NGAS Resources Inc - FORM 10-K

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United States Securities and Exchange Commission

Washington, D.C. 20549

FORM 10-K


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

For the Year Ended December 31, 2009



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

Commission File No. 0-12185

NGAS Resources, Inc.

(Exact name of registrant as specified in its charter)


Province of British Columbia		Not Applicable
(State or other jurisdiction of incorporation)		(I.R.S. Employer 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

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: Common Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for any shorter period required). Yes o No o

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in the definitive proxy statement incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark if the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller Reporting Company o
		(Do not check if a smaller reporting company)

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the last sale price of the common stock as of the last business day of the registrant’s most recently completed second fiscal quarter, was $53,450,086.

As of March 5, 2010, there were 33,521,512 shares of the registrant’s common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Certain portions of the proxy statement for the 2010 annual meeting of shareholders are incorporated by reference into Part III of this report.

Table of Contents


			Page
Part I

Items 1 and 2 Business and Properties			1
Item 1A Risk Factors			15
Item 1B Unresolved Staff Comments			19
Item 3 Legal Proceedings			19
Item 4 Submission of Matters to Security Holders			19

Part II

Item 5 Market for Common Equity and Related Matters			19
Item 6 Selected Financial Data			21
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 7A Quantitative Disclosure About Market Risk			30
Item 8 Index to Financial Statements and Supplementary Data			30
Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			30
Item 9A Controls and Procedures			30
Item 9B Other Information			31

Part III

Item 10 Directors, Executive Officers and Corporate Governance			31
Item 11 Executive Compensation			32
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			32
Item 13 Certain Relationships and Related Transactions, and Director Independence			32
Item 14 Principal Accountant Fees and Services			32

Part IV

Item 15 Exhibits, Financial Statement Schedules			32

Additional Information

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

Part I

Items 1 and 2 Business and Properties

General

We are an independent exploration and production company focused on natural gas shale plays in the eastern United States, principally in the southern Appalachian Basin. We have specialized for over 25 years in generating our own geological prospects in this region, where we have established expertise and recognition. We also operate the gas gathering facilities for our core properties, providing deliverability directly from the wellhead to the interstate pipeline network serving major east coast natural gas markets. During the last two years, we have successfully transitioned to horizontal drilling throughout our Appalachian acreage and extended our operations to the Illinois Basin. We believe our extensive operating experience, coupled with our relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to achieve sustained volumetric growth and strong financial returns on a long-term basis.

Recent Developments

We completed several initiatives during 2009 and the beginning of 2010 to strengthened our balance sheet and add liquidity. These transactions have provided us with greater financial flexibility to take advantage of our development opportunities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	•		Convertible Note Exchange. In January 2010, we retired $37 million of our 6% convertible notes due December 15, 2010 in exchange for an aggregate of $28.7 million in new amortizing convertible notes due May 1, 2012 (exchange notes), plus approximately $7.9 million in cash and common shares. The retired notes were issued in December 2005, and their entire carrying amount was reclassified as a current liability at the end of 2009 based on their stated maturity date. The exchange notes have a 6% interest coupon and are convertible into our common stock at $2.18 per share. Beginning in June 2010, the exchange notes require monthly amortization of principal, payable in cash or common shares valued at the lesser of the conversion price or 95% of the prevailing market price of the stock. This creates a flexible repayment structure with the potential for replacing part of the debt with equity at a premium to the stock price at the time of the exchange.

	•		Gathering System Sale and Equity Raise. During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering facilities (Appalachian Gathering System) to Seminole Energy Services, LLC and its subsidiary (Seminole Energy) for $50 million, of which $14.5 million is payable in monthly installments through December 2011 with interest at 8% per annum. We also entered into gas marketing and gas sales arrangements with Seminole Energy that provide us with long-term operating rights and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas through the system, ensuring continued market access for our Appalachian production. Cash proceeds of $35.5 million from our monetization of the Appalachian Gathering System and approximately $6.1 million from a contemporaneous equity raise were applied to debt reduction under our revolving credit facility.

Business Strategy

Over 76% of our operated properties in the Appalachian and Illinois Basins are undeveloped. Our business is structured for efficient development of these resources, which has been transformed by advances in air-driven horizontal drilling and staged completion technology optimized for our operating areas. We began this transition early in 2008 and had 36 horizontals on line by the end of 2009. Our success with these initiatives contributed to growth in our production volumes to 4 Bcfe in 2009, up 6% over 2008. With our gas gathering infrastructure in place, our extensive inventory of horizontal locations positions us for sustainable growth under a low-cost structure with several key components.

•

Organic Growth with Reduced Capital Spending. While we are committed to a long-term strategy of developing our reserves through the drillbit, we have addressed the challenging conditions in our industry by reducing our capital spending and returning to our successful partnership structure for sharing development costs on operated properties. We raised $19.25 million for our 2009 drilling partnership. This enabled us to meet our near-term drilling commitments and objectives with a reduced budget of $12 million in 2009. We plan to retain this strategy for participation by our 2010 program in up to 57 horizontal wells on our core properties, while continuing to maintain capital expenditures in line with our cash flow from operations.

	•		Horizontal Drilling Advances. Advances in horizontal shale drilling technology have enhanced the value proposition of our operated properties by substantially increasing recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or difficult terrain. We began horizontal drilling early in 2008, initially focusing on our key Leatherwood field, and continued the transition throughout our operated properties during 2009. These wells have a single lateral leg of at least 3,500 feet, with initial 30-day production averaging 310 Mcf per day (Mcf/d). The laterals traverse one or more sections of the Devonian shale formation, which blankets our Appalachian properties at an average depth of 4,500 feet, or the New Albany shale at depths ranging from 2,600 to 2,800 feet in the Illinois Bain. We have further improved the performance metrics of our horizontals by extending the laterals and stacking multiple wells on a single drilling pad.

	•		Infrastructure Position. We operate and co-own the gas gathering infrastructure for our Illinois Basin acreage, and we continue to operate the Appalachian Gathering System following its sale in the third quarter of 2009. As part of the sale, we retained firm capacity rights for daily delivery of 30,000 Mcf of controlled gas through the Appalachian Gathering System for a fifteen-year term with renewal options. This ensures continued deliverability from our connected fields, representing over 90% of our Appalachian production, to major east coast natural gas markets through an interconnect with Spectra Energy Partners’ East Tennessee Interstate pipeline network. Our operating and capacity rights preserve our competitive advantages from control of regional gas flow, enhancing our opportunities to acquire undeveloped acreage near our core producing fields upon completion of coal mining activities. We also retained our 50% interest in a liquids extraction plant for production serviced by the Appalachian Gathering System, located at its delivery point in Rogersville, Tennessee. This is within 5.5 miles of the site for a 880-megawatt gas-fired power plant to be constructed by the Tennessee Valley Authority. In addition to increasing regional demand, the TVA project may provide us with opportunities for long-term gas sales arrangements.

	•		Expansion of Leatherwood Position. In October 2009, we expanded our position in our key Leatherwood field with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with participation rights for up to 50% of the working interest in wells drilled on the covered acreage and requires us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment. Combined with a farmout we acquired earlier in the year from Chesapeake Appalachia, LLC for a significant tract next to the Amvest portion of our Stone Mountain field, this brings our holdings in the Appalachian Basin to a total of 333,392 gross acres.

Drilling Operations

Geographic Focus. As of December 31, 2009, we had interests in a total of 1,387 wells, concentrated on Appalachian properties that we operate and control through our infrastructure position. We believe our long and successful operating history have situated us as a leading producer in this region. Although mineral development in Appalachia has historically been dominated by coal mining interests, it is also one of the oldest and most prolific natural gas producing areas in the United States. The primary pay zone throughout our Appalachian acreage is the Devonian shale formation, providing predictable locations for repeatable drilling. It is considered an unconventional target due to its low permeability, requiring effective treatment to enhance gas flows. Estimated ultimately recoverable volumes (EURs) of natural gas for our vertical Devonian shale wells reflect modest initial volumes offset by low annual decline rates. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

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

Drilling Results. The following table shows the number of our gross and net development and exploratory wells drilled during the last three years. Drilling results for 2009 include 10 gross (2.30 net) horizontal wells drilled during the fourth quarter of the year. The 2009 results also include 9 gross (2.30 net) wells that were drilled by year-end but were awaiting installation of gathering lines. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may earn in managed drilling partnerships.


	Development Wells						Exploratory Wells
Year Ended	Productive				Dry		Productive				Dry
December 31,	Gross		Net		Gross		Gross		Net		Gross
2009
Vertical		10		1.6972		—		—		—		—
Horizontal		24		5.0588		—		—		—		—

Subtotal⁽¹⁾		34		6.7560		—		—		—		—
2008
Vertical		137		58.8522		—		9		8.8125		—
Horizontal		47		15.7254		—		—		—		—

Subtotal⁽¹⁾		184		74.5776		—		9		8.8125		—
2007
Vertical		211		76.1508		—		6		6.0000		—

Total		429		157.4844		—		15		14.8125		—


(1)		Includes 9 gross (1.9560 net) non-operated wells in 2009 and 25 gross (2.6003 net) non-operated wells in 2008.

Most of the exploratory wells shown in the table were drilled as part of the second phase of a project commenced in 2006 to test the New Albany shale in the southcentral portion of the Illinois Basin in our Haley’s Mill acreage. Based on encouraging results, we have expanded our position to over 52,000 acres in this play and have drilled a total of 12 exploratory and 32 development wells through the end of 2009. The remaining exploratory wells were drilled during 2008 in our Licking River project, where we have development rights and a 50% interest in currently constrained gathering infrastructure on acreage spanning six counties in eastern Kentucky. We have suspended this project pending improvements in market conditions. See “Oil and Gas Properties.”

Participation Rights. The interests in some of our operated properties in the Appalachian Basin, primarily our Leatherwood field, are subject to participation rights retained by the mineral interest owners, generally up to 50% of the working interest in wells drilled on the covered acreage. During 2009, we had third-party participation for average working interests of 35% in our horizontal wells in Leatherwood. We anticipate third-party participation at similar levels in most our Leatherwood development during 2010.

Drilling Operations. We do not operate any of the rigs or equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline our operations and conserve capital for new wells, while retaining control over all geological, drilling, engineering and operating decisions. The geological characteristics of our Appalachian properties enables us to drill most of our horizontal wells within 15 days from spudding. Because of scheduling complexities for handling large volumes of nitrogen in the treatment stage, we have an overall drilling and completion cycle of at least 28 days for most of our horizontal wells. With the core gas gathering infrastructure in place for all our operated properties, we are usually able to bring our horizontal wells on line within one week after completion.

Producing Activities

Regional Advantages. Our proved reserves, both developed and undeveloped, are concentrated in the southern Appalachian Basin. The proximity of this region to major east coast gas markets generates realization premiums above Henry Hub spot prices. Our Appalachian gas production also has the advantage of a high energy content, ranging from 1.1 to 1.3 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput above 1 Dth per Mcf, this resulted in additional energy related premiums over normal pipeline quality gas.

Liquids Extraction. In response to a tariff issued by the Federal Energy Regulatory Commission (FERC) limiting the upward range of energy content to 1.1 Dth per Mcf, we constructed a processing plant during 2007 with a joint venture partner in Rogersville, Tennessee to extract natural gas liquids (NGL) from production delivered through the Appalachian Gathering System. The plant was brought on line in January 2008, ensuring our compliance with the FERC tariff. Gas processing fees for liquids extraction are shared with our joint venture partner and are volume dependent. Our share of processing fees, coupled with savings from rail shipping arrangements implemented for our NGL sales during 2009, have offset part of the reduction in energy-related yields from our Appalachian gas sales.

Production Profile. Our Appalachian wells produce high quality natural gas at low pressures with little or no water production. Vertical wells in this region share a predictable profile characterized by moderate annual production declines throughout an economic life of 25 years or more without significant remedial work. Although the production history for horizontal wells in our operating areas is limited, reported production declines are consistent with profiles for vertical shale wells in the region. As of December 31, 2009, the reserve life index of our estimated proved reserves, representing the ratio of reserves to annual production, was 19.7 years overall and approximately 13.5 years for our proved developed producing reserves, based on annualized fourth quarter production.

Production Volumes, Prices and Costs. The following table shows our net production volumes for natural gas, crude oil and NGL during the last three years and the fourth quarters of 2009 and 2008.


	Three Months Ended
	December 31,				Year Ended December 31,
Production volumes:	2009		2008		2009		2008		2007
Natural gas (Mcf)		799,923		818,667		3,321,146		3,087,596		2,950,690
Crude oil (Bbl)		11,424		12,573		48,737		57,291		57,738
Natural gas liquids (gallons)		962,845		964,675		4,858,044		3,895,649		154,797

Equivalents (Mcfe)		940,681		966,456		3,977,920		3,745,124		3,310,665

Production Prices and Costs. Our average sales prices for natural gas, crude oil and NGL during the last three years are listed below, along with our average lifting costs and transmission, compression and processing costs in each of the reported periods.


	Year Ended December 31,
Sales Prices and Production Costs:	2009		2008		2007
Average sales prices:
Natural gas (per Mcf)	$	6.17	$	8.89	$	8.19
Crude oil (per Bbl)		52.63		95.07		64.97
Natural gas liquids (per gallon)		0.73		1.41		1.41
Lifting costs (per Mcfe)		0.74		1.42		1.46
Transmission, compression and processing costs (per Mcfe)		2.28		1.85		1.01

Future Gas Sales Contracts. We use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time to address commodity price volatility. Our physical delivery contracts are not treated as financial hedges and are not subject to mark-to-market accounting. The financial impact of these contracts is included in our oil and gas revenues at the time of settlement. As of the date of this report, we have contracts in place for the following portions of our anticipated quarterly natural gas production through the middle of 2011.


Fixed price contracts for	2010								2011
natural gas production:	Q1		Q2		Q3		Q4		Q1		Q2
Percentage of gas contracted		58%		52%		57%		54%		53%		22%
Average price per Mcf	$	7.54	$	6.47	$	6.54	$	6.60	$	6.63	$	6.66

Proved Oil and Gas Reserves

General. The estimates of our proved oil and gas reserves at the end of each period covered in this report were prepared by Wright & Company, Inc., independent petroleum engineers (Wright & Co.). Wright & Co. was selected for its geographic expertise and historical experience in engineering properties in our operating areas. The technical personnel of Wright & Co. responsible for preparing the estimates meet the qualification, independence, objectivity and confidentiality standards of the Society of Petroleum Engineers for estimating and auditing reserves. The summary reserve report of Wright & Co. covering its estimates of our proved oil and gas reserves as of December 31, 2009 is included as an exhibit to this report. We have not filed any estimates of our proved reserves with any federal agency during the past year other than estimates included in periodic reports filed with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934 (Exchange Act).

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished for their reserve estimates. This includes regular updates on our ownership interests in oil and gas properties, production information, well test data, commodity prices and operating and development costs. Our technical team meets throughout the year with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal reserve review committee, our senior management periodically reviews our reserve estimation and reporting process and our internal reserve and resource estimates.

Revised Reserve Rules. Our reserve estimates as of December 31, 2009 were prepared in accordance with Subpart 1200 of Regulation S-K and Item 4-10 of Regulation S-X under the Exchange Act and related Compliance and Disclosure Interpretations on the Oil and Gas Rules issued by the SEC in October 2009 (current reserve rules). The current reserve rules went into effect at the end of 2009. They are intended to modernize reserve estimation and reporting standards to reflect current industry practices and technologies. Estimates of our proved oil and gas reserves as of December 31, 2008 and 2007 were prepared in accordance with the SEC’s reserve estimation and disclosure rules in effect prior to the current reserve rules (prior reserve rules).

Commodity Pricing. Economic producibility for estimates under the current reserve rules is determined using the unweighted average of the first-of-the-month spot prices for each commodity category during the twelve months preceding the date of the estimate, except for future production to be sold at contractually determined prices. Under the prior reserve rules, economic producibility was based on commodity prices as of the date of the estimate. In all cases, costs are determined as of the date the estimate, and both prices and costs are held constant over the estimated life of the reserves. Commodity prices used in the estimates of our proved reserves are shown in the following table. All prices are adjusted for energy content and basis differentials.


	Average		At December 31,
Commodity prices for reserve estimates:	2009		2008		2007
Natural gas (Mcf)	$	4.25	$	5.51	$	7.39
Crude oil (Bbl)		61.18		40.00		87.98
Natural gas liquids (Bbl)		14.58		6.46		N/A

Reserve Quantities. The following table summarizes the estimated quantities of our proved developed reserves and proved undeveloped reserves as of December 31, 2009, using the twelve-month average pricing model under the current reserve rules. Historical reserve estimates shown in the table as of December 31, 2008 and 2007 were based on commodity prices as of the date of the estimates in accordance with the prior reserve rules. All reserves are located within the continental United States.


	As of December 31,
Proved Reserves:	2009		2008		2007
Natural gas (Mmcf)
Proved developed		38,177		44,817		45,012
Proved undeveloped		19,984		16,314		57,153

Total natural gas		58,161		61,131		102,165
Natural gas liquids (Mbbl)
Proved developed		1,391		1,500		—
Proved undeveloped		1,262		697		—

Total natural gas liquids		2,653		2,197		—

Crude oil (Mbbl)
Proved developed		709		602		500
Proved undeveloped		4		—		—

Total crude oil		713		602		500

Total natural gas equivalents (Mmcfe)⁽¹⁾	78,357			77,922		105,162


(1)		Crude oil and NGL are converted to equivalent natural gas volumes at a 6:1 ratio.

Changes in Proved Reserves. As of December 31, 2009, our proved undeveloped (PUD) reserves of 27.6 Bcfe represented 35% of our total proved reserves, compared to 20.5 Bcfe of PUD reserves as of December 31, 2008. None of our 2009 year-end PUDs have been included in our reported reserves for more than five years. Under the current reserve rules, proved undeveloped reserves are estimated volumes expected with reasonable certainty to be recovered from new wells on undrilled acreage within a reasonable time horizon, generally limited to five years from the date of the estimate, based on reliable technology that has demonstrated by field testing to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This modification of the prior reserve rules enabled us to add 15.9 Bcfe in new horizontal PUD locations supported by reliable technology. We also converted 0.03 Bcfe in prior year-end PUDs and 19.4 Bcfe in unproved reserves into proved developed reserves during 2009. The additions were partially offset by negative revisions of 6.7 Bcfe to our proved developed reserves from lower 2009 average prices.

Reserve Values. The following table summarizes the estimated future net cash flows from the production and sale of our proved reserves as of December 31, 2009, 2008 and 2007 and the standardized measure for reporting the present value of those cash flows, discounted at 10% per year in accordance with SEC regulations to reflect the timing of net cash flows. The future net cash flows were computed after giving effect to estimated future development and production costs, based on year-end costs and assuming the continuation of economic conditions at the time of the estimates. The standardized measure of future net cash flows gives effect to future income taxes on discounted future cash flows based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits.

(In thousands)


	As of December 31,
Estimated future net cash flows from proved reserves:	2009			2008			2007
Undiscounted future net cash flows⁽¹⁾	$	88,207		$	161,455		$	317,356
10% annual discount for estimated timing of cash flows		(59,441	)		(93,892	)		(214,574	)

Standardized measure of discounted future net cash flows	$	28,766		$	67,563		$	102,782


(1)		Reflects the twelve-month average of the first-day-of-the-month reference prices for 2009 and year-end prices for prior years.

Estimates of our proved undeveloped reserves as of December 31, 2009 include locations that would generate positive future net revenue based on the constant prices and costs determined under the current reserve rules but would have negative present value when discounted at 10% per year under the standardized measure. These locations have been included based on our business plan for their development, along with all other 2009 year-end PUD locations, within the next five years. Our reported reserves do not include any probable or possible reserves that might be established for these properties under the current reserve rules.

Reserve Pricing Sensitivity. Under the twelve-month average pricing model required by the current reserve rules, the natural gas price used in our reserve estimates at December 31, 2009 was 27% less than the year-end spot price and 39% less than the 10-year average NYMEX strip price, before basis differentials. The following table shows the impact of these pricing assumptions on our reported proved reserves at December 31, 2009, both developed and undeveloped, and the discounted future net cash flows from our estimated proved reserves, before giving effect to any future income taxes on the discounted future cash flows (PV-10).


	Natural		Crude Oil		Proved				Total
	Gas		and NGL		Developed		PUD		Proved
2009 Pricing Assumptions:	Price		Price		Reserves		Reserves		Reserves		PV-10
	($/Mcf)		($/Bbl)		(Bcfe)		(Bcfe)		(Bcfe)		(000)
Twelve-month average	$	4.25	$	61.18		50.8		27.6		78.4	$	36,891
Year-end spot		5.79		77.85		56.7		78.0		134.7		57,887
10-year average NYMEX strip		6.94		92.24		59.0		83.4		142.4		107,553

Oil and Gas Properties

Oil and Gas Interests. The following table shows our ownership interests under oil and gas leases and farmout agreements, by state, as of December 31, 2009. Our leases and farmouts are for varying primary terms and are generally subject to specified royalty or overriding royalty interests, development obligations and other commitments and restrictions.


	Developed				Undeveloped
Property Location:	Gross Acres		Net Acres		Gross Acres		Net Acres
Kentucky		87,854		33,995		240,401		204,341
Virginia		2,749		2,362		14,358		12,204
Tennessee		1,691		397		38,497		32,722
Arkansas		8,913		2,179		2,960		2,235
West Virginia		11,120		1,376		—		—
Oklahoma		2,127		426		—		—


Total		114,454		40,735		296,216		251,502

Productive Wells. The following table shows, by state, our gross and net productive oil and gas wells as of December 31, 2009. The table does not include wells that were in progress or were drilled by year end but were awaiting installation of gathering lines.


	Gas Wells				Oil Wells				Total
Well Location:	Gross		Net		Gross		Net		Gross		Net
Kentucky		948		474.84		15		11.74		963		486.58
West Virginia		240		37.53		—		—		240		37.53
Arkansas		54		14.83		—		—		54		14.83
Virginia		40		31.63		1		1.00		41		32.63
Tennessee		19		6.69		—		—		19		6.69
Oklahoma		13		3.74		—		—		13		3.74
Other		—		—		12		0.34		12		0.34


Total		1,314		569.26		28		13.08		1,342		582.34

Reserves from Significant Fields. The following table shows our estimated proved reserves, both developed and undeveloped, on a field-wide basis as of December 31, 2009.


	Proved Reserves at December 31, 2009
	Developed								Undeveloped
Field:	Gas		NGL		Oil		Total		%			Gas		NGL		Total
	(Mmcf)		(MBbls)		(MBbls)		(Mmcfe)					(Mmcf)		(MBbls)		(Mmcfe)
Leatherwood		11,718		711		73		16,418		52	%		10,466		794		15,231
Arkoma		9,659		—		—		9,659		85			1,671		—		1,671
SME—Amvest		3,181		195		316		6,241		94			279		19		394
SME—Martin’s Fork		3,463		214		54		5,071		58			2,640		181		3,726
Straight Creek		2,564		157		92		4,063		53			2,505		184		3,608
Kay Jay		1,949		—		3		1,969		67			954		—		954
Fonde		1,423		79		8		1,944		62			811		61		1,178
HRE		2,399		—		3		2,419		100			—		—		—
Haley’s Mill		433		—		—		433		100			—		—		—
Other fields		1,388		35		160		2,559		76			658		27		819


Total		38,177		1,391		709		50,776		65	%		19,984		1,266		27,581

Description of Significant Fields. Our producing properties and undeveloped acreage positions are concentrated in the southern Appalachian Basin, as well as our recently developed New Albany shale play within the Illinois Basin in western Kentucky. We also have interests in a non-operated coalbed methane project in the Arkoma Basin and non-operated projects in West Virginia and Virginia. Additional information about our significant fields is summarized below. Unless otherwise indicated, well counts, production volumes and reserve data are provided as of December 31, 2009.

Leatherwood. The Leatherwood field covers approximately 69,000 acres, extending 41 miles through Letcher, Perry, Leslie and Harlan Counties in eastern Kentucky. We acquired most of our interests in this field at the end of 2002 under a farmout agreement with the mineral interest owners, Equitable Production Company and KRCC Oil & Gas, LLC. Since completion of a successful 25-well exploratory project during 2003, we have drilled 278 development wells under the Leatherwood farmout, including 30 horizontal wells during the last two years. Vertical wells in Leatherwood produce from the Maxon sand, Big Lime and Devonian shale formations, and our horizontals have targeted the Lower Huron and Cleveland sections of the Devonian shale. Our transition to horizontal drilling in Leatherwood contributed to additions of approximately 5.8 Bcfe to our proved developed reserves in 2009. At year end, we had 281 wells on line in Leatherwood, with total daily gross and net production of 8,360 Mcfe and 3,174 Mcfe, respectively. We operate all the wells in Leatherwood, which produce to sales through the Appalachian Gathering System. Estimated reserves from our interests in Leatherwood are 52% proved developed.

At the time we acquired our farmout for Leatherwood, there was no gas gathering infrastructure in the region, which has a history as an active coal producing district. We completed the construction of a 23-mile gathering system for our Leatherwood wells and a 16-mile line that connects them to the midstream portion of the Appalachian Gathering System late in 2005, enabling us to bring a backlog of unconnected wells on line. Prior to the sale of the system in the third quarter of 2009, we added several pipeline and compression upgrades to keep pace with our expanding production base in Leatherwood, including substantially higher gas flows from our horizontal wells. We have an ongoing annual drilling commitment for 25 wells under our farmout for Leatherwood. The farmout provides the mineral interest owners with participation rights for up to 50% of the working interest in new wells. These rights were exercised for average total working interests of 35% in our Leatherwood wells during 2009. We anticipate similar participation levels by the mineral interest owners in most of the horizontal wells planned under our Leatherwood farmout during 2010.

In October 2009, we expanded our position in Leatherwood with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with participation rights for up to 50% of the working interest in wells drilled on the covered acreage and requires us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment.

Arkoma. The Arkoma field is a coalbed methane (CBM) project covering approximately 14,000 acres in the Arkoma Basin within Sebastian County, Arkansas and Leflore County, Oklahoma. Initial development of the project began in 2001 through a joint venture between CDX Gas, LLC, with a 75% stake, and Dart Energy Corporation, with a 25% interest. In November 2005, we acquired Dart Energy’s position, including its 25% interest in the field’s gathering system and a total of 48 CBM wells drilled by the joint venture. We also entered into a farmout with CDX for 90% of its majority (75%) interest in specified drilling locations on its acreage. Under the farmout, we assumed all of future developments costs for the CDX position and granted them a 25% carried working interest, increasing to 50% after payout of the covered wells. Combined with our interests from the Dart Energy acquisition, this gave us an overall position of approximately 73% in future development of the field. We participated in 15 horizontal wells under the Arkoma farmout before electing to terminate it in 2007. During the balance of 2007, we participated in four CBM wells through our interests from the Dart Energy acquisition. No wells were drilled in the last two years. We had interests in a total of 67 wells producing to sales in this field at the end of 2009, with daily gross and net CBM production of 9,272 Mcf and 2,075 Mcf, respectively. Estimated reserves from our interests in the Arkoma field are 85% proved developed.

Amvest and Martin’s Fork. We acquired our interests in the Amvest and Martin’s Fork fields, including existing wells and infrastructure, during the fourth quarter of 2004. Also known as the Stone Mountain or SME fields, they span approximately 86,500 acres in Harlan County, Kentucky and Lee County, Virginia. Our interests are subject to annual drilling commitments for two wells in Martin’s Fork and four wells in Amvest. Since acquiring these interests, we have drilled a total of 59 wells on this acreage, including two horizontal wells during 2009. Vertical wells produce from the Big Lime, Devonian shale and Clinton formations in Martin’s Fork at depths between 3,200 and 6,500 feet and from the Big Lime, Weir sand and Devonian shale formations in Amvest at depths between 3,800 and 5,500 feet. Oil is also produced from the Big Lime in Martin’s Fork and from the Big Lime and Weir sand in Amvest. Our horizontals have targeted the Lower Huron section of the Devonian shale in Martin’s Fork, which ranges in thickness up to 200 feet, and the Upper Huron and Cleveland sections of the Devonian shale in Amvest, with a combined thickness up to 130 feet. At year end, we had a total of 78 wells in Martin’s Fork and 75 wells in Amvest, with daily gross and net production aggregating 3,209 Mcfe and 2,219 Mcfe, respectively. We operate all the wells and produce all natural gas in these fields through the Appalachian Gathering System. Estimated reserves are 94% proved developed in Amvest and 58% proved developed in Martin’s Fork.

In May 2009, we acquired a farmout from Chesapeake Appalachia, LLC for a tract of 56,000 gross (42,000 net) undeveloped acres contiguous to the Amvest portion of our Stone Mountain field in Letcher and Harlan Counties, Kentucky. Prior development includes approximately 100 producing wells and infrastructure connecting to the Appalachian Gathering System. Penn Virginia Operating, LLC, the royalty interest owner, and Chesapeake each have participation rights for up to 25% of the working interests in our future wells on the acreage, and we have a minimum annual drilling commitment of four wells under the farmout. We also had an initial commitment to drill six vertical Devonian shale wells by the beginning of June 2009. To meet the commitment, we entered into arrangements with a joint venture partner that provides us with a 15% carried working interest in these wells, which we completed on schedule with encouraging results. We granted our joint venture partner participation rights for up to 50% of our available working interest in subsequent wells drilled on the acquired acreage.

Straight Creek. The Straight Creek field is located in Bell and Harlan Counties, Kentucky. We have interests in approximately 28,000 acres in this field. In addition to several wells we acquired in the field during 2004, we have drilled 180 vertical wells in Straight Creek, which produce from the Maxon sand, the Big Lime, Devonian shale, Corniferous and Big Six sand formations at depths between 3,200 and 4,700 feet. During 2009, we drilled four horizontal wells in Straight Creek through the Upper Huron and Cleveland sections of the Devonian shale, which have a combined thickness of approximately 80 feet in this field at an average depth of 4,000 feet. We operate all the wells in Straight Creek, which produce to sales through the Appalachian Gathering System. As of year end, we had a total of 192 wells on line in this field, with daily gross and net production of 2,451 Mcfe and 800 Mcfe, respectively. Estimated reserves from our interests in Straight Creek are 53% proved developed.

Kay Jay. The Kay Jay field spans portions of Knox and Bell Counties, Kentucky. Our initial interests in the field were acquired in 1996 under a farmout for approximately 11,500 acres, with an ongoing annual drilling commitment for a total of four wells. We subsequently assembled an additional 15,500 acres under a leasing program for this field. Wells in Kay Jay produce natural gas from the Maxon sand, Big Lime, Borden, Devonian shale and Clinton formations at depths ranging from 2,200 to 3,300 feet. Oil is also produced from the Maxon sand. We operate all of our Kay Jay wells and retained our ownership of the field-wide gathering facilities, which are currently connected to third-party pipeline systems. In connection with our sale of the Appalachian Gathering System during the third quarter of 2009, we granted certain first refusal rights to Seminole Energy for any sale of our interests in Kay Jay or in its field-wide gathering facilities. We had a total of 148 wells in Kay Jay producing to sales at year end, with daily gross and net production of 2,087 Mcfe and 673 Mcfe, respectively. Estimated reserves from our interests in Kay Jay are 67% proved developed.

Fonde. The Fonde field spans portions of Bell County, Kentucky and Claiborne County, Tennessee. We acquired our initial position for 3,900 acres in this field during 1998 and subsequently assembled an additional 39,000 acres under a series of farmouts and leases. We have drilled a total of 65 vertical wells in Fonde, which produce natural gas from the Big Lime and Devonian shale formations at depths up to 4,500 feet, along with crude oil from the Big Lime. During the first quarter of 2008, we completed construction of a 14-mile, six-inch steel line to provide deliverability for our Fonde production into the Appalachian Gathering System. This enabled us to connect a backlog of wells previously drilled in Fonde and open the balance of our acreage for development. During 2009, we drilled one horizontal well in Fonde through the Cleveland section of the Devonian shale, which ranges in thickness up to 100 feet in the field at an average depth of 4,500 feet. At year end, we had 37 wells in Fonde producing to sales, with daily gross and net production of 950 Mcfe and 409 Mcfe, respectively. We operate all the wells and produce all natural gas in the field through the Appalachian Gathering System. Estimated reserves from our interests in Fonde are 62% proved developed.

HRE. We have participated in development of the HRE fields with a joint venture partner, Hard Rock Exploration, Inc. (Hard Rock), under its leases and farmouts covering approximately 114,000 acres in Boone, Cabell, Jackson, Randolph and Roane Counties, West Virginia and Buchanan County, Virginia. Since the beginning of 2006, we have participated in a total of 246 wells drilled by Hard Rock on its acreage, including 39 horizontals. Most of the HRE wells target the Lower Huron section of the Devonian shale formation at total depths up to 5,000 feet. Some of the wells also produce from the Berea sand formation at depths ranging from 2,600 to 2,700 feet. Hard Rock operates all of the wells in the HRE fields and controls all of the field-wide gathering facilities for their production. We have participated in developing the HRE fields primarily through our interests in sponsored drilling partnerships. As of year end, we had interests in a total of 244 wells producing to sales in these fields, with daily gross and net production of 6,733 Mcfe and 895 Mcfe, respectively. Estimated reserves from our interests in the HRE fields are 100% proved developed.

Haley’s Mill. Our New Albany shale play, known as Haley’s Mill, is situated in the southcentral portion of the Illinois Basin, spanning portions of Christian and Hopkins Counties in western Kentucky. We assembled our initial lease position during 2006 and expanded our position during the last two years to approximately 52,000 acres. The New Albany shale formation blankets this acreage at depths ranging from 2,600 to 2,800 feet and has similar geologic characteristics to the Devonian shale in the Appalachian Basin. Although we completed the infrastructure build-out for the project during 2007, including a processing facility to reduce nitrogen levels in the gas to pipeline quality standards, our deliverability was substantially reduced by unanticipated constraints in third-party pipeline capacity. In September 2008, we completed an extension to an alternative pipeline network and began producing the project to sales. We had a total of 34 wells on line in Haley’s Mill at the end of 2009, including three horizontals. Estimated reserves for the project are 100% proved developed, with daily gross and net year-end production of 527 Mcf and 421 Mcf, respectively. This reflects high shrinkage and fuel burn rates from membrane unit processing used at out nitrogen reduction facility. During the first quarter of 2010, we converted the facility to pressure swing absorption technology. This has reduced our total shrinkage rates from over 40% to less than 10% and has substantially improved the economics for our New Albany shale play.

Drilling Partnerships

Structure. Our drilling partnerships are structured to optimize tax advantages for private investors and share development costs, risks and returns proportionately, except for functional allocations of intangible drilling costs (IDC) to investors and reversionary interests that we earn after specified distribution thresholds are reached. Under our drilling partnership structure, proceeds from the private placement of interests in each investment partnership, together with our capital contribution, are contributed to a separate joint venture or “program” that we form with that partnership to conduct operations. The portion of the profit on drilling contracts from our ownership interest in each program is eliminated on consolidation in our financial statements.

Benefits. Our established track record and sales network for sponsored drilling partnerships has enabled us to attract outside capital from accredited investors for participation in selected development initiatives. This addresses part of 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.

	•		Expanding our drilling budget with outside capital from partnership investors enables us to build our asset base through increased drilling commitments, while also leveraging our buying power for drilling services and materials, resulting in lower overall development costs.

	•		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.

	•		Our drilling partnership business model increases the number of gross wells we could drill on our own, diversifying our drilling risks and opportunities.

Investment Capital. During the last three years, we raised over $83.5 million from accredited investors for participation in many of our drilling initiatives through private placements of interests in sponsored drilling partnerships. Proceeds from these private placements are used to fund the investors’ share of drilling and completion costs under our drilling and operating agreements. These payments are recorded as customer drilling deposits at the time of receipt. We recognize revenues from these operations on the completed contract method as the wells are drilled, rather than when funds are received. Our development activities through sponsored drilling partnerships during the last three years are summarized in the following table.


			Drilling Program Capital
	Total Wells		Partnership		Our		Total
Drilling Partnerships:	Contracted		Contributions		Contributions		Capital
2009		22	$	19,251,125	$	4,812,781	$	24,063,906
2008		89		34,460,340		10,919,628		45,379,968
2007		140		29,829,219		13,939,508		43,768,727


Total		251	$	83,540,684	$	29,671,917	$	113,212,601

Drilling Program Interests. In addition to managing operations, we contribute capital to the joint venture program formed with each of our sponsored drilling partnerships in proportion to our initial ownership interest, and we share program distributions in the same ratio until program payout, generally established at 110% of the partners’ investment. After payout, we are entitled to specified increases in our distributive share, up to 15% of the total program interests. In 2008, we sponsored a program for 89 natural gas development wells, including 20 horizontal wells, on acreage controlled by a joint venture partner in West Virginia and Virginia. We have a 25% stake in the 2008 program, increasing to 40% after program payout. We retained all of our available working interest in wells drilled on our operated properties in 2008 to accelerate organic growth. In response to market conditions since that time, we reduced our capital expenditure budget and opened up our operated properties for joint development with sponsored partnerships, as well as industry partners. We have a 20% interest before payout and a 35% interest after payout in our 2009 program, which is participating in 22 horizontal wells. We plan to continue this business model during 2010.

Liquidity Features. Many of the drilling partnerships we sponsored over the last nine years have a liquidity feature enabling participants to tender requests for us to purchase their interests after specified periods under various conditions. For recent programs, this feature gives us the option to acquire tendered interests for cash based on a multiple of partnership distributions for the preceding year. For older programs, we have the right to purchase any tendered interests in exchange for our common shares based on the most recent year-end reserve valuations for the particular partnership. The valuations under either of these liquidity features may not necessarily correspond to the fair value of the tendered interests. Both of these liquidity features are subject to various conditions and limitations. Less than 1% of the outside investors in our drilling partnerships have used these liquidity features, which do not affect the way we account for our interests in these programs.

Gas Gathering Operations

Gas Gathering. Historically, we constructed and operated the gas gathering and compression facilities for all of our operated properties in the Appalachian and Illinois Basins. Our sale of the Appalachian Gathering System in the third quarter of 2009 did not include the infrastructure for our Kay Jay field in eastern Kentucky or our Haley’s Mill project in western Kentucky, and we continue to receive gas gathering and compression fees for third-party production serviced by these facilities. Although our sale of the Appalachian Gathering System eliminated our cost savings from ownership of the system, our long-term operating and capacity rights preserve our competitive advantages from control of regional gas flows. We estimate that up to 200,000 undeveloped acres surrounding our Appalachian properties serviced by this infrastructure will open up for drilling when active coal mining operations wind down. We believe our retained infrastructure position, coupled with our established track record in this region, positions us to acquire these development rights when they become available.

Gas Processing. We own 50% interests in a liquids extraction plant for natural gas delivered through the Appalachian Gathering System, located in Rogersville, Tennessee, and a nitrogen rejection facility for our Illinois Basin production. The Rogersville plant extracts NGL at levels enabling us to flow dry pipeline quality natural gas into the interstate network. Brought on line in January 2008, the plant is currently configured for throughput at rates up to 25,000 Mcf per day, which can be increased to accommodate production growth and relief of constrained regional supplies. The nitrogen rejection facility is part of the infrastructure build-out for our New Albany shale project in western Kentucky, which we brought on line in September 2008. Both the Rogersville processing plant and the western Kentucky treatment facility are co-owned and operated by Seminole Energy. Gas processing fees are volume dependent and are shared with Seminole Energy.

Customers

Natural Gas Sales. We sell our natural gas production primarily through unaffiliated gas marketing intermediaries, including Seminole Energy and Stand Energy Corporation, which each account for more than 10% of our total gas sales. In addition to providing gas marketing services, these firms generally coordinate gas transportation arrangements and perform revenue receipt and related services. Our customers also include pipelines and transmission companies. During 2009, approximately 55% of our natural gas production was sold under fixed-price contracts at rates ranging from $5.20 to $9.15 per Dth. The balance of our natural gas production for the year was sold primarily at prices determined monthly under formulas based on prevailing market indices. The gas sales contracts covering both types of marketing arrangements yield upward adjustments from index based pricing for throughput with an energy content between 1 Dth and 1.1 Dth per Mcf.

Crude Oil and NGL Sales. Our crude oil production and NGL extracted from our Appalachian gas production is sold primarily to refineries at posted field or spot prices, net of transportation costs. Crude oil is generally picked up and transported by our customers from storage tanks located near the wellhead. NGL is delivered to customers from our Rogersville plant under rail shipping arrangements implemented during 2009, reducing our transportation costs for extracted natural gas liquids.

Utility Sales. Through our Sentra subsidiary, we own and operate distribution systems for retail sales of natural gas to two communities in southcentral Kentucky. As a public utility, Sentra’s gas sales are regulated by the Kentucky Public Service Commission. As of December 31, 2009, Sentra had over 200 customers, many of which are commercial and agri-business accounts. Demand for these services has benefited from increasing acceptance and use of natural gas by participants in the poultry industry, which is a major segment of the economy in Sentra’s service areas.

Competition

Competition in the oil and gas industry is intense, particularly for the acquisition of producing properties and undeveloped acreage. Independent oil and gas companies, drilling and production purchase programs and individual producers and operators actively bid for desirable oil and gas properties and for the equipment and labor required to develop and operate them. Strength in domestic natural gas prices for several years prior to the current economic downturn heightened the demand, competition and cost for these resources. Many industry competitors have exploration and development budgets substantially greater than ours, potentially reducing our ability to compete for desirable properties. To compete effectively, we have structured our business to capitalize on our experience and strengths, including our extensive infrastructure base. We maintain a disciplined approach to selecting property acquisition and development opportunities and a commitment to infrastructure control, with a view to consolidating our position as a niche developer and an established producer in our operating areas.

Regulation

General. The oil and gas business is subject to broad federal and state laws that are routinely under review for amendment or expansion. Various agencies that administer these laws have issued extensive regulations that are binding on industry participants. Many of these laws and regulations, particularly those affecting the environment, have become more stringent in recent years, with increased penalties for noncompliance, creating the risk of greater liability on a larger number of potentially responsible parties. The following overview of oil and gas industry regulation is summary in nature and is not intended to cover all regulatory matters that could affect our operations.

State Regulation. State statutes and regulations require permits for drilling operations and construction of gathering lines, as well as drilling bonds and reports on operations. These requirements can create delays in drilling and completing new wells and connecting completed wells. Kentucky and other states in which we conduct operations also have statutes and regulations governing conservation matters. These include regulations affecting the size of drilling and spacing or proration units, the density of wells that may be drilled and the unitization or pooling of oil and gas properties. State conservation laws generally prohibit the venting or flaring of gas and impose requirements on the ratability of production. None of the existing statutes or regulations in states where we operate currently impose restrictions on the production rates of our wells or the prices received for our production.

Federal Regulation. The sale and transportation of natural gas in interstate commerce is subject to regulation under various federal laws administered by FERC. During the last decade, a series of initiatives were undertaken by FERC to remove various barriers and eliminate practices that historically limited producers from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. These regulations have had a profound influence on domestic natural gas markets, primarily by increasing access to pipelines, fostering the development of a large short term or spot market for gas and creating a regulatory framework designed to put gas sellers into more direct contractual relations with gas buyers. These changes in the federal regulatory environment have greatly increased the level of competition among suppliers. They have also added substantially to the complexity of marketing natural gas, prompting many producers to rely on highly specialized experts for the conduct of gas marketing operations.

Environmental Regulation. Participants in the oil and gas industry are subject to numerous federal, state and local laws and regulations designed to protect the environment. These include regulations governing the generation, storage, handling and disposal of materials and the discharge of materials into the environment. Liability for some violations of these laws and regulations may be unlimited in cases of willful negligence or misconduct, and there is no limit on liability for environmental clean-up costs or damages on claims by the state or private parties. Under regulations adopted by the Environmental Protection Agency (EPA) and similar state agencies, producers must prepare and implement spill prevention control and countermeasure plans to deal with the possible discharge of oil into navigable waters. State and local permits or approvals may also be needed for waste-water discharges and air pollutant emissions. Violations can result in substantial liabilities, penalties and injunctive restraints, as well as potential claims by landowners and other third parties for personal injury and property damage.

We conduct our drilling and production activities to comply with all applicable environmental regulations, permits and lease conditions, and we monitor drilling subcontractors for environment compliance. While we believe our operations conform to those conditions, we remain at risk for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities by prior owners or operators of properties in which we own interests. In any of those events, we could be exposed to liability for clean-up costs or damages in excess of insurance coverage, and we could be required to remove improperly disposed materials, remediate property contamination or undertake plugging operations to prevent future contamination.

Regulation of greenhouse gas (GHG) emissions and hydraulic fracturing presents a number of issues for our industry. Although we use only nitrogen fracturing and are not subject to a recently adopted EPA rule requiring annual reporting of GHG emissions, we monitor legislative and regulatory developments on these issues at both the federal and state levels. We will continue to review and take appropriate actions where necessary to comply with any new environmental policies, legislation or regulations affecting our operations.

Occupational Safety Regulations. We are subject to various federal and state laws and regulations intended to promote occupational health and safety. Although all of our wells are drilled by independent subcontractors, we have adopted environmental and safety policies and procedures designed to protect the safety of our own supervisory staff and to monitor all subcontracted operations for compliance with applicable regulatory requirements and lease conditions, including environmental and safety compliance. This program includes regular field inspections of our drill sites and producing wells by members of our operations staff and internal assessments of our compliance procedures. We consider the cost of compliance a manageable and necessary part of our business.

Employees

As of December 31, 2009, we had 111 full-time employees. Our staff includes professionals experienced in geology, petroleum engineering, land acquisition, finance, accounting and law.

Gold and Silver Properties

We own rights to gold and silver properties spanning 381 acres on Unga Island in the Aleutian Chain, approximately 579 miles southwest of Anchorage, Alaska. The property interests are comprised of various federal patented lode and mill site claims and several state mining claims. There are inferred but no defined mineral reserves for either of these claims. While we continue to expend funds required for maintaining our interests in these claims, we stopped all exploratory work on the properties in 1996 and elected to write off their remaining carrying value in 2000. We have no plans to develop these properties, which would require rehabilitation and equipping of existing mine shafts and workings, level rehabilitation and geologic sampling and mapping prior to any surface and underground drilling. Our objective is to eventually monetize our interests in these properties through a joint venture arrangement or sale. Implementing this strategy will depend on price expectations for gold and silver as well as a variety of geological and market factors beyond our control.

Office Facilities

We lease 13,852 square feet of commercial space for our principal and administrative offices in Lexington, Kentucky at monthly rents ranging from $20,398 to $21,355 through the end of the lease term in January 2013. This reflects expansion of our offices under lease modifications and renewals we implemented during the last several years.

Item 1A Risk Factors

Our business involves numerous business and operating risks, many of which have been heightened by the contraction of the financial markets and our economy as a whole. The risks and related factors we consider material to our business are summarized below.

Natural gas and NGL prices are volatile, and continuing weakness in commodity prices could reduce our revenue, liquidity and ability to grow.

Factors Affecting Market Volatility. Our financial performance and prospects depend on the prices we receive for sales of natural gas and NGL, which accounted for 93% of our total production revenues in 2009. Commodity prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Natural gas prices declined sharply since the second half of 2008. While the decline from mid-year 2008 levels has been extreme, natural gas prices have historically been subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and many other factors beyond the control of producers. These factors are interrelated and include:

	•		the extent of domestic natural gas and NGL production, which has increased over the last few years from the use of horizontal drilling technologies to accelerate development of shale and other unconventional resource plays;

	•		the impact of weather and general economic conditions on consumer and industrial demand for natural gas;

	•		volatile trading patterns in the commodities trading markets;

	•		the proximity and capacity of pipelines;

	•		storage levels;

	•		comparative prices and availability of alternative fuels;

	•		worldwide supply and demand for oil, natural gas, NGL and liquefied natural gas; and

	•		federal and state regulatory and conservation programs, including possible climate-related measures for regulating greenhouse gas emissions.

Impact of Commodity Prices on Financial Performance. The volatility of energy markets makes it extremely difficult to predict future natural gas prices. Because we sell our natural gas production under market-sensitive arrangements, we are exposed us to this price volatility. We do not address this risk through financial hedging, but we do use fixed-price, fixed-volume physical delivery contracts that cover a portion of our natural gas production for various terms, up to two years from the contract date. While prices established by our outstanding physical delivery contracts are favorable compared to current spot markets indices, the use of these arrangements in volatile markets could result in future gas sales at fixed prices below prevailing market prices at the time of delivery. Continued weakness in the energy markets or further erosion of natural gas prices would limit our ability to obtain favorable terms for future production under these type of arrangements, potentially reducing our production revenue and cash flow.

Impact of Commodity Prices on Reserve Estimates. Lower natural gas prices not only decrease our revenues on a per unit basis but may also reduce the amount of natural gas that we can produce economically. Our estimated proved reserves as of December 31, 2009 reflect negative revisions of approximately 6.9 Bcfe from the prior year-end estimates as a result of commodity price declines. In addition, our 2009 year-end estimates include proved undeveloped locations that would generate positive future net revenue, based on the constant prices and costs determined under the current reserve rules, but would have negative present value when discounted at 10% per year under the standardized measure. Further deterioration in natural gas prices could require us to make additional downward adjustments to our estimated proved reserves. Under successful efforts accounting rules, this could potentially require impairment charges in future periods if the carrying value of any proved oil and gas property exceeds the expected undiscounted future net cash flows from that acreage based on commodity prices or other economic factors at the time of the impairment review. While any impairment charge would not affect our cash flow from operations, it could reflect our long-term ability to recover an investment based on prevailing conditions and would impact our reported earnings and leverage ratios.

We are leveraged and may be unable to repay or refinance our long-term debt on satisfactory terms.

We have $28.7 million principal amount of amortizing convertible notes due May 1, 2012 and $39.5 million of credit facility borrowings outstanding as of the date of this report, with a borrowing base of $53 million. The borrowing base limits the amount we can have outstanding under our revolving credit facility, as determined semi-annually by the lenders. A recent amendment to the credit agreement provides for borrowing base reductions of $1 million each month from February 2010 until the next semi-annual redetermination scheduled for April 2010. Redeterminations of the borrowing base primarily reflect estimated volumes of our proved developed oil and gas reserves. However, the lenders apply their own price decks, generally at a risk-adjusted discount to prevailing commodity prices, and they may also consider other credit factors and general economic conditions in our industry. Any reduction in our borrowing base below our outstanding indebtedness would require us to repay the excess or provide additional collateral. Our ability to reduce, repay or refinance our debt at maturity will be subject to our future performance and prospects as well as market and general economic conditions beyond our control. There can be no assurance that we will be able to secure the necessary refinancing on satisfactory terms.

Our outstanding convertible notes require monthly principal amortization payments either in cash, which may be unavailable, or in common shares, which may be dilutive to shareholders.

While our note restructuring in January 2010 reduced our outstanding convertible debt by $8.3 million and extended the final maturity of the debt until May 2012, monthly principal amortization requirements on outstanding exchange notes could adversely affect us. Under a credit agreement amendment entered in connection with the note restructuring, we may not receive any upstream dividends from our operating subsidiary for principal installments on the exchange notes if they would cause our revolving debt to exceed 80% of the facility’s borrowing base. In view of scheduled and anticipated reductions in the borrowing base, this could limit our ability to make amortization payments on the notes in cash. To the extent we use common shares for that purpose, they will be valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the stock (VWAP) prior to the installment date. In addition, under the true-up provisions of the notes, if the 20-day VWAP following an installment payment in stock differs from the share value applied to that payment, any shortfall will be settled in additional shares. Accordingly, although the exchange notes are intended to provide a flexible repayment structure with the potential for replacing part of the convertible debt with equity at a premium to our stock price at the time of the exchange, the use of common shares to pay all or part of the note installments could be dilutive to shareholders.

The level and terms of our outstanding debt may limit our financial and operating flexibility and performance.

The amount and terms of our debt may adversely affect our business in various ways. Among other adverse consequences, our outstanding indebtedness could:

	•		limit our ability to take advantage of acquisition and development opportunities or otherwise realize the value of our assets, to the extent that operating cash flow otherwise available for these activities is required to service or repay our debt;

	•		increase our vulnerability to adverse economic and industry conditions;

	•		limit our flexibility in planning for developments or reacting to changes in our industry; and

	•		place us at competitive disadvantage to producers in our operating areas with less debt and greater liquidity.

Challenging economic, business and industry conditions may adversely impact our operating results, liquidity and future prospects.

The economic downturn has required us to modify our business plan and may continue to adversely affect our business and prospects in various ways. The sale of our Appalachian Gathering System during 2009 enabled us to substantially reduce our revolving senior debt but also eliminated our cost savings from ownership of those facilities. Similarly, while we met our 2009 drilling commitments and near-term objectives with a drilling budget limited to internally generated cash flow, this required a return to our established partnership structure for participation in these initiatives, which proportionately reduces our interest in wells with joint ownership. Our ability to continue developing our properties with outside participation from sponsored drilling partnerships could be impaired by any adoption of legislative proposals for eliminating IDC and depletion deductions for federal income tax purposes, which is also included among the deficit reduction measures in the pending fiscal 2011 federal budget proposal released by the White House in February 2010.

Historically, we have relied on the financial markets to provide us with additional capital for property acquisitions and a more aggressive development program than we could fund internally. Adverse conditions have restricted our access to these markets, and continuation of these conditions may increase our cost of capital or our ability to raise capital from the sale of our debt or equity securities. Without greater access to the credit and capital markets, we could be required to sell additional assets or further reduce our drilling expenditures, which could result in the loss of undeveloped acreage from unsatisfied drilling commitments. Deteriorating economic conditions could also affect the collectability of our trade receivables, including production payments from our interests in non-operated wells, and could impair the effectiveness of our physical delivery contracts if counterparties are unable or unwilling to perform their obligations.

Our current proved developed reserves will decline from depletion of our existing wells.

Unless we continue to expand our reserves through the drillbit or acquire additional proved properties, our current proved developed reserves will decline as they are produced. Based on extensive historical production profiles for vertical wells in the Appalachian Basin and the limited production history for horizontal Devonian shale wells in the region, the blended decline rate for our proved developed reserves as of December 31, 2009 averaged 15.7% for 2010, decreasing hyberbolically to 5.5% in 2023. The actual performance of our wells could differ from these estimates, and EURs for our horizontal wells could vary even more materially from their estimated reserves in view of their limited production history. The depletion of our reserves, whether at anticipated rates or otherwise, will reduce cash flow for future growth as well as the assets available to secure financing for the development of our oil and gas properties and replacement of our existing reserves.

Estimates of our proved reserves are based on assumptions that could cause them to be substantially higher or lower than the volume and net present value of natural gas and oil actually recovered.

There are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production, as well as the timing and amount of development expenditures and production costs. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be directly measured. The accuracy of any reserve estimate is dependent on the quality of available data and is subject to engineering and geological interpretation and judgment. Results of our drilling and production as well as changes in commodity prices and production costs after the date of our estimates may require future revisions of the estimates. In addition, estimates of our proved undeveloped reserves assume that we will be able to make the necessary capital expenditures, and we may not have the capital or financing we need for their development at the pace or levels assumed in our estimates. As a result, our reserve estimates may differ materially from the quantities of natural gas and oil that are ultimately recovered.

We may be unable to fully develop our oil and gas properties due to general economic conditions or capital constraints.

As of December 31, 2009, approximately 76% of our oil and gas properties were undeveloped. Our ability to develop our properties at the levels and pace anticipated by our business model is uncertain. Developing these properties will require significant capital expenditures for ongoing drilling operations, and we may not have the capital or financing we need for their development. Our costs associated with developing these resources is also uncertain and may increase disproportionately with commodity prices over time. Any of these factors could cause our actual results from future development initiatives on unproved properties to vary significantly from the results anticipated in our business plan.

The timing and costs of implementing our planned drilling schedule are uncertain and may differ materially from our expectations.

Our cash flow, earnings and prospects are highly dependent on our success in efficiently developing and exploiting our current reserves and resources, as well as our ability to find additional recoverable reserves economically. Executing our planned drilling schedule is subject to a number of uncertainties, including our access to capital, seasonal conditions, regulatory approvals and the continued availability of field services and equipment. Drilling activity increased appreciably prior to the third quarter of 2008 in response to higher commodity prices and reported success in regional shale plays, notably the Marcellus play near our operating areas in the Appalachian Basin. The heightened demand for field services contributed to constraints on the availability of skilled labor, equipment, pipeline capacity and other resources in the region. While the steep decline in natural gas prices after July 2008 ultimately reduced drilling activity, drilling costs did not begin to moderate until the first quarter of 2009.

Continued market disruptions may cause delays in drilling operations and the possibility of poor results. Because of these uncertainties, we may be unable to drill and produce our planned drilling locations or alternative prospects on schedule or on budget. Actual results from these initiatives may differ materially from our expectations, which could adversely affect all aspects of our business.

Our operations involve hazards and exposure to liabilities that might not be fully covered by insurance.

Our drilling, production and gas gathering operations involve many operating hazards and a high degree of risk. They include the risk of fire, explosions, blowouts, craterings, pipe or mechanical failure of drilling equipment, casing collapse and environmental hazards such as gas leaks, ruptures and discharges. Any of these hazards could result in personal injury, property and environmental damage, clean-up responsibilities and other regulatory penalties. See “Business and Properties — Regulation.” While we conduct our operations to comply with applicable environmental regulations, permits and lease conditions, including maintenance of insurance against these risks, we remain exposed to liabilities for inadvertent noncompliance, conditions beyond our control and undetected conditions resulting from activities by prior owners or operators of properties in which we own interests. As a result, the operating hazards associated with our development and production activities may result in substantial liabilities, some of which may not be fully covered by our insurance.

Our production volumes may be less than anticipated.

Various field operating conditions may adversely our production volumes. These conditions include potential delays in obtaining regulatory approvals and easements for connecting completed wells to existing gathering facilities and the risk that production from connected wells could be interrupted, or shut in, from time to time for various reasons, including weather conditions, accidents, loss of pipeline access, mechanical conditions, field labor issues or intentionally as a result of market conditions. While close well monitoring and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Moreover, due to the short production history for horizontal shale wells in our operating areas and similar regional plays, the timing and extent of production declines for our horizontal wells cannot be predicted with any certainty.

We depend on key personnel for decision making and industry contacts.

We are dependent on the continued contributions of our executives and key personnel for the decision making and industry contacts necessary to manage and maintain growth within our highly competitive industry. There are a limited number of people with this level of knowledge and experience in our operating areas, and competition for qualified personnel can be intense. While we have retention agreements with our senior management or other key personnel, the loss of their services for any reason could have a material adverse effect on our business and prospects.

We have never paid dividends on our common stock and do not anticipate any change in that policy.

We have never paid cash dividends on our common stock. Our current policy is to retain future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend upon our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant. If we issue any preferred stock, it will be eligible for dividends prior and in preference to our common stock, when and if declared by the board of directors.

Market prices for our common stock are volatile.

The market price of our common stock is subject to significant volatility in response to variations in our operating and financial results, perceptions about our future prospects and other factors. Sales of substantial amounts of our common stock can also affect its market price. There were 33,521,512 shares of our common stock issued and outstanding at March 10, 2010. As of that date, we also had outstanding exchange notes that are convertible at the option of their holders for a total of 13,165,137 common shares, as well as outstanding stock options and warrants exercisable for an additional 5,998,706 shares of our common stock. All of these underlying shares are eligible for public resale without restrictions. Sales of substantial amounts of our common stock in the public market, or the perception that substantial sales may occur, could adversely affect prevailing market prices of the common stock.

Failure to stay in compliance with Nasdaq listing requirements would adversely affect the market price and liquidity of our common stock.

To remain eligible for trading on the Nasdaq Global Select Market, we must meet various requirements, including corporate governance standards, specified shareholders’ equity and a minimum bid price for our common stock above $1.00 per share. Although the market price and related market value requirements for continued listing afford a grace period to regain compliance, it is currently limited to 180 days. If our common stock were to be delisted, liquidity in the stock would be impaired. Any delisting of our common stock would also trigger an event of default that would entitle holders of our outstanding convertible notes to require us to redeem the notes at a default rate equal to 125% of their face amount.

Our undeveloped gold and silver properties may never be profitable or monetized.

We have gold and silver properties in Alaska that are undeveloped, dormant and unprofitable. To retain our interests in the properties, we must expend funds each year to maintain the underlying mineral rights. We have no plans to develop these properties independently and instead monetize our interests in these properties through a joint venture arrangement or sale. are seeking either a joint venture partner to provide funds for additional exploration of the prospects or a buyer for the properties. Our ability to find a strategic partner or buyer will depend on the anticipated profitability of potential production activities as well as the price of gold and silver, which in turn is affected by factors such as inflation, interest rates, currency rates, geopolitical and other factors beyond our control. We have not derived any revenues from our gold and silver properties and may never be able to realize any production revenues or sale proceeds from the properties.

Item 1B Unresolved Staff Comments

None.

Item 3 Legal Proceedings

We are involved in several legal proceedings incidental to our business, none of which is considered to be material to our consolidated financial position, results of operations or liquidity.

Item 4 Submission of Matters to a Vote of Security Holders

No proposals were submitted for approval by our shareholders during the fourth quarter of 2009.

Part II

Item 5 Market for Common Stock and Related Security Holder Matters

Trading Market

Our common stock has traded on the Nasdaq Global Select Market under the symbol NGAS. The following table shows the range of high and low bid prices for our common stock during the periods indicated, together with the average daily trading volume, as reported by Nasdaq. These quotations represent inter-dealer prices, without mark-ups or commissions, and they may not necessarily correspond to actual sales prices.


		Bid Prices				Average Daily
		High		Low		Volume
2008	First quarter	$	6.39	$	4.50		235,556
	Second quarter		10.31		5.58		452,262
	Third quarter		9.75		4.41		361,095
	Fourth quarter		4.80		1.30		289,235

2009	First quarter	$	2.26	$	0.77		202,114
	Second quarter		3.00		1.18		280,423
	Third quarter		2.62		1.46		428,316
	Fourth quarter		2.40		1.60		268,019
2010	First quarter (through March 5^th)	$	2.14	$	1.35		379,969

Security Holders

As of March 5, 2010, there were 609 holders of record of our common stock. We estimate there were approximately 7,500 beneficial owners of our common stock as of that date.

Dividend Policy

We have never paid cash dividends on our common stock. Our current policy is to retain any future earnings to finance the acquisition and development of additional oil and gas reserves. Any future determination about the payment of dividends will be made at the discretion of our board of directors and will depend on our operating results, financial condition, capital requirements, restrictions in debt instruments, general business conditions and other factors the board of directors deems relevant.

Common Shares Issuable under Equity Compensation Plans

The following table shows the amount of our common stock issuable as of December 31, 2009 under our equity compensation plans, which are defined to include stock award and option plans, individual compensation arrangements and obligations under warrants or options issued in financing transactions and property acquisitions.

[a]

Shares Issuable

Weighted Average

Shares Remaining

Upon Exercise of

Exercise Price of

Available for Future

Outstanding

Issuance under Equity

Options and Warrants

Options, Warrants

Compensation Plans

Plan Category

and Rights

(excluding column [a])

Plans approved by shareholders

3,873,668

3.92

520,473

Plans not approved by shareholders

1,740,000

2.35

—

Total

5,613,668

3.44

520,473

Performance Graph

The following graph presents a comparison of annual percentage changes in the cumulative total return on our common stock over the last five years with the total return on the Dow Jones U.S. Exploration and Production Index and the S&P 500 over the same period, assuming the investment of $100 in our common stock and each index, with reinvestment of any dividends. The performance graph is being furnished, not filed, for purposes of the Exchange Act and is not incorporated by reference in any registration statement under the Securities Act of 1933.


	2004		2005		2006		2007		2008		2009
NGAS	$	100	$	230	$	140	$	123	$	36	$	37
S&P 500		100		105		122		128		81		102
Dow Jones US E&P		100		165		174		250		150		211

Item 6 Selected Financial Data

Our consolidated financial statements included in this report have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP). All of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are in U.S. dollars. We are organized at the parent company level under the laws of British Columbia, and we prepared our consolidated financial statements prior to 2006 in accordance with accounting principles generally accepted in Canada (Canadian GAAP). Our adoption of U.S. GAAP did not have a material effect on our reported financial condition or results for prior periods and did not require us to restate any previously issued financial statements, which included reconciliations between items with different treatment under Canadian and U.S. GAAP.

The following table presents our summary selected consolidated financial data as of and for each of the five years ended December 31, 2009. The financial data is derived from our audited consolidated financial statements, which have been audited by Hall, Kistler & Company LLP, beginning in 2006, under U.S. GAAP and by Kraft Berger LLP for prior years under Canadian GAAP. The summary selected consolidated financial data as of December 31, 2009 and 2008 and for the three years ended December 31, 2009 should be read in conjunction with our consolidated financial statements and related notes included at the end of this report, as well as the discussion following the table, which presents management’s analysis of events, factors and trends with an important effect or prospective impact on our financial condition, results of operations and cash flows.

(In thousands, except per share data)


	Year Ended December 31,
Statement of Operations Data:	2009			2008		2007			2006		2005
Total revenues	$	57,824		$	84,407	$	70,203		$	79,820	$	62,228
Direct expenses		32,702			43,981		39,044			49,361		40,477
Net income (loss)		(7,701	)		2,936		(817	)		1,992		953
Net income (loss) per common share (basic)		(0.27	)		0.11		(0.04	)		0.09		0.05
Weighted average common shares outstanding		28,256			26,409		22,240			21,511		17,351


	As of December 31,
Balance Sheet Data:	2009			2008			2007			2006			2005
Current assets	$	18,567		$	12,052		$	11,240		$	24,656		$	34,016
Current liabilities		44,642	⁽¹⁾		17,571			12,381			25,484			34,880
Working capital (deficit)		(26,075	)		(5,519	)		(1,141	)		(828	)		(864	)
Total assets		214,616			247,354			204,801			178,219			146,774
Total liabilities		102,765			143,477			104,892			101,862			74,546
Shareholders’ equity		111,851			103,877			99,909			76,357			72,227


(1)		Includes the carrying amount of our 6% convertible notes due December 2010. Our convertible debt was restructured in January 2010. See “Business and Properties — Recent Developments.”


		Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent exploration and production company focused on natural gas shale plays in the Appalachian and Illinois Basins. We also operate the gas gathering facilities for our core properties, providing deliverability directly from the wellhead to interstate pipelines serving major east coast natural gas markets. We develop many of our prospects with participation from sponsored drilling partnerships, maintaining combined interests as both general partner and an investor ranging from 12.5% to 75%, along with additional reversionary interests after specified distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation.

Results of Operations — 2009 and 2008

Revenues. The following table shows the components of our revenues for 2009 and 2008, together with their percentages of total revenue in 2009 and percentage change on a year-over-year basis.


	Year Ended December 31,
			% of					%
Revenue:	2009		Revenue			2008		Change
Contract drilling	$	24,279,345		42	%	$	35,553,956		(32	)%
Oil and gas production		26,586,422		46			38,522,474		(31	)
Gas transmission, compression and processing		6,957,906		12			10,330,234		(33	)

Total	$	57,823,673		100	%	$	84,406,664		(31	)

Our total revenues for 2009 reflect the impact of declining commodity prices, reduced drilling activity and the third-quarter sale of our Appalachian Gathering System, which also eliminated our cost savings from ownership of these facilities. In view of our current business model for maintaining capital expenditures in line with operating cash flows, we do not expect this trend to reverse without a significant recovery in commodity prices or increased participation by sponsored partnerships in our drilling activities.

Contract drilling revenues reflect the size and timing of our drilling partnership initiatives. Although we receive the proceeds from private placements in sponsored partnerships as prepayments under our drilling contracts, revenues from the interests of outside investors are recognized on the completed contract method as the wells are drilled, rather than when funds are received. Our contract drilling revenues in 2009 reflect the challenging economic environment, which contributed to a 44% reduction in the size of our 2009 drilling partnership compared to the prior year’s program. With a raise of $19.25 million, the partnership is participating in 22 horizontal wells, of which four wells are being drilled during the 2010 first quarter.

Production revenues for 2009 reflect year-over-year declines of 31% in natural gas prices, 45% in oil prices and 48% for sales of natural gas liquids. The impact of weak commodity prices was partially offset by an increase of 6% in production output to 3,978 Mmcfe, compared to 3,745 Mmcfe in the prior year. Our volumetric growth reflects our transition to horizontal drilling throughout our operated properties in 2009. During the year, approximately 55% of our natural gas production was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2009 averaged $7.24 per Mcf for our Appalachian production and $6.17 per Mcf overall, compared to an average overall realization of $8.89 per Mcf in 2008.

The contraction of gas transmission, compression and processing revenues was driven by our sale of the Appalachian Gathering System in the third quarter of 2009. See “Business and Properties — Recent Developments.” Following the sale, our gas transmission, compression and processing revenues were limited primarily to fees for moving third-party production through our retained gas gathering facilities, gas utility sales and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.

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


	Year Ended December 31,
Direct Expenses:	2009		Margin			2008		Margin
Contract drilling	$	18,185,340		25	%	$	27,272,756		23	%
Oil and gas production		11,357,397		57			12,600,897		67
Gas transmission, compression and processing		3,159,331		55			4,107,763		60

Total direct expenses		32,702,068		43	%		43,981,416		48	%


Other Expenses:				% Revenue						% Revenue
Selling, general and administrative		11,658,541			20	%		14,005,041			17	%
Options, warrants and deferred compensation		1,307,194			2			911,561			1
Depreciation, depletion and amortization		14,019,826			24			12,418,234			15
Bad debt expense		—			N/A			749,035			1
Interest expense, net of interest income		8,694,256			15			5,479,233			6
Gain on sale of assets		(3,346,491	)		N/A			(14,104	)		N/A
Fair value gain on derivative financial instruments		(14,726	)		N/A			—			N/A
Other, net		845,560			1			139,176			—

Total other expenses	$	33,164,160					$	33,688,176

Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses represented 75% of contract drilling revenues in 2009, compared to 77% in the prior year. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. Historically, our ownership of the Appalachian Gathering System eliminated transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system. The increase in production expenses year-over-year primarily reflects higher transportation costs following our sale of the Appalachian Gathering System in the third quarter of 2009.

Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, were substantially reduced following our sale of the Appalachian Gathering System. Our remaining infrastructure position is comprised of 100% interests in the gas gathering facilities for our Haley’s Mill and Kay Jay fields, 50% interests in our Haley’s Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses in future periods will reflect this reduction in our infrastructure asset base.

Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling partnerships and general overhead costs. Our SG&A expenses decreased by 17% year-over-year, primarily from the decline in 2009 partnership sales. As a percentage of revenues, SG&A expenses increased from 17% in 2008 to 20% in 2009.

Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $614,548 for deferred compensation cost in 2009.

Depreciation, depletion and amortization (DD&A) is recognized under the units-of-production method, based on the estimated proved developed reserves of the underlying oil and gas properties, and on a straight-line basis over the useful life of other property and equipment. The 13% increase in DD&A charges reflects additions to our oil and gas properties from drilling initiatives, partially offset by a reduction in historical depletion costs for the Appalachian Gathering System following its sale in the third quarter of 2009.

Cash interest expense in 2009 decreased 8% year-over-year, reflecting the reduction of debt levels under our revolving credit facility from proceeds of our infrastructure monetization and equity raise in the third quarter of 2009. Non-cash interest expense of $3,925,531 reflects the application of the effective interest method for accretion of the debt discount for the embedded conversion feature of our 6% notes, which had a face amount of $37 million prior to the restructuring of our convertible debt in January 2010. See “Liquidity and Capital Resources.” The carrying amount of the exchange notes issued in the restructuring will be reduced by the initial fair values of the equity components of the exchange transaction. The resulting debt discount will be amortized to interest expense though the conversion or repayment dates of exchange notes and the expiration or exercise dates of the warrants.

We recognized pre-tax gains totaling $3,346,491 during 2009, primarily from our sale of the Appalachian Gathering System. We acquired the open-access portion of the system from Duke Energy in March 2006 for $18 million and built out the field-wide infrastructure at historical costs totaling approximately $33.5 million.

Deferred income tax expense recognized in both reporting periods represents future tax liabilities at the operating company level. Although we generally have no current tax liability at that level due to the utilization of deductions primarily for intangible drilling costs and percentage depletion, our consolidated income tax expense is negatively impacted by the non-recognition of tax benefits at the parent company level. For 2009, we had an income tax benefit of $341,394 from our operating loss.

Other expenses in 2009 totaled $845,560, net of minor income items. The recorded expenses include payments and accruals totaling $642,000 for various guaranteed obligations of a Virginia steam company in which we previously held a 50% interest. We have also accrued $350,000 for the unreimbursed part of a personal injury litigation settlement reached in March 2010, which we will seek to recoup under our umbrella liability insurance coverage.

Net Income (Loss) and EPS. We recognized a net loss of $7,701,161 in 2009, reflecting the foregoing factors. Earnings (loss) per share (EPS) was $(0.27) on 28,256,253 weighted average common shares outstanding, compared to net income of $2,936,275 realized in 2008, with EPS of $0.11 on 26,910,642 fully diluted shares.

Results of Operations — 2008 and 2007

Revenues. The following table shows the components of our revenues for 2008 and 2007, together with their percentages of total revenue in 2008 and percentage change on a year-over-year basis.


	Year Ended December 31,
			% of					%
Revenue:	2008		Revenue			2007		Change
Contract drilling	$	35,553,956		42	%	$	34,334,829		4	%
Oil and gas production		38,522,474		46			28,148,689		37
Gas transmission, compression and processing		10,330,234		12			7,719,308		34

Total	$	84,406,664		100	%	$	70,202,826		20

Contract drilling revenues reflect the application of prepayments by outside investors under our drilling contracts with sponsored partnerships, which we recognize under the completed contract method as the wells are drilled. During 2008, we sponsored a program for participation in 89 wells on non-operated properties known as the HRE fields, spanning six counties in West Virginia and Virginia. Our contract drilling revenues in 2008 reflect ongoing operations for that program and the completion of our 2007 HRE program. Outside investors have interests of 75% before payout and 60% after payout in both of those programs.

The growth in our production revenues for 2008 reflects a 13% increase in production output to 3,745 Mmcfe, compared to 3,311 Mmcfe in 2007. Our volumetric growth was driven by added production from wells brought on line during 2008, including substantial contributions from our horizontal drilling initiatives. Approximately 50% of our natural gas production in 2008 was sold under fixed-price contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in 2008 averaged $9.59 per Mcf for our Appalachian production and $8.89 per Mcf overall, compared to an average overall realization of $8.19 per Mcf in 2007.

Gas transmission, compression and processing revenues for 2008 were driven by gas gathering and compression fees totaling $6,966,115 for moving third-party production through the Appalachian Gathering System and $746,970 in related processing fees for liquids extraction through our Rogersville plant. We also had contributions of $565,727 from gas utility sales and $458,154 from our 25% interest in the gathering system that services a non-operated coalbed methane project in the Arkoma Basin.

Expenses. The following table shows the components of our direct and other expenses for 2008 and 2007. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.


	Year Ended December 31,
Direct Expenses:	2008		Margin			2007		Margin
Contract drilling	$	27,272,756		23	%	$	26,773,028		22	%
Oil and gas production		12,600,897		67			7,648,558		73
Gas transmission, compression and processing		4,107,763		60			3,657,977		53
Impairment of oil and gas assets		—		N/A			964,000		N/A

Total direct expenses		43,981,416		48	%		39,043,563		44	%


Other Expenses:			% Revenue					% Revenue
Selling, general and administrative		14,005,041		17	%		12,920,591		18	%
Options, warrants and deferred compensation		911,561		1			1,069,306		2
Depreciation, depletion and amortization		12,418,234		15			10,416,696		15
Bad debt expense		749,035		1			215,000		—
Interest expense, net of interest income		5,479,233		6			6,007,105		9
Other, net		125,072		—			107,738		—

Total other expenses	$	33,688,176				$	30,736,436

Contract drilling expenses increased 2% year-over-year basis and represented 77% of contract drilling revenues, compared to 78% in 2007. All of our contract drilling activities in 2008 were conducted on non-operated HRE properties in West Virginia and Virginia. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

The increase in production expenses in 2008 primarily reflects our volumetric growth and higher severance and production taxes, as well as $2,282,841 in hauling costs for natural gas liquids, which we began stripping from our Appalachian production through our Rogersville plant during the first quarter of the year. As a percentage of oil and gas production revenues, our production expenses were 33%, compared to 27% in 2007, primarily reflecting start-up costs for bringing our Rogersville processing plant and our Fonde and Haley’s Mill gathering systems on line, as well as added transportation fees for extracted natural gas liquids.

Gas transmission, compression and processing expenses in 2008 were 40% of associated revenues, compared to 47% in the prior year. The margins for this part of our business benefited from third-party fees generated by the Appalachian Gathering System. Our gas transmission, compression and processing expenses do not include capitalized costs of approximately $10.1 million during 2008 for extensions of our field-wide gas gathering systems and additions to compression capacity required to bring new wells on line.

SG&A expenses in 2008 increased by 8% from the prior year, primarily reflecting sales costs for a drilling partnership launched in April 2008 for participation in our non-operated initiatives in West Virginia and Virginia, along with overhead costs for supporting our expanded operations as a whole. As a percentage of revenues, SG&A expenses decreased from 18% in 2007 to 17% in 2008.

Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. We also recognized an accrual of $286,419 in 2008 for deferred compensation costs.

The increase in DD&A charges in 2008 reflects substantial additions to our oil and gas properties, gas gathering systems and related equipment.

We recognized bad debt expenses aggregating $749,035 in 2008 for write-offs of receivables from a regional refinery for sales prior to its bankruptcy filing, a separate non-performing loan to a regional operator on a three-well project in Texas and unreimbursed trade debt we paid on behalf of a Virginia steam company in which we previously held a 50% interest. See “Critical Accounting Policies and Estimates — Allowance for Doubtful Accounts.”

Interest expense for 2008 decreased from lower variable rates under our revolving credit facility. Draws under the credit facility were used primarily to support our ongoing drilling initiatives and enhancements of our field-wide gas gathering systems.

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

Net Income and EPS. We realized net income of $2,936,275 in 2008, compared to a net loss of $816,597 recognized in 2007, reflecting the foregoing factors. EPS was $0.11 based on 26,409,275 weighted average basic common shares outstanding in 2008, compared to EPS of $(0.04) in 2007 based on 22,240,429 weighted average common shares outstanding.

Liquidity and Capital Resources

Liquidity. We completed a registered direct placement of 3.48 million units at $1.90 per unit on August 13, 2009, with net proceeds of approximately $6.1 million applied to debt reduction under our revolving credit facility. Each unit consisted of one share of our common stock and a warrant to buy 0.5 common share. The warrants are exercisable for a total of 1.74 million shares of our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances, during a four-year term expiring in February 2014.

During 2009, we generated net cash of $6,180,241 from operating activities and $22,755,628 from investing activities, which included our proceeds from the Appalachian Gathering System sale, all of which were applied to debt reduction under our revolving credit facility. Our investing activities also included capital expenditures aggregating $14,776,307, of which $11,914,566 was recorded as net additions to oil and gas properties. As a result of these activities, net cash increased to $4,332,650 at December 31, 2009 from $981,899 at the prior year-end.

Operating activities in 2008 provided net cash of $26,733,185. During the year, we used $56,875,544 in investing activities, most of which were capital expenditures for additions to our oil and gas properties and gathering systems. These investments were funded in part with net cash of $28,307,580 from financing activities, primarily consisting of advances under our revolving credit facility. As a result of these activities, net cash decreased from $2,816,678 at the end of 2007 to $981,899 at December 31, 2008.

Our working capital generally reflects wide fluctuations from the timing of customer deposits and expenditures under drilling contracts with our sponsored partnerships and from draws and payments under our credit facility. Since these fluctuations are normalized over relatively short time periods, we do not consider working capital to be a reliable measure of our liquidity. In addition, based on the December 2010 maturity of our 6% convertible notes, their entire carrying amount was reclassified as a current liability at December 31, 2009. This comprised most of the working capital deficit at year end, which was eliminated in January 2010 from the restructuring of our convertible debt.

Capital Resources. Our business involves significant capital requirements. The rate of production from oil and gas properties declines as reserves are depleted. Without successful development activities, our proved reserves would decline as oil and gas is produced from our proved developed reserves. We also have substantial annual drilling commitments under various leases and farmouts for our Appalachian properties, including an annual 25-well commitment for our Leatherwood field. Our long-term performance and profitability is dependent not only on meeting these commitments and recovering existing oil and gas reserves, but also on our ability to find or acquire additional reserves and fund their development on terms that are economically and operationally advantageous.

Historically, we have relied on a combination of cash flows from operations, bank borrowings and private placements of our convertible notes and equity securities to fund our reserve and infrastructure development and acquisition activities. We also relied on participation in our drilling initiatives by outside investors in our sponsored partnerships. For 2008, we changed our business model to accelerate organic growth by retaining all of our available working interest in wells drilled on operated properties, limiting our use of drilling partnerships to non-operated initiatives. While we are committed to continue expanding our reserves and production through the drillbit, we have addressed the challenging conditions in our industry during the last two years by monetizing the Appalachian Gathering System, restructuring our convertible debt, reducing our capital expenditures and returning to our successful partnership structure for sharing development costs on operated properties.

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

In January 2010, we retired $37 million of our 6% convertible notes due December 15, 2010 (retired notes) in exchange for an aggregate of $28.7 million in new amortizing convertible notes due May 1, 2012 (exchange notes), together with 3,037,151 shares of our common stock, five-year warrants to purchase 1,285,038 common shares (exchange warrants) and cash payments totaling approximately $2.7 million. The exchange notes bear interest at 6% per annum, payable in cash at the beginning of each calendar quarter. They are convertible at the option of the holders into our common stock at $2.18 per share, and the exchange warrants are exercisable at $2.37 per share, subject in each case to certain volume limitations and adjustments for certain fundamental change transactions or share recapitalizations. Under certain conditions, we may call the exchange notes for redemption to force their conversion.

During the period from June 1, 2010 through the maturity date, we will be obligated to make 24 equal monthly principal amortization payments on outstanding exchange notes. Subject to certain volume limitations, true-up adjustments and other conditions, we may elect to pay all or part of each principal installment in common stock, valued at the lesser of $2.18 per share or 95% of the 10-day VWAP prior to the installment date. Each holder may elect to defer any installment payment to maturity. Holders also have the right to require us to redeem their exchange notes in cash upon any event of default at 125% of their principal amount or upon a change of control at 110% of their principal amount. Any exchange notes that are neither repaid, redeemed nor converted will be repayable at maturity in cash plus accrued and unpaid interest.

We have a senior secured revolving credit facility maintained by our operating subsidiaries with KeyBank National Association, as agent and primary lender. The facility provides for revolving term loans and letters of credit in an aggregate amount up to $125 million, with a scheduled maturity in September 2011. Outstanding borrowings under the facility bear interest at fluctuating rates ranging from the agent’s prime rate to 1.0% above that rate, depending on the amount of borrowing base utilization. We are also responsible for commitment fees at rates ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties. Outstanding borrowings under the facility aggregated $38.5 million at December 31, 2009, with a borrowing base of $55 million and a 5% interest rate. We are in compliance with our financial and other covenants under the credit agreement covering the facility.

In January 2010, we entered into an amendment to the credit agreement that permitted us to consummate the exchange transaction for our convertible debt, subject to certain non-financial covenants and borrowing base modifications. These include restrictions on upstream dividends from our operating subsidiary for any principal amortization payments on the exchange notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. The amendment also provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination scheduled for April 2010, resulting in a borrowing base of $53 million as of the date of this report. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend we used for repurchasing retired notes in the exchange transaction, unless recontributed for debt reduction under the credit facility by June 1, 2010.

Our ability to service and repay our revolving and convertible debt will be subject to our future performance and prospects as well as market and general economic conditions. Our future revenues, profitability and rate of growth will continue to be substantially dependent on the market price for natural gas. Future commodity prices will also have a significant impact on our ability to maintain or increase our borrowing capacity, obtain additional capital on acceptable terms and attract drilling partnership capital. While we have been able to mitigate some of the steep decline in natural gas prices with fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production, we are exposed to price volatility for future production not covered by these arrangements. See “Risk Factors” and “Quantitative and Qualitative Disclosures about Market Risk.”

We have addressed the economic downturn and challenging conditions in our industry by monetizing most of our gas gathering infrastructure, deleveraging and modifying our business model to reduce our reliance on the financial and capital markets. To realize our long-term goals for growth in revenues and reserves, however, we will continue to dependent on those sources of capital or other financing alternatives. Any prolonged constriction in the capital markets or protracted weakness in domestic energy markets could require us to sell additional assets or pursue other financing or strategic arrangements to meet those objectives and to repay or refinance our long-term debt at maturity.

Forward Looking Statements

Some statements made by us in this report are prospective and constitute forward-looking statements within the meaning of Section 21E of the Exchange Act and Section 27A of the Securities Act of 1933. Other than statements of historical fact, all statements that address future activities, outcomes and other matters we plan, expect, budget, intend or estimate, and other similar expressions, are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which are beyond our control. Among other things, these include:

•

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

•

commodity price volatility;

•

increases in the cost of drilling, completion, gas gathering and processing or other costs of developing and producing our reserves;

•

unavailability of drilling rigs and services;

•

drilling, operational and environmental risks; and

•

uncertainties about future federal and state regulatory, conservation and tax measures.

If the assumptions we use in making forward-looking statements prove incorrect or the risks described in this report occur, our actual results could differ materially from future results expressed or implied by the forward-looking statements. See “Risk Factors.”

Financial Market Risk

Interest Rate Risk. Borrowings under our secured credit facility bear interest at fluctuating market-based rates. Accordingly, we are exposed to interest rate risk on current and future indebtedness under the facility.

Foreign Market Risk. We conduct operations solely in the United States. As a result, our financial results are unlikely to be affected by factors such as changes in foreign currency exchange rates or weak economic conditions in foreign markets, except to the extent that global demand may affect domestic energy markets.

Contractual Obligations and Commercial Commitments

General. Our contractual obligations include long-term debt, operating leases, drilling commitments, transportation commitments, asset retirement obligations and leases for office facilities and various types of equipment. The following summarizes our contractual financial obligations at December 31, 2009 and their future maturities. The table does not include commitments under our gas gathering and sales agreements described below.


	Operating Leases						Long-Term
Year	Equipment		Premises		Total		Debt⁽¹⁾
2010	$	2,091,292	$	247,815	$	2,339,107	$	32,534,084
2011		1,831,447		252,389		2,083,836		38,593,557
2012		590,520		255,973		846,493		2,157,461
2013 and thereafter		51,928		21,355		73,283		198,818

Total	$	4,565,187	$	777,532	$	5,342,719	$	73,483,920


(1)		Excludes an allocation of $4,555,513 for the unaccreted debt discount on $37 million of 6% convertible notes due December 2010, which were reclassified as current liabilities at December 31, 2009 and restructured in January 2010.

Gas Gathering and Sales Commitments. We have various commitments under our gas gathering and sales agreements entered with Seminole and Seminole Energy in connection with our sale of the Appalachian Gathering System during the third quarter of 2009. See “Business and Properties — Recent Developments.” These agreements provide us with firm capacity rights for daily delivery of 30,000 Mcf of controlled gas and have an initial term of fifteen years with extension rights. Our commitments under these agreements include:

•

Base monthly gathering fees of $850,000, with annual escalations at the rate of 1.5%;

•

Base monthly operating fees of $175,000, plus $0.20 per Mcf of purchased gas; and

•

Monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on the Appalachian Gathering System by Seminole Energy.

Related Party Transactions

Because we operate through subsidiaries and managed drilling partnerships, our corporate structure causes various agreements and transactions in the normal course of business to be treated as related party transactions. Our policy to structure any transactions with related parties only on terms that are no less favorable to NGAS than could be obtained on an arm’s length basis from unrelated parties. Significant related party transactions are summarized in Notes 6 and 15 to the consolidated financial statements included in this report.

Critical Accounting Policies and Estimates

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

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

Impairment of Long-Lived Assets. Our long-lived assets include property, equipment and goodwill. Long-lived assets with an indefinite life are reviewed at least annually for impairment, and all long-lived assets are reviewed whenever events or changes in circumstances indicate that their carrying values may not be recoverable. During 2007, we recognized an impartment charge of $964,000 for exploratory well costs that had been capitalized for less than one year pending our assessment of reserves for the project.

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

Off-Balance Sheet Arrangements

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

Item 7A Quantitative and Qualitative Disclosures about Market Risk

Our major market risk exposure is the pricing of natural gas production, which has been highly volatile and unpredictable during the last several years. While we do not use financial hedging instruments to manage these risks, we do use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time up to two years from the contract date. Because these physical delivery contracts qualify for the normal purchase and sale exception under derivative fair value accounting standards, they are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of physical delivery contracts is included in our oil and gas revenues at the time of settlement, which in turn affects our average realized natural gas prices. See “Business and Properties — Producing Activities.”

Item 8 Financial Statements and Supplementary Data


	Page
Management’s Report on Internal Controls over Financial Reporting		F-1
Reports of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheets — December 31, 2009 and 2008		F-5
Consolidated Statements of Operations — For each of the three years ended December 31, 2009		F-6
Consolidated Statements of Changes in Shareholders’ Equity — For each of the three years ended December 31, 2009		F-7
Consolidated Statements of Cash Flows — For each of the three years ended December 31, 2009		F-8
Notes to Consolidated Financial Statements		F-9
Supplementary Oil and Gas Reserve Information — Unaudited		F-21
Supplementary Selected Quarterly Financial Data — Unaudited		F-25

Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A Controls and Procedures

Management’s Responsibility for Financial Statements

Our management is responsible for the integrity and objectivity of all information presented in this report. The consolidated financial statements included in this report have been prepared in accordance with U.S. GAAP and reflect management’s judgments and estimates on the effect of the reported events and transactions.

Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on management’s evaluation as of December 31, 2009, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures are effective to ensure that material information about our business and operations is recorded, processed, summarized and publicly reported within the time periods required under the Exchange Act, and that this information is accumulated and communicated to our management to allow timely decisions about required disclosures.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008 using the criteria established under Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on those criteria, management concluded that our internal control over financial reporting was effective as of December 31, 2009. Management reviewed the results of their assessment with the audit committee of our board of directors. The effectiveness of our internal control over financial reporting as of December 31, 2009 has been audited by Hall, Kistler & Company LLP, our independent registered public accounting firm, as stated in their report appearing on page F-2 of this report.

Changes in Internal Control over Financial Reporting

We regularly review our system of internal control over financial reporting to ensure the maintenance of an effective internal control environment. There were no changes in our internal control over financial reporting during the period covered by this report that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Item 9B Other Information

None.

Part III

Item 10 Directors, Executive Officers and Corporate Governance

Executive Officers

Our executive officers are listed in the following table, together with their age and term of service with the Company.


				Officer
Name	Age		Position	Since
William S. Daugherty		55	Chairman of the Board, President and Chief Executive Officer		1993
William G. Barr III		60	Vice President		1993
D. Michael Wallen		55	Vice President		1995
Michael P. Windisch		35	Chief Financial Officer		2002

A summary of the business experience and background of our executive officers is set forth below.

William S. Daugherty has served as our President, Chief Executive Officer and member of our board of directors since September 1993, as well as our Chairman of the Board since 1995. He has also served as the Chairman of the Board of NGAS Production Co., our operating subsidiary (NGAS Production), since 1984. Mr. Daugherty currently serves as the Governor of Kentucky’s Official Representative to the Interstate Oil and Gas Compact Commission and as a member of the Board of Directors of the Independent Petroleum Association of America. He also serves on the Unconventional Resources Technology Advisory Committee. He is a past president of both the Kentucky Oil and Gas Association (KOGA) and the Kentucky Independent Petroleum Producers Association. Mr. Daugherty holds a B.S. Degree from Berea College, Berea, Kentucky.

William G. Barr III has served as a Vice President of NGAS since 2004 and as Chief Executive Officer of NGAS Production since September 2005, having served as a Vice President of NGAS Production from 1993 until being appointed its CEO. Mr. Barr has more than 30 years of experience in the corporate and legal sectors of the oil and gas industry. Before joining NGAS Production, he served in senior management positions with several oil and gas exploration and production companies and built a significant natural resource law practice. Mr. Barr currently serves as Governing Member Trustee for the Energy & Mineral Law Foundation. He also serves as President of KOGA and as a member of its Board of Directors, as well as Vice Chairman of the Kentucky Gas Pipeline Authority. He received a Juris Doctorate from the University of Kentucky, Lexington, Kentucky.

D. Michael Wallen has served as a Vice President of NGAS since 1997 and as a Vice President of NGAS Production between 1995 and September 2005, when he was appointed as its President. For six years before joining NGAS Production, he served as the Director of the Kentucky Division of Oil and Gas. He has more than 25 years of experience as a drilling and completion engineer for various exploration and production companies. Mr. Wallen recently served as President of KOGA and currently serves as a member of its Board of Directors and Executive Committee. He has also served as President of the Eastern Kentucky Section of the Society of Petroleum Engineers and as the Governor’s Representative to the Interstate Oil & Gas Compact Commission. Mr. Wallen holds a B.S. Degree in Physics from Morehead State University, Morehead, Kentucky.

Michael P. Windisch has served as Chief Financial Officer of NGAS and NGAS Production since 2002. Prior to that time, he was employed by PricewaterhouseCoopers LLP, participating for five years in the firm’s audit practice. He was recently named Regional Financial Executive of the Year by the Institute of Management Accountants and Robert Half International. Mr. Windisch is a member of the American Institute of Certified Public Accountants and holds a B.S. Degree from Miami University, Oxford, Ohio, where he serves on the Advisory Board of the Department of Finance.

Incorporation of Part III Information by Reference

The balance of Part III to this report is incorporated by reference to the proxy statement for our 2010 annual meeting of shareholders to be filed with the Securities and Exchange Commission before the end of April 2010.

Part IV

Item 15 Exhibits, Financial Statement Schedules


		*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 Amortizing Convertible Note of NGAS Resources, Inc. due May 1, 2012 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).

4.2		Form of Warrant issued by NGAS Resources, Inc. on August 13, 2009 (incorporated by reference to Exhibit C to Underwriting Agreement dated August 10, 2009 between NGAS Resources, Inc. and BMO Capital Markets Corp., filed as Exhibit 1.1 to Current Report on Form 8-K [File No. 0-12185] filed August 11, 2009).

4.3		Form of Warrant issued by NGAS Resources, Inc. on January 12, 2010 (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).

10.1		2001 Stock Option Plan (incorporated by reference to Exhibit 10[b] to Annual Report on Form 10-KSB [File No. 0-12185] for the year ended December 31, 2002).

10.2		2003 Incentive Stock and Stock Option Plan (incorporated by reference to Exhibit 10.3 to Quarterly Report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).

10.3		Amended and Restated Credit Agreement dated as of May 30, 2008 (“ARCA”) among NGAS Resources, Inc., NGAS Production Co. and KeyBank National Association, as agent for the lenders named therein (incorporated by reference to Exhibit 10.6 to Quarterly Report on Form 10-Q [File No. 0-12185] for the quarter ended June 30, 2008).

10.4		Third Amendment to ARCA dated as of June 2, 2009 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K [File No. 0-12185] filed June 5, 2009).


		*Exhibit*
*Number*		*Description of Exhibit*
10.5		Fourth Amendment to ARCA dated as of January 11, 2010 (incorporated by reference to Exhibit 10.4 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).

10.6		Form of Exchange Agreement dated January 11, 2010 (“Exchange Agreements”) between NGAS Resources, Inc. and each holder of its 6% Convertible Notes due December 15, 2010 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K [File No. 0-12185] filed January 12, 2010).

10.7		NAESB Gas Purchase Agreement dated as of July 15, 2009 between NGAS Production Co. and Seminole Energy Services, LLC (incorporated by reference to Exhibit 10.5 to current report on Form 8-K [File No. 0-12185] dated July 17, 2009).

10.8		Form of Change of Control Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.9 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).

10.9		Form of Indemnification Agreement dated as of February 25, 2004 (incorporated by reference to Exhibit 10.10 to quarterly report on Form 10-QSB [File No. 0-12185] for the quarter ended June 30, 2004).

10.10		Form of Long-Term Incentive Agreement dated as of December 9, 2008 (incorporated by reference to Exhibit 10.11 to annual report on Form 10-K [File No. 0-12185] for the year ended December 31, 2008).

10.11		Form of general partnership agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.11 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).

10.12		Form of limited partnership agreement with sponsored investment partnerships (incorporated by reference to Exhibit 10.12 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).

10.13		Form of assignment of drilling rights with sponsored drilling programs (incorporated by reference to Exhibit 10.13 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).

10.14		Form of drilling and operating agreement with sponsored drilling programs (incorporated by reference to Exhibit 10.14 to amended annual report on Form 10-K/A [File No. 0-12185] for the year ended December 31, 2006).

11.1		Computation of Earnings Per Share (included in Note ___to the accompanying consolidated financial statements).

21.0		Subsidiaries (incorporated by reference to Exhibit 21.1 to annual report on Form 10-K [File No. 0-12185] for the year ended December 31, 2006).

23.1		Consent of Hall, Kistler & Company LLP.

23.2		Consent of Wright & Company, Inc., independent petroleum engineers.

24.1		Power of Attorney.

31.1		Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Exchange Act Rule 13a-14(a), as adopted under Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer pursuant to Exchange Act Rule 13a-14(b), as adopted under Section 906 of the Sarbanes-Oxley Act of 2002.

99.1		Independent Petroleum Engineers Audit Report.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, NGAS Resources, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 11, 2010.

NGAS Resources, Inc.


By:	/s/ William S. Daugherty	By:	/s/ Michael P. Windisch

	William S. Daugherty,		Michael P. Windisch,
	President and Chief Executive Officer		Chief Financial Officer
	(Principal executive officer)		(Principal financial and accounting officer)

In accordance with the Exchange Act, this report has been signed as of the date set forth below by the following persons in their capacity as directors of the NGAS Resources, Inc.


Name		Date
William S. Daugherty
Paul R. Ferretti*
James K. Klyman*
Thomas F. Miller*
Steve U. Morgan*


By:	/s/ William S. Daugherty	March 11, 2010

	William S. Daugherty,
	Individually and *as attorney-in-fact

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of NGAS Resources, Inc. (the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process defined by or under the supervision of the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. They include policies and procedures that:

•

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company;

•

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

•

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management has concluded that, as of December 31, 2008, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, Hall, Kistler & Company LLP, has audited the effectiveness of the Company’s internal control over financial reporting as of December 31, 2009, as stated in their report appearing on page F-3.


/s/ William S. Daugherty				/s/ Michael P. Windisch

William S. Daugherty,				Michael P. Windisch,
President and Chief Executive Officer				Chief Financial Officer
March 11, 2010				March 11, 2010

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

•

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of assets of the Company;

•


/s/ William S. Daugherty				/s/ Michael P. Windisch

William S. Daugherty,				Michael P. Windisch,
President and Chief Executive Officer				Chief Financial Officer
March 11, 2010				March 11, 2010

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.

We have audited NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NGAS Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, NGAS Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of operations, shareholders’ equity and cash flows of NGAS Resources, Inc., and our report dated March 9, 2010 expressed an unqualified opinion.



	/s/ Hall, Kistler & Company LLP

Canton, Ohio
March 9, 2010

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
NGAS RESOURCES, INC.

We have audited the accompanying consolidated balance sheets of NGAS Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years ended December 31, 2009. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of NGAS Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), NGAS Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 9, 2010 expressed an unqualified opinion thereon.



	/s/ Hall, Kistler & Company LLP

Canton, Ohio
March 9, 2010

F-4

NGAS Resources, Inc.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2009			2008
ASSETS
Current assets:
Cash	$	4,332,650		$	981,899
Accounts receivable		7,277,311			10,450,173
Note receivable		6,247,880			—
Prepaid expenses and other current assets		633,884			540,253
Loans to related parties		75,679			79,188

Total current assets		18,567,404			12,051,513

Bonds and deposits		258,695			623,898
Note receivable		6,766,451			—
Oil and gas properties		182,189,679			229,218,344
Property and equipment		5,113,093			3,285,925
Loans to related parties		171,429			171,429
Deferred financing costs		1,235,705			1,689,580
Goodwill		313,177			313,177

Total assets	$	214,615,633		$	247,353,866


LIABILITIES
Current liabilities:
Accounts payable	$	5,587,290		$	12,362,092
Accrued liabilities		938,829			675,141
Deferred compensation		—			2,246,439
Fair value of derivative financial instruments		111			—
Customer drilling deposits		5,581,877			2,262,955
Long-term debt, current portion		32,534,084			24,000

Total current liabilities		44,642,191			17,570,627

Deferred compensation		651,287			—
Deferred income taxes		12,559,549			12,949,476
Long-term debt		40,949,836			109,270,818
Other long-term liabilities		3,962,254			3,685,849

Total liabilities		102,765,117			143,476,770


SHAREHOLDERS’ EQUITY
Capital stock
Authorized:
5,000,000 Preferred shares
100,000,000 Common shares
Issued:
30,484,361 Common shares (2008 — 26,543,646)		117,142,639			110,626,912
21,100 Common shares held in treasury, at cost		(23,630	)		(23,630	)
Paid-in capital — options and warrants		4,467,246			3,774,600
To be issued:
9,185 Common shares (2008 — 9,185)		45,925			45,925

		121,632,180			114,423,807
Deficit		(9,781,664	)		(10,546,711	)

Total shareholders’ equity		111,850,516			103,877,096

Total liabilities and shareholders’ equity	$	214,615,633		$	247,353,866

See accompanying notes.

F-5

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2009			2008			2007
REVENUE

Contract drilling	$	24,279,345		$	35,553,956		$	34,334,829
Oil and gas production		26,586,422			38,522,474			28,148,689
Gas transmission, compression and processing		6,957,906			10,330,234			7,719,308


Total revenue		57,823,673			84,406,664			70,202,826


DIRECT EXPENSES

Contract drilling		18,185,340			27,272,756			26,773,028
Oil and gas production		11,357,397			12,600,897			7,648,558
Gas transmission, compression and processing		3,159,331			4,107,763			3,657,977
Impairment of oil and gas assets		—			—			964,000


Total direct expenses		32,702,068			43,981,416			39,043,563


OTHER EXPENSES (INCOME)

Selling, general and administrative		11,658,541			14,005,041			12,920,591
Options, warrants and deferred compensation		1,307,194			911,561			1,069,306
Depreciation, depletion and amortization		14,019,826			12,418,234			10,416,696
Bad debt expense		—			749,035			215,000
Interest expense		9,049,931			5,575,007			6,330,760
Interest income		(355,675	)		(95,774	)		(323,655	)
Loss (gain) on sale of assets		(3,346,491	)		(14,104	)		54,304
Fair value gain on derivative financial instruments		(14,726	)		—			—
Other, net		845,560			139,176			53,434

Total other expenses		33,164,160			33,688,176			30,736,436


INCOME (LOSS) BEFORE INCOME TAXES		(8,042,555	)		6,737,072			422,827

INCOME TAX EXPENSE (BENEFIT)		(341,394	)		3,800,797			1,239,424


NET INCOME (LOSS)	$	(7,701,161	)	$	2,936,275		$	(816,597	)


NET INCOME (LOSS) PER SHARE

Basic	$	(0.27	)	$	0.11		$	(0.04	)

Diluted	$	(0.27	)	$	0.11		$	(0.04	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:

Basic		28,256,253			26,409,275			22,240,429

Diluted		28,256,253			26,910,642			22,240,429

See accompanying notes.

F-6

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY


	Years Ended December 31,
	2009						2008						2007
	Shares			Amount			Shares			Amount			Shares			Amount
COMMON STOCK
Beginning balance		26,543,646		$	110,626,912			26,136,064		$	108,842,526			21,788,551		$	84,531,832
Issued in registered direct placement		3,480,000			6,089,476			—			—			4,200,000			23,687,955
Issued as bonus under incentive plan		460,715			426,251			50,000			259,690			10,430			61,010
Issued upon exercise of options and warrants		—			—			357,582			1,524,696			137,083			561,729

Ending balance		30,484,361			117,142,639			26,543,646			110,626,912			26,136,064			108,842,526

Treasury stock		(21,000	)		(23,630	)		(21,000	)		(23,630	)		(21,000	)		(23,630	)

Paid-in-capital — options and warrants					4,467,246						3,774,600						3,484,148
To be issued		9,185			45,925			9,185			45,925			9,185			45,925


DEFICIT
Beginning balance					(10,546,711	)					(13,482,986	)					(12,666,389	)
Cumulative effect adjustment					8,466,208						—						—
Net income (loss)					(7,701,161	)					2,936,275						(816,597	)

Ending balance					(9,781,664	)					(10,546,711	)					(13,482,986	)


TOTAL SHAREHOLDERS’ EQUITY				$	111,850,516					$	103,877,096					$	98,865,983

See accompanying notes.

F-7

NGAS Resources, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2009			2008			2007
OPERATING ACTIVITIES
Net income (loss)	$	(7,701,161	)	$	2,936,275		$	(816,597	)
Adjustments to reconcile net income to net cash provided by operating activities:
Incentive bonus paid in common shares		426,251			259,690			61,010
Options, warrants and deferred compensation		1,307,194			911,561			1,069,306
Depreciation, depletion and amortization		14,019,826			12,418,234			10,416,696
Bad debt expense		—			749,035			215,000
Impairment of oil and gas assets		—			—			964,000
Loss (gain) on sale of assets		(3,346,491	)		(14,104	)		54,304
Fair value gain on derivative financial instruments		(14,726	)		—			—
Accretion of debt discount		3,925,531			—			—
Deferred income taxes		(389,927	)		3,730,706			1,182,991
Changes in assets and liabilities:
Accounts receivable		3,172,862			(3,289,265	)		983,631
Prepaid expenses and other current assets		(93,631	)		(34,475	)		602,956
Other non-current assets		—			3,242,790			(608,519	)
Accounts payable		(6,774,802	)		5,712,283			(2,637,040	)
Accrued liabilities		263,688			(1,809,476	)		(852,151	)
Deferred compensation		(2,209,700	)		—			—
Customer drilling deposits		3,318,922			(594,851	)		(9,316,099	)
Other long-term liabilities		276,405			2,514,782			508,857

Net cash provided by operating activities		6,180,241			26,733,185			1,828,345


INVESTING ACTIVITIES
Proceeds from sale of assets		37,516,732			66,555			394,720
Purchase of property and equipment		(2,861,741	)		(504,329	)		(1,571,772	)
Change in bonds and deposits		15,203			(88,453	)		(1,750	)
Additions to oil and gas properties, net		(11,914,566	)		(56,349,317	)		(49,654,013	)


Net cash provided by (used in) investing activities		22,755,628			(56,875,544	)		(50,832,815	)


FINANCING ACTIVITIES
Decrease in loans to related parties		3,509			6,447			7,513
Proceeds from issuance of common shares		6,089,476			1,190,006			24,131,483
Payments of deferred financing costs		(422,719	)		(590,698	)		—
Proceeds from issuance of long-term debt		2,300,000			29,740,000			13,360,000
Payments of long-term debt		(33,555,384	)		(2,038,175	)		(109,825	)


Net cash provided by (used in) financing activities		(25,585,118	)		28,307,580			37,389,171


Change in cash		3,350,751			(1,834,779	)		(11,615,299	)

Cash, beginning of year		981,899			2,816,678			14,431,977


Cash, end of year	$	4,332,650		$	981,899		$	2,816,678


SUPPLEMENTAL DISCLOSURE
Interest paid	$	5,119,176		$	5,575,759		$	6,343,734
Income taxes paid		—			—			—

See accompanying notes.

F-8

NGAS Resources, Inc.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies

General. The accompanying consolidated financial statements of NGAS Resources, Inc. (NGAS) for each of the three years ended December 31, 2009 have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Although NGAS is organized under the laws of British Columbia, all of our oil and gas operations are conducted within the continental United States, and all amounts reported in the consolidated financial statements are stated in U.S. dollars.

Basis of Consolidation. The consolidated financial statements include the accounts of our direct and indirect wholly owned subsidiaries, NGAS Production Co. (NGAS Production), Sentra Corporation (Sentra) and NGAS Securities, Inc. (NGAS Securities). NGAS Production (formerly named Daugherty Petroleum, Inc.) conducts all our oil and gas drilling, production and gas gathering operations. Sentra owns and operates natural gas distribution facilities for two communities in Kentucky, and NGAS Securities provides marketing support services for private placement financings. The consolidated financial statements also reflect our interests in drilling partnerships sponsored by NGAS Production to participate in many of our drilling initiatives. NGAS Production maintains a combined interest as both general partner and an investor in the drilling partnerships ranging from 12.5% to 75%, with additional reversionary interests after certain distribution thresholds are reached. We account for those interests using the proportionate consolidation method, with all material inter-company accounts and transactions eliminated on consolidation. References in the consolidated financial statements to we, our or us include NGAS, NGAS Production, its subsidiaries and interests in drilling partnerships.

Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses. The most significant estimates pertain to proved oil and gas reserves and related cash flow estimates used in impairment tests of goodwill and other long-lived assets, estimates of future development, production and abandonment costs. The evaluations required for these estimates involve various uncertainties, and actual results could differ from the estimates.

Oil and Gas Properties.

• Proved Properties. We follow the successful efforts method of accounting for oil and gas producing activities. Under this method, costs for exploratory discoveries and development costs for proved properties are capitalized and amortized on a unit-of-production basis over the estimated reserve life of the properties. In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification) Topic (ASC) 360-10, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets, we evaluate our proved oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. If the evaluation indicates that undiscounted future net cash flows from estimated proved reserves of a property exceed its book value, the unamortized capital costs of the property would be reduced to its fair value.

• Exploratory Wells. We account for exploratory well costs under ASC 932-360-35, Extractive Industries-Oil and Gas—Property, Plant and Equipment—Subsequent Measurement, which provides for exploratory well costs to be initially capitalized but charged to expense unless the wells are determined to be successful within one year after completion of drilling. The one-year limitation may be exceeded only if reserves from an exploratory well are sufficient to justify its completion and sufficient progress has been made in assessing the economic and operating viability of the overall project. If an exploratory well does not meet both criteria, its capitalized costs must be expensed, net of any salvage value. Under ASC 932-235-50, annual disclosures are required about management’s evaluation of capitalized exploratory well costs, including disclosure of (i) net changes from period to period in the costs for wells that are pending the determination of proved reserves, (ii) the amount of any exploratory well costs that have been capitalized for more than one year after the completion of drilling and (iii) an aging of suspended exploratory well costs and the number of wells affected. See Note 3 — Oil and Gas Properties.

F-9

• Unproved Properties. Lease acquisition costs for unproved properties are capitalized and amortized based on a composite of factors, including past success, experience and average lease-term lives. Unamortized lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units-of-production basis.

• Other Properties and Equipment. Other properties and equipment include well equipment, gathering and processing facilities, office equipment and other fixed assets. These items are recorded at cost and depreciated using either the straight-line method based on expected life of the assets, ranging from 3 to 25 years, or the unit-of-production method over the estimated reserve life of the underlying properties.

Revenue Recognition. We recognize revenue on drilling contracts using the completed contract method of accounting for both financial reporting purposes and income tax purposes. This method is used because the typical contract is completed in three months or less, and our financial position and results of operations would not be significantly affected by using the percentage-of-completion method. A contract is considered complete when all remaining costs and risks are relatively insignificant. Oil and gas production revenue is recognized as production is extracted and sold. Other revenue is recognized at the time it is earned and we have a contractual right to receive it.

Regulated Activities.

• Sentra. Regulated operations of Sentra, our gas utility subsidiary, are subject to the provisions of ASC 980-605, Regulated Operations—Revenue Recognition, which requires covered entities to record regulatory assets and liabilities resulting from actions of regulators. Kentucky’s Public Service Commission regulates Sentra’s billing rates for natural gas distribution sales based on recovery of purchased gas costs. For the years ended December 31, 2009, 2008 and 2007, our gas transmission, compression and processing revenue includes gas utility sales from Sentra’s regulated operations aggregating $539,374, $565,727 and $365,951, respectively.

• NGAS Securities. NGAS Securities is a registered broker-dealer and member of the Financial Industry Regulatory Authority. Among other regulatory requirements, it is subject to the net capital provisions of Rule 15c3-1 under of the Securities Exchange Act of 1934 (Exchange Act). Because it does not hold customer funds or securities or owe money or securities to customers, NGAS Securities is required to maintain minimum net capital equal to the greater of $5,000 or 6.67% of its aggregate indebtedness. At December 31, 2009, NGAS Securities had net capital of $62,599 and aggregate indebtedness of $26,654.

Investments. Long-term investments in which we do not have significant influence are accounted for using the cost method. In the event of a permanent decline in value, an investment is written down to estimated realizable value, and any resulting loss is charged to earnings.

Deferred Financing Costs. Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. See Note 7 — Deferred Financing Costs.

Goodwill. In accordance with the authoritative guidance, goodwill is tested for impairment annually and more frequently if events or changes in circumstances indicate that the carrying amount of goodwill or other reporting unit exceeds its fair value. We test goodwill impairment utilizing a fair value approach at a reporting unit level, as discussed in Note 8.

Customer Drilling Deposits. Net proceeds received under NGAS Production’s drilling contracts with sponsored drilling partnerships are recorded as customer drilling deposits at the time of receipt. We recognize revenues from contract drilling operations on the completed contract method as the wells are drilled, rather than when funds are received. Customer drilling deposits represent unapplied payments for wells that were not yet drilled as of the balance sheet dates. See Note 9 — Customer Drilling Deposits.

Convertible Notes. We issued $37 million principal amount of 6% convertible notes in December 2005 with a five-year maturity and an initial conversion price of $14.34, which was reduced to $11.16 per share from weighted-average antidilution adjustments triggered by subsequent equity raises. See Note 11 — Capital Stock. Based on the December 2010 maturity of the notes, their entire carrying amount was reclassified as a current liability at December 31, 2009. See Note 10 — Long-Term Debt. After year end, we completed an exchange with the holders of these notes to extend the maturity of our convertible debt and create a flexible repayment structure with the potential for replacing part of the debt with equity at a premium to the stock price at the time of the exchange. See Note 20 — Subsequent Events.

F-10

Stock Options and Awards. We account for stock options and awards under the fair value recognition and measurement provisions of ASC 718, Compensation—Stock Compensation. See Note 11 — Capital Stock.

Deferred Compensation. Accruals for deferred compensation are recorded ratably based on estimated future payment dates and forfeiture rates for contingent payouts and benefits under our executive retention program. The program in initially included long-term incentive agreements with our executive officers and a key employee, providing for vesting of stock options and incentive awards after a five-year retention period that ended in February 2009. At that time, we provided new long-term incentive agreements to our executive officers and twelve key employees. The cash incentive awards will amount to one times the annual base salary and bonus of our executive officers, determined at the time of vesting, and will total up to $705,000 for key employees participating in the program. Awards for all participants will vest 40% after three years and 100% after five years or any earlier employment termination without cause following a change of control. See Note 11 — Capital Stock—Stock Options and Awards.

Deferred Income Taxes. We provide for income taxes using the asset and liability method. This requires that income taxes reflect the expected future tax consequences of temporary differences between the carrying amounts of assets or liabilities and their tax bases. Deferred income tax assets and liabilities are determined for each temporary difference based on the tax rates that are assumed to be in effect when the underlying items of income and expense are expected to be realized. See Note 12 — Income Taxes.

Fair Value of Derivative Financial Instruments. During 2009, we adopted ASC 815-40-15, Contracts in Entity’s Own Equity, which requires the embedded conversion feature of our 6% convertible notes to be bifurcated and treated as a derivative liability based on its fair value as a stand-alone instrument. The transition provisions of ASC 815-40-15 required cumulative effect adjustments as of January 1, 2009 to reflect the amounts that would have been recognized if derivative fair value accounting had been applied from the original issuance date of an equity-linked financial instrument through the implementation date of the revised guidance. Our fair value analysis of the notes reflected an initial derivative liability of $16,575,445 for the embedded conversion feature. From the note issuance date through the end of 2008, we would have recorded fair value gains on derivative financial instruments of $16,560,608, offset by non-cash interest expenses totaling $8,094,400 reflecting accretion of the debt discount under the effective interest method. The unaccreted debt discount of $8,466,208 was recorded a cumulative effect adjustment to retained deficit at January 1, 2009, resulting in an opening retained deficit of $2,080,503, as adjusted.

Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts to reflect losses that could result from failures counterparties to make payments on our receivables. When maintained, an allowance is based on factors including historical experience, aging and financial information. We recognized bad debt expenses aggregating $749,035 in 2008 and $215,000 in 2007 as reserves against past due receivables.

Reclassifications and Adjustments. Certain amounts included in the 2008 and 2007 consolidated financial statements have been reclassified to conform to the 2009 presentation.

Subsequent Events. Except as discussed in Note 20, there were no events or transactions through March 12, 2010, the issuance date of the consolidated financial statements, requiring recognition or disclosure.

Comprehensive Income and Loss. The accompanying consolidated financial statements do not include statements of comprehensive income (loss) since we had no items of comprehensive income or loss for the reported periods.

Note 2 — Recently Adopted Accounting Standards

ASU 2010-09. In February 2010, the FASB issued Accounting Standards Update (ASU) 2010-09, Amendments to Certain Recognition and Disclosure Requirements, amending its guidance on subsequent events under ASC 855 to remove the requirement for SEC filers to disclose the date through which events or transactions occurring after the balance sheet date have been evaluated for potential recognition or disclosure. The ASU will be effective for the first reporting period after its issuance. ASC 855 became effective in June 2009, and its adoption did not affect our practices for evaluating, recording or disclosing subsequent events.

ASU 2010-03. In January 2010, the FASB issued Accounting Standards Update (ASU) 2010-03, Extractive Industries—Oil and Gas (Topic 932) — Oil and Gas Reserve Estimation and Disclosures. The ASU aligns industry-specific accounting standards for oil and gas producing activities with revised oil and gas reserve estimation and disclosure rules adopted by the Securities and Exchange Commission (SEC) at the end of 2008 and subsequently consolidated in Subpart 1200 of Regulation S-K and amendments to Rule 4-10 of Regulation S-X under the Exchange Act. We adopted the revised standards and reserve reporting rules on December 31, 2009, as discussed in Note 21 and Note 22.

F-11

ASU 2009-05. In August 2009, the FASB issued ASU 2009-05, Fair Value Measurements and Disclosures — Measuring Liabilities at Fair Value, which provides clarification for the fair value measurement of liabilities, effective for the first reporting period after issuance. Our adoption of this update did not have a significant impact on our financial position, results of operations, cash flows or disclosures.

ASC 105. ASC 105, Generally Accepted Accounting Principles. was issued by the FASB in July 2009 to establish the Codification as the single source of authoritative nongovernmental GAAP, except for SEC rules and interpretive releases. Under ASC 105, the Codification became effective for reporting periods ended after September 15, 2009. The Codification did not change existing GAAP, and adoption of ASC 105 did not have any impact on our consolidated financial statements.

Note 3 — Oil and Gas Properties

Property Acquisitions and Divestitures.

• Sale of Appalachian Gas Gathering Assets. During the third quarter of 2009, we sold 485 miles of our Appalachian gas gathering facilities (Appalachian Gathering System) to Seminole Energy Services, LLC and its subsidiary (Seminole Energy) for $50 million, of which $14.5 million is payable in monthly installments through December 2011, together with interest at the rate of 8% per annum. See Note 5 — Note Receivable. As part of the transaction, we entered into various gas marketing and gas sales arrangements with Seminole Energy, enabling us to retain operating rights for the Appalachian Gathering System and firm capacity rights for daily delivery of 30,000 Mcf of controlled gas, ensuring long-term deliverability for our Appalachian production. Cash proceeds of $35.5 million from the sale and approximately $6.1 million from a contemporaneous equity raise were applied to debt reduction under our revolving credit facility. See Note 10 — Long-Term Debt and Note 11 — Capital Stock.

• Expansion of Leatherwood Position. In October 2009, we expanded our position in the Leatherwood field with the acquisition of a lease covering 10,300 gross (8,280 net) undeveloped acres in Leslie and Harlan Counties, Kentucky. The lease provides the mineral interest owner with participation rights for up to 50% of the working interest in wells drilled on the covered acreage and requires us to drill at least three horizontal wells by the end of March 2011, followed by a two-well annual drilling commitment.

• Chesapeake Farmout. In May 2009, we acquired a farmout for 56,000 gross (42,000 net) undeveloped acres contiguous to the Amvest portion of our Stone Mountain field in Letcher and Harlan Counties, Kentucky. The mineral interest owner and royalty interest owner each have participation rights for up to 25% of the working interests in our future wells on the acreage, and we have a minimum annual drilling commitment of four wells.

Capitalized Costs and DD&A. The following table presents the capitalized costs and accumulated depreciation, depletion and amortization (DD&A) for our oil and gas properties, gathering facilities and well equipment as of December 31, 2009 and 2008.


	As of December 31,
	2009			2008
Proved oil and gas properties	$	203,670,153		$	192,186,676
Unproved oil and gas properties		5,441,933			5,065,835
Gathering facilities and well equipment		15,411,788			67,326,445

		224,523,874			264,578,956
Accumulated DD&A		(42,334,195	)		(35,360,612	)

Net oil and gas properties and equipment	$	182,189,679		$	229,218,344

Exploratory Well Costs. The following tables show net changes in our capitalized exploratory well costs, together with the aging of these costs, for each reported period. As of December 31, 2009, exploratory wells costs for nine wells had been capitalized for more than one year after drilling. Six of the wells were drilled during 2008 in our Licking River project, where we have development rights and a 50% interest in constrained gathering infrastructure. We suspended this project pending completion of an operating plan for infrastructure development with the successor to the co-owner of the existing facilities. The remaining three wells were drilled during 2008 on the extreme eastern and western flanks of our New Albany shale project. While considered successful based on preliminary testing, they range from seven to twelve miles from our western Kentucky gathering system, and we elected to defer completion pending expansion of the system as additional wells are drilled on the acreage.

F-12


	2009		2008		2007
Beginning balance at January 1	$	2,669,407	$	—	$	964,000
Additions pending determination of proved reserves		—		2,669,407		—
Reclassifications to proved reserves		—		—		—
Charged to expense		—		—		(964,000	)

Ending balance at December 31	$	2,669,407	$	2,669,407	$	—

Exploratory costs capitalized for one year or less	$	—	$	2,669,407	$	—
Exploratory costs capitalized for more than one year		2,669,407		—		—

Balance at December 31	$	2,669,407	$	2,669,407	$	—

Note 4 — Other Property and Equipment

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


	As of December 31,
	2009			2008
Land	$	12,908		$	12,908
Building improvements		64,265			64,265
Machinery and equipment		5,866,853			3,333,981
Office furniture and fixtures		175,862			175,862
Computer and office equipment		688,261			670,349
Vehicles		1,810,064			1,951,279

		8,618,213			6,208,644
Accumulated depreciation		(3,505,120	)		(2,922,719	)

Net other property and equipment	$	5,113,093		$	3,285,925

Note 5 — Note Receivable

As part of the consideration for the sale of our Appalachian Gathering System during the third quarter of 2009, we received a promissory note issued by Seminole Energy in the original principal amount of $14.5 million. See Note 3 — Oil and Gas Properties. The note is payable in equal monthly installments through December 2011, with interest at 8% per annum. Performance of the note is secured by a second mortgage on Seminole Energy’s interest in the Appalachian Gathering System. We have assigned the note as part of the collateral package under our revolving credit facility and have agreed to apply note payments to debt reduction under the facility. See Note 10 — Long-Term Debt.

Note 6 — Loans to Related Parties

We extended loans to several of our officers prior to 2003 and to one of our shareholders in 2004. The shareholder loan bears interest at 5% per annum and had an outstanding balance of $75,679 at December 31, 2009 and $79,188 at December 31, 2008. The loan is collateralized by the shareholder’s interests in our drilling partnerships and is repayable from partnership distributions. The loans receivable from officers totaled $171,429 at December 31, 2009 and 2008. These loans are non-interest bearing and unsecured.

Note 7 — Deferred Financing Costs

Financing costs for our convertible notes and secured credit facility are initially capitalized and amortized at rates based on the terms of the underlying debt instruments. See Note 10 — Long-Term Debt. Upon conversion of convertible notes, the principal amount converted is added to equity, net of a proportionate amount of the original financing costs. Unamortized deferred financing costs for our convertible notes and credit facility aggregated $1,235,705 at December 31, 2009 and $1,689,580 at December 31, 2008, net of accumulated amortization.

Note 8 — Goodwill

Goodwill of $1,789,564 was recorded in our 1993 acquisition of NGAS Production and was amortized on a straight-line, ten-year basis until 2002, when we adopted authoritative guidance for evaluating goodwill annually and whenever potential impairment exists under a fair value approach at the reporting unit level. With no impairment under our initial and subsequent analyses, unamortized goodwill has remained at $313,177.

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Note 9 — Customer Drilling Deposits

Prepayments under drilling contracts with sponsored partnerships are recorded as customer drilling deposits upon receipt. Contract drilling revenues are recognized on the completed contract method as wells are drilled, rather than when funds are received. Customer drilling deposits of $5,581,877 at December 31, 2009 and $2,262,955 at December 31, 2008 represent unapplied prepayments for wells that were not yet drilled as of the balance sheet dates.

Note 10 — Long-Term Debt

Convertible Notes. At December 31, 2009, we had $37 million principal amount of 6% convertible notes outstanding, with a stated maturity on December 15, 2010. Upon any event of default under the notes or any change of control, holders could require us to redeem the notes at specified premiums above their face amount. Notes that were neither redeemed nor converted prior to maturity were repayable in cash or common shares, valued at 92.5% of their market price and subject to various volume limitations. During 2009, we adopted revised guidance for treating the embedded conversion feature of the notes as a derivative liability, resulting in an unaccreted debt discount of $4,555,513 at December 31, 2009, as discussed in Note 1. Based on the stated maturity date of the notes, their entire carrying amount, net of the unaccreted debt discount, was reclassified at the end of 2009 as a current liability. We completed a restructuring of our convertible debt in January 2010. See Note 20 — Subsequent Events.

Credit Facility. We have a revolving credit facility maintained by NGAS Production under a credit agreement with KeyBank National Association, as administrative agent. The facility provides for loans and letters of credit in an aggregate amount up to $125 million, with a scheduled maturity in September 2011. Credit availability under the facility is subject to borrowing base limits, as determined semi-annually by the lenders. Interest is payable at fluctuating rates ranging from the agent’s prime rate to 2.25% above that rate, depending on borrowing base utilization. We are also responsible for commitment fees ranging from 0.375% to 0.5% of the unused borrowing base. The facility is guaranteed by NGAS and is secured by liens on our oil and gas properties.

As of December 31, 2009, we had outstanding borrowings of $38.5 million under the facility, with a borrowing base of $55 million. This reflects debt reductions totaling $41.5 million from proceeds of our Appalachian Gathering System sale and related equity raise in the third quarter of 2009, as well as a borrowing base reduction of $25 million from lower commodity prices and the release of our Appalachian Gathering System assets from the collateral package. See Note 3 — Oil and Gas Properties. Further borrowing base reductions will be implemented under a credit agreement amendment entered in connection with the restructuring of our convertible debt during the first quarter of 2010. See Note 20 — Subsequent Events.

Installment Loan. In June 2009, NGAS Production obtained a $2.3 million loan from Central Bank & Trust Co. to finance the balance of its commitment under an airplane purchase contract entered in 2005. The loan bears interest at 5.875% per annum and is repayable in monthly installments of $16,428 over a three-year term, with the balance due at maturity. The loan is secured by a lien on the airplane and had an outstanding balance of $2,268,615 at December 31, 2009.

Acquisition Debt. We issued a $854,818 note in 1986 to finance our acquisition of mineral claims in Alaska. The note is repayable $2,000 per month without interest and was $270,818 at December 31, 2009.

Total Long-Term Debt and Maturities. The following tables summarize our total long-term debt at December 31, 2009 and 2008 and the principal payments due each year through 2014 and thereafter.


	At December 31,
	2009			2008
Principal Amount Outstanding
Total long-term debt (including current portion)	$	73,483,920		$	108,604,448
Less current portion		32,534,084	⁽¹⁾		24,000

Total long-term debt	$	40,949,836		$	108,580,448


Maturities of Debt
2010	$	32,534,084	⁽¹⁾
2011		38,593,557
2012		2,157,461
2013		24,000
2014 and thereafter		174,818


(1)		Excludes an allocation of $4,555,513 for the unaccreted debt discount on $37 million of 6% convertible notes due December 2010, which were reclassified as current liabilities at December 31, 2009. See Note 20 — Subsequent Events.

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Note 11 — Capital Stock

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

Common Shares. On August 13, 2009, we completed a registered direct placement of 3.48 million units under a shelf registration statement at $1.90 per unit. Each unit consisted of one share of our common stock and a warrant to buy 0.5 common share, as described below under “Common Stock Purchase Warrants.” The following table reflects the 2009 equity raise and other transactions involving our common stock during the reported periods.


	Shares		Amount
Common Shares Issued
Balance, December 31, 2007		26,136,064	$	108,842,526
Issued to employees as incentive bonus		50,000		259,690
Issued upon exercise of stock options		357,582		1,524,696

Balance, December 31, 2008		26,543,646		110,626,912
Issued in registered direct placement		3,480,000		6,089,476
Issued as stock awards under incentive plan		460,715		426,251

Balance, December 31, 2009		30,484,361	$	117,142,639

Paid In Capital — Options and Warrants
Balance, December 31, 2007			$	3,484,148
Recognized				625,142
Exercised				(334,690	)

Balance, December 31, 2008				3,774,600
Recognized				692,646

Balance, December 31, 2009			$	4,467,246

Common Shares to be Issued
Balance, December 31, 2009 and 2008		9,185	$	45,925


(1)		Reflects accretion of the equity components allocated under prior accounting treatment of our 6% convertible notes and related warrants issued in 2005.

(2)		Reflects our adoption of ASC 815-40-15, Contracts in Entity’s Own Equity, effective as of January 1, 2009. See Note 1 — Summary of Significant Accounting Policies.

Stock Options and Awards. We maintain equity incentive plans adopted in 2001 and 2003 for the benefit of our directors, officers, employees and certain consultants. The 2001 plan provides for the grant of options to purchase up to 3 million common shares, and the 2003 plan provides for the issuance of up to 4 million common shares as stock awards or upon exercise of stock options. Awards may be subject to restrictions or vesting requirements, and option grants must be at prevailing market prices. Stock awards aggregated 460,715 shares during 2009 and 50,000 shares during 2008. Transactions in stock options during those periods are shown in the following table.


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

Balance, December 31, 2008		4,613,668			1,413,668			3.95
Vested		—			1,225,000			4.69
Expired		(740,000	)		(740,000	)		4.06

Balance, December 31, 2009		3,873,668			1,898,668			3.92

F-15

At December 31, 2009, the exercise prices of options outstanding under our equity plans ranged from $1.51 to $7.64 per share, with a weighted average remaining contractual life of 2.81 years. The following table provides additional information on the terms of stock options outstanding at December 31, 2009.


Options Outstanding							Options Exercisable
			Weighted		Weighted				Weighted
Exercise			Average		Average				Average
Price			Remaining		Exercise				Exercise
or Range	Number		Life (years)		Price		Number		Price
$ 1.51		1,650,000		5.36	$	1.51		—	$	—
4.03		800,000		0.15		4.03		800,000		4.03
6.02 — 7.64		1,423,668		1.36		6.66		1,098,668		6.70

		3,873,668						1,898,668

We use the Black-Scholes pricing model to determine the fair value of each stock option at the grant date, and we recognize the compensation cost ratably over the vesting period. For the periods presented in the consolidated financial statements, the fair value estimates for option grant assumed a risk free interest rate ranging from 0.03% to 6%, no dividend yield, a theoretical volatility ranging from 0.30 to 0.85 and an expected life ranging from six months to six years based on the vesting provisions of the options. This resulted in non-cash charges for options and warrants of $692,646 in 2009 and $625,142 in 2008.

Common Stock Purchase Warrants. As part of our registered direct equity placement on August 13, 2009, we issued warrants to purchase 1.74 million shares of our common stock at $2.35 per share, subject to adjustment for certain dilutive issuances. The warrants are exercisable during a four-year term ending on February 13, 2014.

Note 12 — Income Taxes

Components of Income Tax Expense. The following table sets forth the components of income tax expense (benefit) for each of the years presented in the consolidated financial statements.


	Year Ended December 31,
	2009			2008		2007
Current	$	—		$	—	$	—
Deferred		(341,394	)		3,800,797		1,239,424

Total income tax expense (benefit)	$	(341,394	)	$	3,800,797	$	1,239,424

Reconciliation of Tax Rates. The following table sets forth a reconciliation between prescribed tax rates and the effective tax rate for our income tax expense in each of the years presented in the consolidated financial statements.


	Year Ended December 31,
	2009			2008		2007
Income tax at statutory combined basic income tax rates	$	(3,217,022	)	$	2,694,829	$	169,131
Increase (decrease) in income tax resulting from:
Non-recognition of tax benefit from parent company net losses		2,859,545			1,078,055		1,031,288
Non-deductible expenses		16,083			27,913		18,286
Difference in tax rates between Canada and United States		—			—		20,719

Total income tax expense (benefit)	$	(341,394	)	$	3,800,797	$	1,239,424

Components of Deferred Income Tax Liabilities. The following table sets forth the components of our deferred income tax liabilities as of the end of each of the years presented in the consolidated financial statements.

F-16


	As of December 31,
	2009			2008			2007
Net operating loss carryforward and investment tax credit	$	11,884,758		$	19,025,393		$	10,860,013
Gold and silver properties		2,522,094			2,522,094			2,522,094
Oil and gas properties		(19,441,150	)		(23,586,375	)		(15,654,201	)
Property and equipment		(597,664	)		(625,351	)		(634,988	)
Less valuation allowance		(6,927,587	)		(10,285,237	)		(6,311,688	)

Deferred tax liabilities	$	(12,559,549	)	$	(12,949,476	)	$	(9,218,770	)

Net Operating Loss Carryforwards. As of December 31, 2009, we had net operating loss carryforwards of $20.3 million, including approximately $6.3 million at the parent company level. We have provided a valuation allowance in the full amount of the parent company loss carryforwards. The following table summarizes those net operating loss carryforwards by year of expiry.


Year of Expiry
2026	$	976,000
2027		7,901,042
2028		11,389,193

Total net operating loss carryforwards	$	20,266,235

Uncertain Tax Positions. We apply the guidance and procedures prescribed under ASC 740, Income Taxes, for recognizing and measuring amount of any uncertain tax position, as well as the guidance under this standard relating to derecognition, classification, transition and increased disclosure of uncertain tax positions. We recognized no liability for unrecognized tax benefits resulting from our application of this guidance during the periods presented in the consolidated financial statements.

Note 13 — Income (Loss) Per Share

The following table shows the computation of basic and diluted earnings (loss) per share (EPS) for each of the years presented in the consolidated financial statements in accordance with ASC260, Earnings per Share.


	Year Ended December 31,
Numerator:	2009			2008		2007
Net income (loss) as reported for basic EPS	$	(7,701,161	)	$	2,936,275	$	(816,597	)
Adjustments for diluted EPS		—			—		—

Net income (loss) for diluted EPS	$	(7,701,161	)	$	2,936,275	$	(816,597	)

Denominator:
Weighted average shares for basic EPS		28,256,253			26,409,275		22,240,429
Effect of dilutive securities:
Stock options		—			501,367		—
Warrants		—			—		—

Adjusted weighted average shares for dilutive EPS		28,256,253			26,910,642		22,240,429

Basic EPS	$	(0.27	)	$	0.11	$	(0.04	)

Diluted EPS	$	(0.27	)	$	0.11	$	(0.04	)

Note 14 — Employee Benefit Plan

We maintain a salary deferral plan under section 401(k) of the Internal Revenue Code. The plan allows all eligible employees to defer up to 15% of their annual compensation through contributions to the plan, with matching contributions by NGAS Production up to 3% of the participating employees’ compensation, plus half of their plan contributions between 3% and 5% of annual compensation. The deferrals accumulate on a tax deferred basis until a participating employee withdraws the funds allowable based on a vesting schedule. Our matching contributions to the plan aggregated $180,814 in 2009, $195,145 in 2008 and $172,075 in 2007.

F-17

Note 15 — Related Party Transactions

Drilling Partnerships. NGAS Production invests in sponsored drilling partnerships on substantially the same terms as unaffiliated investors, contributing capital in proportion to its initial partnership interest, which range from 12.5% to 75%, with specified increases after certain distribution thresholds are reached. Each partnership enters into drilling and operating contracts with NGAS Production or any third-party operator for all wells to be drilled for the partnership. The portion of the profit on drilling contracts attributable to NGAS Production’s partnership interest is eliminated on consolidation. The following table lists the total revenues recognized from the performance of these contracts with sponsored drilling partnerships for each of the years presented.


	Contract Drilling
Year	Revenues
2009	$	24,279,345
2008		35,553,956
2007		34,334,829

Office Lease. The building in Lexington, Kentucky that houses our principal and administrative offices was acquired during 2006 by a company formed for that purpose by our executive officers and a key employee. At the time of the sale, our lease covered 12,109 square feet at a monthly rent of $18,389 through expiration in February 2008. Following the sale of the building, we entered into a lease modification for an additional 1,743 square feet at a monthly rent of $2,542. In November 2007, we entered into lease renewals for a five-year term at monthly rents totaling $20,398, subject to annual escalations on the same terms as our prior lease. The terms of the initial lease modification and subsequent lease renewals were negotiated on our behalf by one of our independent directors appointed for that purpose by our board. The negotiations were conducted at arms’ length with the management company for the building, and the terms reflect prevailing rental rates with other tenants in our building and comparable office buildings in our locale.

Note 16 — Financial Instruments

Credit Risk. We maintain bank accounts in excess of FDIC insured limits, and we grant credit to our customers in the normal course of business. We perform ongoing credit evaluations of customers’ financial condition and generally require no collateral.

Fair Value of Financial Instruments. The carrying values of cash, accounts receivable, other receivables, accounts payable, accrued liabilities and customer drilling deposits approximate fair value due to their short-term maturity. Bonds and deposits, loans receivable and payable and other long-term debt payable approximate fair value since they bear interest at variable, market-based rates. The following table sets forth the financial instruments with a carrying value at December 31, 2009 different from their estimated fair value, based upon discounted future cash flows using discount rates reflecting market conditions for similar instruments.


	Carrying		Fair
Financial Instrument:	Value		Value
Non-interest bearing long-term debt	$	270,818	$	195,995
Loans to related parties		247,108		202,904

Note 17 — Segment Information

We have a single reportable operating segment for our oil and gas business based on the integrated way we are organized by management in making operating decisions and assessing performance. Although our financial reporting reflects our separate revenue streams from drilling, production and gas gathering activities, along with the direct expenses for each component, we do not consider the components as discreet operating segments under ASC 280, Segment Reporting.

Note 18 — Commitments

Operating Lease Obligations. We incurred operating lease expenses of $2,670,002 in 2009 and $2,583,417 in 2008. As of December 31, 2009, we had future obligations under operating leases as follows:

F-18


Future Lease Obligations
2010	$	2,339,107
2011		2,083,836
2012		846,493
2013		73,283

Total	$	5,342,719

Gas Gathering and Sales Commitments. We have various long-term commitments under gas gathering and sales agreements entered with Seminole Energy in connection with our sale of the Appalachian Gathering System during the third quarter of 2009. See Note 3 — Oil and Gas Properties. These include (i) base monthly gathering fees of $850,000, with annual escalations at the rate of 1.5%, (ii) base monthly operating fees of $175,000, plus $0.20 per Mcf of purchased gas, and (iii) monthly capital fees in amounts intended to yield a 20% internal rate of return for all capital expenditures on system by Seminole Energy. These agreements have an initial term of fifteen years with extension rights.

Note 19 — Asset Retirement Obligations

We have asset retirement obligations primarily for the future abandonment of oil and gas wells, and we maintain reserve accounts for part of these obligations under our operating agreements with sponsored drilling partnerships. We account for these obligations under ASC 410-20, Asset Retirement and Environmental Obligations, which requires the fair value of an asset retirement obligation to be recognized in the period when it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of the underlying long-lived asset. ASC 410-20 also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation is generally determined on a units-of-production basis over the life of the asset, while the accretion escalates over the life of the asset, typically as production declines. The amounts recognized are based on numerous estimates and assumptions, including recoverable quantities of oil and gas, future retirement and site reclamation costs, inflation rates and credit-adjusted risk-free interest rates. The following table shows the changes in our asset retirement obligations during the years presented in the consolidated financial statements.


	Year Ended December 31,
	2009			2008			2007
Asset retirement obligations, beginning of the year	$	1,094,700		$	947,100		$	820,400
Liabilities incurred during the year		258,986			152,449			182,594
Liabilities settled during the year		(88,302	)		(82,982	)		(90,803	)
Accretion expense recognized during the year		97,416			78,133			34,909

Asset retirement obligations, end of the year	$	1,362,800		$	1,094,700		$	947,100

Note 20 — Subsequent Events

Convertible Note Exchange. In January 2010, we retired $37 million of our 6% convertible notes due December 15, 2010 (retired notes) in exchange for an aggregate of $28.7 million in new amortizing convertible notes due May 1, 2012 (exchange notes), together with 3,037,151 shares of our common stock, five-year warrants to purchase 1,285,038 common shares (exchange warrants) and cash payments totaling approximately $2.7 million. The transaction was covered by separate exchange agreements with the holders of the retired notes, which had been issued in December 2005 and reclassified as a current liability at the end of 2009 based on their stated maturity date. See Note 10 — Long-Term Debt. The exchange notes bear interest at 6% per annum, payable in cash at the beginning of each calendar quarter. They are convertible at the option of the holders into our common stock at $2.18 per share, and the exchange warrants are exercisable at $2.37 per share, subject in each case to certain volume limitations and adjustments for certain fundamental change transactions or share recapitalizations.

F-19

During the period from June 1, 2010 through the maturity date, we will be obligated to make 24 equal monthly principal amortization payments on outstanding exchange notes, together with accrued and unpaid interest. Subject to certain volume limitations and other conditions, including the right of each holder to defer any installment payment to maturity, we may elect to pay all or part of each principal installment in common stock, valued at the lesser of $2.18 per share or 95% of the 10-day volume-weighted average price of the common stock ending on the second business day prior to the installment date. Any installment payment or partial payment in common shares is subject to certain true-up adjustments. In addition, the exchange notes and the exchange warrants include blockers that prohibit us from issuing any shares to a holder that would increase its beneficial ownership of our stock above 4.99% of the outstanding common shares. These provisions could limit our ability to make amortizing payments on the exchange notes in common stock.

The total shares issuable under the exchange notes upon conversion, amortization or otherwise (conversion shares), together with the common shares issued in the exchange (exchange shares) and shares issuable upon exercise of the exchange warrants (warrant shares) substantially exceed 20% of our common shares outstanding prior to the transaction. To ensure compliance with our Nasdaq listing standards, the exchange documents limit the total conversion shares and warrant shares that we may issue prior to shareholder approval of the transaction to 19.99% of our shares outstanding on the date of the exchange agreements, net of the exchange shares (share ceiling). The exchange agreements require us to use our best efforts to obtain shareholder approval at the next annual meeting for all share issuances under the exchange documents. If approved by our shareholders, this will have the effect of eliminating the share ceiling.

The exchange notes are subject to customary non-financial covenants and events of default. The covenants include restrictions on share repurchases or distributions without the consent of a majority-in-interest of the note holders and limitations on any future issuances of certain types of preferred stock or variable interest securities. Subject to customary grace and cure periods in certain cases, events of default include any delisting of our common stock, any failure to pay interest or principal installments or to honor conversion or other material obligations under the exchange notes or certain other indebtedness, the rendering of unbonded judgments above specified limits and certain events of bankruptcy or insolvency. The exchange notes are redeemable in cash at the option of the holders upon any event of default at 125% of their principal amount or any change of control at 110% of their principal amount. Upon a change of control, holders will also have the right to convert their exchange notes and receive an additional number of common shares based on the price of our stock at that time or the consideration that would be received by the holder for the underlying conversion shares in the change of control transaction.

Any exchange notes that are neither redeemed nor converted prior to maturity will be repayable in cash plus accrued and unpaid interest. In accordance with the accounting guidelines for convertible debt, we expect to record the initial carrying amount of the exchange notes net of allocations for the fair value of their conversion feature on the date of the exchange agreements and the initial fair value of the exchange warrants. The resulting debt discount will be amortized to interest expense though the conversion or repayment dates of exchange notes and the exercise or expiration of the exchange warrants.

Amendment to Credit Agreement. On January 11, 2010, we entered into an amendment to the credit agreement maintained by NGAS Production with KeyBank National Association, as administrative agent for the lenders. See Note 10 — Long-Term Debt. The amendment permitted us to consummate the exchange transaction, subject to certain non-financial covenants and borrowing base modifications. These include restrictions on upstream dividends from NGAS Production for any principal amortization payments on the exchange notes that would cause outstanding borrowings under the facility to exceed 80% of the prevailing borrowing base. The amendment also provides for monthly reductions of $1 million to the borrowing base from February 2010 until the next semi-annual redetermination scheduled for April 2010. Under the terms of the amendment, the borrowing base will be further reduced by $2.7 million, representing an upstream dividend used for repurchasing retired notes in the exchange transaction, unless recontributed to NGAS Production for debt reduction under the credit facility by June 1, 2010.

F-20

Note 21 — Supplementary Information on Oil and Gas Development and Producing Activities

General. This Note provides audited information on our oil and gas development and producing activities in accordance with ASC 932-235, Extractive Activities—Oil and Gas — Notes to Financial Statements, and Items 1204 though 1208 of Regulation S-K under the Exchange Act.

Results of Operations from Oil and Gas Producing Activities. The following table shows the results of operations from our oil and gas producing activities during the years presented in the consolidated financial statements. Results of operations from these activities are determined using historical revenues, production costs (including production related taxes) and depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense are excluded from the reported operating results.


	Year Ended December 31,
Operating results:	2009			2008			2007
Revenues	$	26,586,422		$	38,522,474		$	28,148,689
Production costs		(11,357,397	)		(12,600,897	)		(7,648,558	)
DD&A		(10,998,965	)		(9,252,942	)		(7,676,617	)
Income taxes (allocated on percent of gross profits)		(346,364	)		(2,162,500	)		(815,435	)

Results of operations for producing activities	$	3,883,696		$	14,506,135		$	12,008,079

Capitalized Costs for Oil and Gas Producing Activities. For each of the years presented in the consolidated financial statements, the following table sets forth the components of capitalized costs for our oil and gas producing activities, all of which are conducted within the continental United States.


	As of December 31,
Capitalized costs:	2009			2008			2007
Proved properties	$	203,670,153		$	192,186,676		$	148,981,923
Unproved properties		5,441,933			5,065,835			3,876,721
Gathering facilities and well equipment		15,411,788			67,326,445			55,370,995

		224,523,874			264,578,956			208,229,639
Accumulated DD&A		(42,334,195	)		(35,360,612	)		(24,405,937	)

Total	$	182,189,679		$	229,218,344		$	183,823,702

Costs Incurred in Oil and Gas Acquisition and Development Activities. The following table lists the costs we incurred in oil and gas acquisition and development activities for the years presented in the consolidated financial statements.


	Year Ended December 31,
Property acquisition and development costs:	2009		2008		2007
Unproved properties	$	221,183	$	1,189,114	$	1,405,603
Proved properties		10,060,741		39,970,220		35,185,951
Development costs		1,632,642		15,189,983		13,062,459

Total	$	11,914,566	$	56,349,317	$	49,654,013

Note 22 — Supplementary Oil and Gas Reserve Information — Unaudited

General. This Note provides unaudited information on our estimated proved oil and gas reserves and the present value of net cash flows from those reserves as of the end of each year presented in the consolidated financial statements. The reserves estimates for each period were prepared by Wright & Company, Inc., independent petroleum engineers meeting the standards of Society of Petroleum Engineers for estimating and auditing reserves. The estimates as of December 31, 2009 were prepared in accordance with ASU 2010-03 and Subpart 1200 of Regulation S-K under the Exchange Act (collectively, current reserve rules). The current reserve rules went into effect at the end of 2009 and are intended to modernize reserve reporting standards to reflect current industry practices and technologies. Reserve estimates as of December 31, 2008 and 2007 were prepared in accordance with SEC reserve reporting rules in effect prior to the current reserve rules (prior reserve rules).

F-21

Under the current reserve rules, proved reserves are generally defined as quantities of oil and gas that can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and governmental regulations. The reasonable certainty standard must be based on analysis of geoscience and engineering data that provides a high degree of confidence for deterministic estimates or at least a 90% probability that EURs will meet or exceed estimates based on probabilistic methods. Economic producibility for estimates under the current reserve rules is determined using the unweighted average of the first-of-the-month spot prices for each commodity category during the twelve months preceding the date of the estimate, except for future production to be sold at contractually determined prices. Under the prior reserve rules, economic producibility was based on commodity prices as of the date of the estimate. In all cases, costs are determined as of the date the estimate, and both prices and costs are held constant over the estimated life of the reserves. Commodity prices used in the estimates of our proved reserves are shown in the following table. All prices are adjusted for energy content and basis differentials.


	Average		At December 31,
Commodity prices for reserve estimates:	2009		2008		2007
Natural gas (Mcf)	$	4.25	$	5.51	$	7.39
Crude oil (Bbl)		61.18		40.00		87.98
Natural gas liquids (Bbl)		14.58		6.46		N/A

Estimated Oil and Gas Reserve Quantities. The following table summarizes our estimated quantities of proved developed and undeveloped reserves as of December 31, 2009, using the twelve-month average pricing model under the current reserve rules, and historical reserve estimates as of December 31, 2008 and 2007, using prices as of the date of the estimates in accordance with the prior reserve rules. Proved developed reserves are generally defined under the current reserve rules as the estimated amounts of oil and gas that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are estimated volumes that are expected with reasonable certainty to be recovered from new wells on undrilled acreage within a reasonable time horizon, generally limited to five years from the date of the estimate, based on reliable technology that has demonstrated by field testing to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In accordance with the current reserve rules, historical reserve estimates at December 31, 2008 and 2007 were not restated. All reserves are located within the continental United States.


	As of December 31,
Proved Reserves:	2009		2008		2007
Natural gas (Mmcf)
Proved developed		38,177		44,817		45,012
Proved undeveloped		19,984		16,314		57,153

Total natural gas		58,161		61,131		102,165
Natural gas liquids (Mbbl)
Proved developed		1,391		1,500		—
Proved undeveloped		1,262		697		—

Total natural gas liquids		2,653		2,197		—

Crude oil (Mbbl)
Proved developed		709		602		500
Proved undeveloped		4		—		—

Total crude oil		713		602		500

Total natural gas equivalents (Mmcfe)⁽¹⁾		78,357		77,922		105,162


⁽¹⁾		Crude oil and NGL are converted to equivalent natural gas volumes at a 6:1 ratio.

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Changes in Estimated Reserves. The following table summarizes changes in net proved reserves for each of the years presented in the consolidated financial statements.


	Natural Gas (Mmcf)									Crude Oil and NGL (Mbbls)
	2009			2008			2007			2009			2008			2007
Proved developed and undeveloped reserves:
Beginning of year		61,131			102,165			98,205			2,798			500			453
Purchase of reserves in place		24			164			82			2			2			—
Extensions, discoveries and other additions		13,427			9,994			23,290			998			400			14
Transfers/sales of reserves in place		(13	)		(45	)		(3,801	)		(7	)		—			—
Revision to previous estimates		(13,087	)		(48,059	)		(12,660	)		(261	)		2,046			91
Production		(3,321	)		(3,088	)		(2,951	)		(164	)		(150	)		(58	)

End of year		58,161			61,131			102,165			3,366			2,798			500

Proved developed reserves		38,177			44,817			45,012			2,100			2,101			500

As of December 31, 2009, our proved undeveloped (PUD) reserves of 27.6 Bcfe represented 35% of our total proved reserves. None of our 2009 year-end PUDs have been included in our reported reserves for more than five years. Based on modifications adopted under the current reserve rules for unconventional resources supported by reliable technology, we added 15.9 Bcfe in new horizontal PUD locations. We also converted 0.03 Bcfe in prior year-end PUDs and 19.4 Bcfe in unproved reserves into proved developed reserves during 2009. These additions were partially offset by negative revisions of 6.7 Bcfe to our proved developed reserves from lower 2009 average prices. Estimates of our proved undeveloped reserves as of December 31, 2009 include locations that would generate positive future net revenue based on the constant prices and costs determined under the current reserve rules but would have negative present value when discounted at 10% per year under the standardized measure. These locations have been included based on our business plan for their development, along with all other PUD locations, within the next five years.

The reserve additions at year-end 2008 resulted primarily from our transition to horizontal drilling in our Leatherwood field, which added 8.3 Bcfe to our proved developed reserves. However, our PUD reserves were reduced by approximately 37 Bcfe or 64% from the prior year’s estimates, including a reduction of 16.2 Bcfe in Leatherwood. The reduction in these reserves resulted primarily from the loss of previously booked vertical PUD locations that were no longer economic based on 2008 year-end commodity prices and drilling costs. Based on the limited production history for these horizontal wells and definitional restrictions for unconventional shale plays under the prior rules, we were only able to book a total of 14 horizontal PUD locations at the end of 2008, all in Leatherwood, based on restrictions the current reserve reporting rules.

The performance related revisions to our estimated reserves at the end of 2008 also reflect our first year of NGL extraction from our Appalachian natural gas production, which was undertaken in response to a FERC tariff limiting the upward range of energy content for transported natural gas to 1.1 Dth per Mcf. To comply with the tariff, we constructed a processing plant during 2007 with a joint venture partner in Rogersville, Tennessee to extract NGL from our Appalachian gas production delivered through our gathering system. The plant was brought on line in January 2008, ensuring our compliance with the FERC tariff. Prior to 2008, we had limited NGL sales, and reserves from estimated future NGL production were included in our natural gas reserves for prior periods. At year-end 2008, the positive performance revisions of our estimated oil and NGL reserves, amounting to 2,046 Mbbls, was attributable entirely to NGL processing, which reduced our estimated natural gas reserves at year end.

At the end of 2007, we added 23.3 Bcfe to our proved reserves from 82.15 net wells drilled during the year. The reserve additions were partially offset by approximately 5 Bcf from our election to terminate a farmout covering all but 25% of our interest in the CDX—Arkoma field and downward reserve revisions for our interests in the Leatherwood field, where our EURs were reduced by 27% based on year-end production rates. While an upgrade to the main suction line for the field was installed during 2007 to alleviate higher line pressures and allow production at previously projected rates, we were not able to lower field operating pressures to match those rates as new wells were turned on line during the year. The downward reserve revisions at the end of 2007 were partially offset by positive adjustments from higher year-end commodity prices.

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Standardized Measure of Discounted Future Net Cash Flows. The following table presents the standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves as of the end of each of the years presented in the consolidated financial statements. Estimates at December 31, 2009 reflect an unweighted 12-month average of the first-of-the-month reference prices for each commodity. Estimates at December 31, 2008 and 2007 reflect commodity prices as of the date of the estimate. In all cases, prices were held constant over the estimated life of the reserves, except for future production to be sold at contractually determined prices. The estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on cost levels as of the date of the estimates. Future income taxes were based on year-end statutory rates, adjusted for any operating loss carryforwards and tax credits. The future net cash flows were reduced to present value by applying a 10% discount rate prescribed under both the current and prior reserve rules. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of oil and gas properties.

(In thousands)


	Year Ended December 31,
	2009			2008			2007
Future cash inflows⁽¹⁾	$	215,771		$	374,832		$	798,769
Future development costs		(39,687	)		(39,097	)		(165,984	)
Future production costs		(61,876	)		(121,047	)		(197,730	)
Future income tax expenses		(26,001	)		(53,233	)		(117,699	)

Undiscounted future net cash flows		88,207			161,455			317,356
10% annual discount for estimated timing of cash flows		(59,441	)		(93,892	)		(214,574	)

Standardized measure of discounted future net cash flows	$	28,766		$	67,563		$	102,782


(1)		Reflects the twelve-month average of the first-day-of-the-month reference prices for 2009 and the year-end reference prices for prior years.

Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of our proved oil and gas reserves after income taxes for each of the years presented in the consolidated financial statements. Sales of oil and gas, net of production costs, reflect historical pre-tax results. Extensions and discoveries, purchases of reserves in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after-tax basis.

(In thousands)


	Year Ended December 31,
	2009			2008			2007
Balance, beginning of year	$	67,563		$	102,782		$	81,333
Increase (decrease) due to current year operations:
Sales and transfers of oil and gas, net of related costs		(15,229	)		(25,922	)		(20,500	)
Extensions, discoveries and improved recovery, less related costs		1,903			12,071			64,083
Purchase of reserves in place		180			2,667			98
Transfer/sales of reserves in place		(132	)		—			—
Increase (decrease) due to changes in standardized variables:
Net changes in prices and production costs		(27,095	)		(27,272	)		38,984
Revisions of previous quantity estimates		1,296			(24,060	)		(17,138	)
Accretion of discount		6,756			10,278			8,133
Net change in future income taxes		(7,115	)		17,879			(55,005	)
Production rates (timing) and other		639			(860	)		2,794

Net increase (decrease)		(38,797	)		(35,219	)		21,449

Balance, end of year⁽¹⁾	$	28,766		$	67,563		$	102,782


(1)		Reflects the twelve-month average of the first-day-of-the-month reference prices for 2009 and the year-end reference prices for prior years.

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Supplementary Selected Quarterly Financial Data — Unaudited

The following table provides unaudited supplementary financial information on our results of operations for each quarter in the two-year period ended December 31, 2009.


(In thousands, except per share amounts)

	Year Ended December 31,
	2009												2008
	4th			3rd			2nd			1st			4th		3rd		2nd		1st
Revenues	$	14,769		$	11,195		$	14,664		$	17,196		$	21,825	$	23,590	$	21,342	$	17,650
Income (loss) before income taxes		(4,126	)		(614	)		(2,039	)		(1,264	)		735		2,082		3,141		779
Net income (loss)		(3,213	)		(1,122	)		(1,935	)		(1,431	)		307		945		1,521		163
Diluted EPS		(0.11	)		(0.04	)		(0.07	)		(0.05	)		0.01		0.04		0.06		0.01
Common stock price range:
High	$	2.40		$	2.62		$	3.00		$	2.26		$	4.80	$	9.75	$	10.31	$	6.39
Low		1.60			1.46			1.18			0.77			1.30		4.41		5.58		4.50

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Attached files

NGAS Resources Inc Reports

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