drilling initiatives. Although we receive the proceeds fromprogram financings as customers’ drilling deposits under our drilling contracts with sponsoredprograms, we recognize revenues from drilling operations on the completed contract method as thewells are drilled, rather than when funds are received. We participated in 57 gross (23.6000 net)wells in the first quarter of 2007, including five exploratory wells for our own account, comparedto 79 gross (18.6535 net) wells in the same quarter last year. The contraction in third-partycontract drilling revenues reflects this reduction in gross wells, coupled with lower third-partyparticipation levels resulting from our increased net position in current drilling initiatives.     Our growth in production revenues on a period-over period basis reflects an increase of 17% inproduction volumes to 778,312 Mmcfe in the first quarter of 2007, with an 8% decline in our averagesales price of natural gas (before certain transportation charges) to $8.62 per Mcf. Ourvolumetric growth was driven by added production from new wells brought on line in the last twelvemonths. We anticipate ongoing production gains as we continue to upgrade our infrastructure andbring wells in Leatherwood and other key fields on stream. Principal purchasers of our productionare gas marketers and customers with transmission facilities near our producing properties.Approximately 45% of our natural gas production in the first quarter of 2007 was sold underfixed-price contracts, and the balance primarily at prices determined monthly under formulas basedon prevailing market indices.     Gas transmission and compression revenues were driven by fees totaling $894,080 for movingthird-party gas through our NGAS Gathering system, which we acquired in March 2006. This componentof revenues also reflects additional fees for gathering and compression of third-party gasproduction through our field-wide facilities, together with contributions of $137,996 from gasutility sales and $60,720 from our minority interest in the gathering system that services ourArkoma CBM project.     *Expenses*. The following table shows the components of our direct and other expensesfor the three months ended March 31, 2007 and 2006. Percentages listed in the table reflectmargins for each component of direct expenses and percentages of total revenue for each componentof other expenses.                   **Three Months Ended March 31,**  **2007**  **Margin**  **2006**  **Margin** Contract drilling  $7,180,717   22% $16,702,930   18%Oil and gas production   1,683,014   75   1,453,468   77 Gas transmission and compression   1,099,593   44   632,429   10                Total direct expenses   9,963,324   44   18,788,827   31                                       **% Revenue**      **% Revenue** Selling, general and administrative   4,021,882   22%  4,474,392   16%Options, warrants and deferred compensation   341,123   2   428,747   2 Depreciation, depletion and amortization   2,306,470   13   1,537,912   6 Interest expense, net of interest income   1,140,702   6   482,023   2 Other, net   92,749   1   40,948   —                Total other expenses  $7,902,926      $6,964,022                         Contract drilling expenses reflect the substantial level and complexity of our drillinginitiatives. In the first quarter of 2007, these expenses were 78% of contract drilling revenues,compared to 82% in the first quarter of 2006. The margins for this sector reflect our transitionfrom turnkey to cost-plus pricing for our new drilling programs, which we implemented in 2006 witha view to reducing our exposure to price volatility for drilling services, equipment and steelcasing requirements. We expect these margins to stabilize from ongoing cost-plus drilling programoperations.
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     Production expenses for the current quarter were driven by our substantial volumetric growth.In addition to lifting costs, production expenses include field operating and maintenance costs,related overhead, third-party transportation fees and lease operating expenses. The increase inour production expenses was significantly offset by cost savings realized from ownership of theNGAS Gathering system acquired in March 2006, eliminating transportation fees for our share ofLeatherwood, Straight Creek and SME production delivered through the system. As a percentage ofoil and gas production revenues, our production expenses increased to 25% in the first quarter of2007 from 23% in the year-earlier period.     Gas transmission and compression expenses in the first quarter of 2007 were 56% of associatedrevenues, compared to 90% in the same quarter last year. The improvement in margins for this partof our business reflects substantial revenue growth from third-party fees generated by the NGASGathering system acquired in March 2006. Our gas transmission and compression expenses do notreflect our acquisition costs for that system or capitalized costs for extensions of our field-widegas gathering systems and additions to dehydration and compression capacity required to bring newwells on line.     Selling, general and administrative (*SG&A*) expenses primarily reflect the timing and extent ofour selling and promotional costs for sponsored drilling programs. On a period-over-period basis,SG&A expenses also reflect higher costs for supporting expanded operations as a whole, includingadditions to our staff and technology infrastructure as well as increased salary and other employeerelated expenses.     Non-cash charges for options, warrants and deferred compensation reflect the fair value methodof accounting for employee stock options, which we adopted in 2004. Under this method, employeestock options are valued at the grant date using the Black-Scholes valuation model, and thecompensation cost is recognized ratably over the vesting period. We also recognized an accrual of$145,802 for deferred compensation cost.     Depreciation, depletion and amortization (*DD&A*) is recognized under the units-of-productionmethod, based on the estimated proved developed reserves of the underlying oil and gas propertiesand on a straight-line basis over the useful life of other property and equipment. The increase inDD&A charges reflects substantial additions to our oil and gas properties, gas gathering systemsand related equipment, including our acquisition of the NGAS Gathering transmission system for $18million in March 2006.     Interest expense for the first quarter of 2007 increased from higher overall bank borrowings,primarily to support our ongoing drilling and gas gathering initiatives, including capitalizedcosts of approximately $2.0 million for extensions and enhancements of our field-wide gas gatheringsystems during the current quarter.     Deferred income tax expense recognized in the first quarter of 2007 represents future taxliability at the operating company level. Although we have no current tax liability due to the utilizationof intangible drilling costs allocated from our active drillingprograms, our consolidated income tax expense is negatively impactedby the non-recognition of tax benefits at the parent company level.     *Net Income and EPS*. We recognized a net loss of $254,264 in the first quarter of2007, compared to net income of $625,737 in the same quarter last year, reflecting the foregoingfactors. Basic earnings (loss) per share (*EPS*) was $(0.01) based on 21,791,107 weighted averagecommon shares outstanding in the current quarter, compared to EPS of $0.03 based on 21,377,525weighted average common shares outstanding in the first quarter of 2006.     The results of operations for the three months ended March 31, 2007 are not necessarilyindicative of results to be expected for the full year.***Liquidity and Capital Resources***     *Liquidity*. Net cash of $5,092,331 was used by operating activities in the first threemonths of 2007. During the quarter, we used $11,324,342 in investing activities, most of whichreflects net additions to our oil and gas properties and gathering systems. These investments werefunded in part with net cash of $4,036,143 from financing activities. As a result of theseactivities, net cash decreased from $14,431,977 at December 31, 2006 to $2,051,447 at March 31,2007.
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     As of March 31, 2007, we had a working capital deficit of $5,921,720. This reflects widefluctuations in our current assets and liabilities from the timing of customers’ deposits andexpenditures under drilling contracts with our sponsored programs. Since these fluctuations arenormalized over relatively short time periods, we generally do not consider working capital to be areliable measure of liquidity. The working capital deficit at the end of the reported period isnot expected to have an adverse effect on our financial condition or results of operations infuture periods.     *Capital Resources*. Our business involves significant capital requirements. The rateof production from oil and gas properties declines as reserves are depleted. Without successfuldevelopment activities, our proved reserves would decline as oil and gas is produced from ourproved developed reserves. Our long term performance and profitability is dependent not only ondeveloping existing oil and gas reserves, but also on our ability to find or acquire additionalreserves on terms that are economically and operationally advantageous. To fund our ongoingreserve development and acquisition activities, we have relied on a combination of cash flows fromoperations, bank borrowings and private placements of our convertible notes and equity securities,as well as participation by outside investors in our sponsored drilling programs.     In December 2005, we completed an institutional private placement of our 6% convertible notesdue December 15, 2010 in the aggregate principal amount of $37 million. We also issued warrants inthe transaction, which expired unexercised in August 2006. At March 31, 2007, all of the notesremained outstanding but were recorded at $35,692,139, reflecting an initial allocation of$2,394,913 for their equity components, which was ratably accreted by $432,893 in 2006 and $88,213in the first quarter of 2007, along with $565,946 reallocated to debt upon expiration of thewarrants last year.     The notes are convertible by their holders into our common stock at a conversion price of$14.34 per share, subject to adjustments for certain dilutive issuances of common stock. If aholder elects to convert a note before the second anniversary of the issuance date, unless theprevailing market price of our common stock exceeds 160% of the conversion price, the holder willbe entitled to a payment equal to the difference between two years’ interest on the converted noteand the interest already paid on the note, payable at our option in cash or in common shares.After that date, if the prevailing market price of our common stock exceeds 160% of the conversionprice, we may redeem any unconverted notes at a redemption price equal to their principal amountplus accrued and unpaid interest. Upon any event of default or any change of control, the notesare redeemable at the option of the holders in cash at a default rate equal to 125% of theirprincipal amount or at a change of control rate equal to the greater of 110% of their principalamount or 110% of the consideration that would be received by the holder for the underlying sharesin the change of control transaction. Any notes that are neither redeemed nor converted prior tomaturity will be repayable in cash or in common shares. Any common shares issued for interestpayments on converted notes or upon redemption at their maturity will generally be valued for thatpurpose at 92.5% of their prevailing market price.     In September 2006, we entered into a credit agreement with KeyBank National Association, asagent and primary lender. The credit agreement provides us with a senior secured revolving creditfacility that replaces our prior credit facility with KeyBank, which had a scheduled maturity dateof July 31, 2007 and a borrowing base of $35 million. The new facility has a five-year maturityfor revolving term loans and letters of credit in an aggregate amount up to $125 million, with acurrent borrowing base of $50 million. The facility is secured by liens on our interests in mostof our Appalachian wells. Outstanding borrowings under the facility bear interest at fluctuatingrates ranging from 1.5% to 2.5% above quoted LIBOR rates, depending on the amount of borrowing baseutilization, plus commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. As ofMarch 31, 2007, our outstanding borrowings under the facility aggregated $35 million.     Our ability to repay our bank debt and convertible notes will be subject to our futureperformance and prospects as well as market and general economic conditions. We will likely bedependent on additional financings to repay our outstanding long term debt at maturity.     Our future revenues, profitability and rate of growth will continue to be substantiallydependent on the demand and market price for natural gas. Future market prices for natural gaswill 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 fordrilling programs. The market price for natural gas is subject to wide fluctuations in response torelatively minor changes in supply and demand, market uncertainty and a variety of other factorsthat are beyond our control.
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     We expect our cash reserves, cash flows from operations and anticipated borrowing baseavailability under our credit facility to provide adequate working capital to meet our short-termcapital expenditure objectives. To fully realize our financial goals for growth in revenues andreserves, we will continue to be dependent on the capital markets or other financing alternativesas well as continued participation by investors in future drilling programs.***Contractual Obligations and Commercial Commitments***     We are parties to leases for office facilities and various types of equipment. We are alsoobligated to make payments at specified times and amounts under instruments governing our long termdebt and other commercial commitments. The following table lists our minimum annual commitments asof March 31, 2007 under these instruments.                       **Operating Leases**  **Other**  **Long Term** **Year** **Equipment**  **Premises**  **Total**  **Commitments**  **Debt** Remainder of 2007  $1,055,726  $189,074  $1,244,800  $240,000(1) $18,000 2008   1,389,402   21,008   1,410,410   100,000(2)  24,000 2009   1,310,502   —   1,310,502   2,045,000(2)  24,000 2010  1,211,834   —   1,211,834   —   35,716,139(3)2011 and thereafter  1,112,654   —   1,112,654   —   35,246,818                                      Total $6,080,118  $210,082  $6,290,200  $2,385,000  $71,028,957                  (1) Reflects obligations under a guaranty secured by a certificate of deposit provided for bankdebt of Galax Energy Concepts, LLC, a limited liability company in which DPI previously held aminority interest. (2) Reflects commitments under a purchase contract for an airplane. (3) Excludes an allocation of $1,307,861 from our 6% convertible notes in the principal amount of$37,000,000 based on equity components of their conversion features.***Critical Accounting Policies and Estimates***     *General*. The preparation of financial statements requires management to makeestimates and judgments that affect the reported amounts of assets, liabilities, revenues andexpenses and related disclosure of contingent assets and liabilities. On an ongoing basis,management evaluates its estimates, including evaluations of any allowance for doubtful accountsand impairment of long-lived assets. Management bases its estimates on historical experience andon various other assumptions it believes to be reasonable under the circumstances. The results ofthese evaluations form a basis for making judgments about the carrying value of assets andliabilities that are not readily apparent from other sources. Although actual results may differfrom these estimates under different assumptions or conditions, management believes that itsestimates are reasonable and that actual results will not vary significantly from the estimatedamounts.     *Allowance for Doubtful Accounts**.*We maintain an allowance for doubtful accounts whendeemed appropriate to reflect losses that could result from failures by customers or other partiesto make payments on our trade receivables. The estimates of this allowance, when maintained, arebased on a number of factors, including historical experience, aging of the trade accountsreceivable, specific information obtained on the financial condition of customers and specificagreements or negotiated amounts with customers.     *Impairment of Long-Lived Assets**.*Our long-lived assets include property and equipmentand goodwill. Long-lived assets with an indefinite life are reviewed at least annually forimpairment, while other long-lived assets are reviewed whenever events or changes in circumstancesindicate that carrying values of these assets are not recoverable.***Forward Looking Statements and Risk Factors***     Some statements made by us in this report are prospective and constitute forward-lookingstatements within the meaning of the Private Litigation Reform Act of 1995. Other than statementsof historical fact, all statements that address future activities, outcomes and other matters weplan, expect, budget, intend or estimate (and other similar expressions) are forward-lookingstatements. The forward-looking statements involve known and unknown
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risks, uncertainties and other factors, many of which are beyond our control. They includesubsurface risks on the recoverability of hydrocarbons, operating risks involving logistical,infrastructure and regulatory issues and commercial risks stemming from the volatility of naturalgas prices. Our annual report on Form 10-K for the year ended December 31, 2006 includes adiscussion of these risk factors. There were no material changes in these risk factors during theinterim period covered by this report.**Item 3. Quantitative and Qualitative Disclosures about Market Risk**     Not applicable.**Item 4. Controls and Procedures**     Our management, with the participation or under the supervision of our Chief Executive Officerand Chief Financial Officer, is responsible for establishing and maintaining disclosure controlsand procedures and internal control over financial reporting for the Company in accordance with therequirements of the Securities Exchange Act of 1934. Our disclosure controls and procedures areintended to provide a framework for making sure that all information required to be disclosed inour current and periodic reports under the Exchange Act is processed and publicly reported by uswithin the prescribed time periods for our filing of those reports. Our internal controls overfinancial reporting are designed to ensure the reliability of our financial reporting and thepreparation of our financial statements for external purposes in accordance with generally acceptedaccounting principles. They include policies and procedures for maintaining reasonably detailedrecords that accurately and fairly reflect all our business transactions and dispositions ofassets, for ensuring that receipts and expenditures are made only in accordance with managementauthorizations and for preventing or timely detecting any unauthorized acquisition, use ordisposition 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 ofthe design and operation of our disclosure controls and procedures and our internal control overfinancial reporting as of March 31, 2007. Based on their evaluation, they have concluded that ourdisclosure controls and procedures are effective to ensure that material information about ourbusiness and operations is recorded, processed, summarized and publicly reported within the timeperiod required under the Exchange Act. They have also concluded that our internal controls overfinancial reporting are effective to ensure the reliability of our financial reporting and thepreparation of our publicly reported financial statements in accordance with generally acceptedaccounting principles. There were no changes in our controls or procedures during the three monthsended March 31, 2007 that have materially affected or are reasonably likely to materially affectour internal control of financial reporting.**PART II. OTHER INFORMATION****Item 6. Exhibits**   ***Exhibit***  ***Number*** ***Description of Exhibit***3.1 Notice of Articles, certified on June 3, 2004 by the Registrar of Corporations under theBritish Columbia Business Corporations Act (incorporated by reference to Exhibit 3.1 toCurrent 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 ofCorporations under the British Columbia Business Corporations Act (incorporated by referenceto 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 theBritish Columbia Business Corporations Act (incorporated by reference to Exhibit 3.3 toCurrent Report on Form 8-K [File No. 0-12185], filed June 29, 2004).   10.1 1997 Stock Option Plan (incorporated by reference to Exhibit 10[a] to Annual Report on Form10-KSB [File No. 0-12185] for the year ended December 31, 2002).
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   ***Exhibit***  ***Number*** ***Description of Exhibit***10.2 2001 Stock Option Plan (incorporated by reference to Exhibit 10[b] to Annual Report on Form10-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 toQuarterly Report on Form 10-QSB [File No. 0-12185] for the quarter ended March 31, 2004).   10.4 Asset Purchase and Sale Agreement dated as of January 17, 2006 among Duke Energy GasServices, LLC, NGAS Gathering, LLC and Daugherty Resources, Inc. (incorporated by referenceto Exhibit 10.1 to current report on Form 8-K [File No. 0-12185] dated January 19, 2006).   10.5 Securities Purchase Agreement dated as of December 13, 2005 among NGAS Resources, Inc. andthe investors named therein (incorporated by reference to Exhibit 10.1 to current report onForm 8-K [File No. 0-12185] dated December 14, 2005).   10.6 Form of 6% convertible notes issued pursuant to the Securities Purchase Agreement dated asof December 13, 2005 among NGAS Resources, Inc. and the investors named therein (incorporatedby reference to Exhibit 10.2 to current report on Form 8-K [File No. 0-12185] dated December14, 2005).   10.7 Credit Agreement dated as of September 8, 2006 among NGAS Resources, Inc., DaughertyPetroleum, Inc. and KeyBank National Association, as agent for the lenders named therein(incorporated by reference to Exhibit 10.1 to current report on Form 8-K [File No. 0-12185]dated September 8, 2006).   10.8 Form of Change of Control Agreement dated as of February 25, 2004 (incorporated byreference to Exhibit 10.9 to quarterly report on Form 10-QSB [File No. 0-12185] for thequarter ended March 31, 2004).   10.9 Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by referenceto Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter endedMarch 31, 2004).   10.10 Form of Long Term Incentive Agreement dated as of February 25, 2004 (incorporated byreference to Exhibit 10.11 to quarterly report on Form 10-QSB [File No. 0-12185] for thequarter ended March 31, 2004).   11.1 Computation of Earnings Per Share (included in Note 9 to the accompanying consolidatedfinancial statements)   21.0 Subsidiaries (incorporated by reference to Exhibit 21.1 to annual report on Form 10-K [FileNo. 0-12185] for the year ended December 31, 2006).   24.1 Power of Attorney.   31.1 Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a), asadopted under Section 302 of the Sarbanes-Oxley Act of 2002.   31.2 Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a), asadopted under Section 302 of the Sarbanes-Oxley Act of 2002.   32.1 Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(b), asadopted under Section 906 of the Sarbanes-Oxley Act of 2002.   32.2 Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(b), asadopted under Section 906 of the Sarbanes-Oxley Act of 2002.
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**SIGNATURES**     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto duly authorized.         **NGAS Resources, Inc.**         Date: May 10, 2007 By: */s/ William S. Daugherty*             William S. Daugherty      Chief Executive Officer      (Duly Authorized Officer)      (Principal Executive Officer)  
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