General
We are an independent exploration and production company focused on unconventional natural gas plays in the eastern United States, principally in the southern portion of the Appalachian Basin. We have specialized for over 20 years in generating our own geological prospects in this region, where we have established expertise and recognition. We believe our extensive operating experience, coupled with our relationships with partners, suppliers and mineral interest owners, gives us competitive advantages in developing these resources to achieve sustained volumetric growth and strong financial returns on a long-term basis.
Recent Developments
Liquidity from Sale of Interest in Gathering System. On July 15, 2009, we completed the sale of a 50% undivided interest in our Appalachian gas gathering and midstream facilities (Gathering System) for $28 million. Proceeds from the transaction were applied to reduce outstanding borrowings under our revolving credit facility, which was fully drawn prior to the sale. See "Liquidity and Capital Resources." The sale was covered by an Asset Purchase Agreement (APA) among our operating subsidiaries, Daugherty Petroleum, Inc. (DPI), NGAS Gathering, LLC and NGAS Gathering II, LLC (NGAS Gathering II), with Seminole Gas Company, L.L.C. (Seminole). As part of the transaction, we entered into various gas marketing and gas sales arrangements with Seminole and its parent company, Seminole Energy Services, LLC (Seminole Energy). In addition to addressing our liquidity constraints through the sale, we retained operating rights and firm capacity rights in the Gathering System under these arrangements. This ensures long-term deliverability for our Appalachian production through the Gathering System, which currently spans 485 miles through parts of southeastern Kentucky, eastern Tennessee and western Virginia. See "Business Strategy." Option for Sale of Retained Gathering System Interest. At the closing under the APA, we granted Seminole Energy a six-month option to buy our retained 50% interest in the Gathering System for $22 million (Seminole Option). If the Seminole Option is exercised, the purchase price will be payable $7.5 million at closing and the balance over 30 months under a promissory note from Seminole Energy bearing interest at 8% per annum. If certain conditions are met, we have the right to require the exercise of the Seminole Option. Proceeds from any exercise of the Seminole Option will be applied to further reduce our credit facility borrowings, providing us with additional liquidity to take greater advantage of our development opportunities.
Development of Additional Drilling Prospects. We entered into a farmout agreement in May 2009 with 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. Chesapeake's prior development of the tract includes approximately 100 producing wells and gathering facilities that connect to our 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, with an additional commitment to drill six vertical Devonian shale wells by the beginning of June 2009. To meet our initial commitment, we entered into arrangements with a joint venture partner that provide 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 Devonian shale horizontal wells on the acquired acreage. Business Strategy
Over 71% of our 329,000-acre position in the Appalachian Basin is undeveloped, along with most of our assembled acreage in the Illinois Basin. Our business is structured for development of these resources, which has been transformed by our use of horizontal drilling throughout our operating areas. We began this transition early in 2008 and had 20 horizontal wells on line at year-end, with an additional five horizontals producing to sales at the end of June 2009. Our success with these initiatives contributed to growth in our production volumes to 3.7 Bcfe in 2008, up 13% over 2007. Despite substantially reduced drilling activity in the first half of 2009, we produced 1.0 Bcf of natural gas equivalents in the second quarter. This represents a 5% increase from the same quarter last year, but a 4% decline from record production volumes in the 2009 first quarter. Having improved our balance sheet and prospects for additional liquidity, our extensive inventory of low-risk, repeatable horizontal drilling locations positions us for future growth under a sustainable, low-cost structure with several components.

• Organic Growth through Drilling with Reduced Capital Spending. While we are committed to a long-term strategy of developing our reserves through the drillbit and retaining most of our available working interest in new wells, we have addressed the challenging conditions in our industry by reducing our 2009 capital spending budget, currently set at $15 million, and sharing development costs by returning to our successful partnership structure for operated initiatives. We raised over $34 million for a non-operated program last year through our established sales network. To meet our near-term drilling commitments and objectives, in addition to monetizing our Gathering System, we are currently sponsoring a partnership to participate in up to 53 horizontal wells throughout our operated properties. The partnership commenced operations following an initial closing of its private placement in June 2009. We are maintaining a 20% interest in this year's program and will earn an additional 15% reversionary interest after program payout.

• Horizontal Drilling Initiatives. Recent advances in horizontal drilling and completion technology have enhanced the value proposition for our operated properties by substantially increasing our recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or challenging terrain. We focused these initiatives during 2008 in our Leatherwood field, where we completed 20 horizontal wells last year. Each well has a single lateral leg up to 3,500 feet through the Devonian shale formation, which is present throughout our Appalachian operating areas. Initial 30-day flow rates for our Leatherwood horizontals averaged 309 Mcf per day. We achieved comparable results for our first two New Albany shale horizontals drilled late in 2008 on our Illinois Basin acreage and our initial Devonian shale horizontals completed during the first quarter of 2009 in each of our Straight Creek, Fonde and Martin's Fork fields. We plan to continue this transition throughout our operated properties.

• Advantages from Restructured Infrastructure Position. The Gathering System covered by our APA with Seminole provides deliverability from 90% of our Appalachian properties directly from the wellhead to major east coast natural gas markets through an interconnect with Spectra Energy Partners' East Tennessee Interstate pipeline network. Although our sale of a 50% interest in our Gathering System eliminated the closed-access status of our field-wide infrastructure, our retained capacity rights ensure long-term deliverability from our operated Appalachian properties serviced by these facilities. These capacity rights, currently established at 30,000 Mcf per day, also preserve our competitive advantages from control of regional gas flow, enhancing our opportunities to acquire undeveloped acreage near our core producing fields upon completion of coal mining activities.

Drilling Operations
General. As of June 30, 2009, we had interests in a total of 1,403 wells, concentrated on Appalachian properties. We believe our long and successful operating history and proven ability to drill a large number of wells year after year have positioned us as a leading producer in this region. Historically, we conducted most of our drilling operations through sponsored drilling partnerships with outside investors, enabling us to assemble our acreage positions on the strength of our drilling commitments, while also funding infrastructure development on acquired acreage for our own account. Beginning in the second half of 2007, with our core Appalachian infrastructure in place, we changed our business model to limit our use of drilling partnerships to participation in non-operated plays, retaining all of our available working interest in wells drilled on operated properties through the end of 2008. To address part of the capital requirements for meeting this year's drilling commitments and objectives, we are sponsoring a drilling partnership for up to $53.1 million to participate in our horizontal wells during the balance of 2009 and the first quarter of 2010. The partnership commenced operations at the end of June 2009 following the initial closing of its private placement.
Geological Factors. Although mineral development in Appalachia has historically been dominated by coal mining interests, it is also one of the oldest and most prolific natural gas producing areas in the United States. Most of our vertical wells in this region were drilled to relatively shallow total depths averaging 4,500 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout our Appalachian acreage is the Devonian shale formation. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance natural fracturing in these reservoirs. Estimated ultimately recoverable volumes (EURs) of natural gas reported for vertical gas wells in this part of Appalachia range between 100 to 450 Mmcf, with modest initial volumes offset by low annual decline rates, resulting in a reserve life index of over 25 years. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.
Horizontal Drilling. Air-driven horizontal drilling advances and staged completion technology optimized for our operating areas have dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. In general, our horizontal wells use directional air drilling to create a lateral leg up to 3,500 feet through the

target formation. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation than conventional vertical wells. While up to four times more expensive than vertical wells, horizontal drilling is improving overall performance by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells. Typically, one horizontal well replaces between three to four vertical locations, reducing the total footprint by drilling fewer wells. Additional economies can be achieved by drilling multiple horizontal wells on a single drilling location. In addition to these operational advantages, the initial recovery rates for these horizontals are averaging six to eight times the rates for our vertical Devonian shale wells in the same fields. Although not fully reflected in our 2008 year-end reserve estimates, we anticipate substantial upside in both production and EURs from our ongoing transition to horizontal drilling.
Staged Completion Technology. Upon completion of drilling the lateral leg of our horizontal wells, we run 4.5-inch casing and packers to the end of the leg, and the packers are set at intervals, allowing the well to be completed in up to eight separate stages within the horizontal leg. A staged treatment process is then performed on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally over one-million standard cubic feet per stage. After the well is blown back for approximately seven days, it is connected to our existing field-wide gathering facilities to commence gas sales. We have not completed any of our horizontal wells in up-hole zones to avoid the risk of fluid production from those zones.
New Albany Shale Play. In addition to the recent expansion of Appalachian acreage through our Chesapeake farmout, we are continuing to develop our New Albany shale play within the southcentral portion of the Illinois Basin in western Kentucky. We began producing this project to sales in September 2008, with a total of 37 wells on line at June 30, 2009. Based on encouraging results from our New Albany shale horizontals, we have expanded our lease position and plan to drill up to five horizontal wells on this acreage through our 2009 drilling partnership. See "Business Strategy." Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2008 and the first half of 2009. Drilling results shown in the table for 2008 include 55 gross (24.18 net) wells that were drilled by year-end but were awaiting installation of gathering lines or extensions prior to completion, primarily on non-operated properties. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may subsequently earn in wells drilled through our sponsored drilling programs.

                                           Development Wells                Exploratory Wells
                                         Productive           Dry          Productive          Dry
                                     Gross        Net        Gross     Gross       Net        Gross
   Year Ended December 31, 2008

   Vertical                           137       58.8522         -         9       8.8125         -
   Horizontal                          47       15.7254         -         -            -         -

   Total                              184       74.5776         -         9       8.8125         -


   Six Months Ended June 30, 2009

   Vertical                            10        1.6972         -         -            -         -
   Horizontal                           8        1.7588         -         -            -         -

   Total                               18        3.4560         -         -            -         -

Producing Activities
Regional Advantages. Our proved reserves, both developed and undeveloped, are concentrated in the southern portion of the Appalachian Basin. The proximity of this region to major east coast gas markets reduces our transportation costs, generating realization premiums above Henry Hub spot prices and contributing to long-term returns on investment. Our Appalachian gas production also has the advantage of a high energy content (Dth), ranging from 1.1 to 1.3 Dth per Mcf. Historically, because our gas sales contracts yield upward adjustments from index based pricing for throughput with an energy content above 1 Dth per Mcf, this resulted in realized premiums averaging 17% over normal pipeline quality gas.
Liquids Extraction. During 2007, in response to regulatory tariffs limiting the upward range of pipeline throughput to 1.1 Dth per Mcf, we constructed a processing plant with Seminole Energy in Rogersville, Tennessee for liquids extraction from our Appalachian production delivered through the Gathering System. See "Recent Developments." The plant was brought on line in February 2008, ensuring our compliance with the new energy content standard. Sales of extracted liquids have partially offset the reduction in energy-related yields from our

Appalachian gas production. In addition, our margins for sales of extracted liquids have benefited from lower hauling costs achieved through recently implemented rail shipping arrangements.
Oil and Gas Production. Our production revenues and estimated oil and gas reserves are substantially dependent on prevailing market prices for natural gas, which comprised 78% of our proved reserves on an energy equivalent basis at the end of 2008. The following table shows the average sales prices for our oil and gas production during 2008 and the first two quarters of 2009.

                                            Three Months Ended                     Six Months Ended                 Year Ended
                                                 June 30,                              June 30,                    December 31,
                                         2009               2008               2009               2008                 2008
Production volumes:

Natural gas (Mcf)                         836,282            764,530          1,704,830          1,508,528             3,087,596
Oil (Bbl)                                  12,149             14,994             25,426             28,482                57,291
Natural gas liquids (gallons)           1,235,477          1,094,547          2,436,658          1,728,682             3,895,649


Equivalents (Mcfe)                      1,001,838            950,268          2,040,135          1,830,682             3,745,124


Average sales prices:

Natural gas (per Mcf)                 $      6.47        $      9.88        $      6.61        $      9.21        $         8.89
Oil (per Bbl)                               51.89             115.54              42.07             103.67                 95.07
Natural gas liquids (per gallon)             0.69               1.73               0.67               1.64                  1.41

Future Gas Sales Contracts. We use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time to address commodity price volatility. Our physical delivery contracts are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of these contracts is included in our oil and gas revenues at the time of settlement. As of the date of this report, we have contracts in place for the following portions of our anticipated natural gas production for 2010 and the second half of 2009. The table includes contracts added with Seminole Energy in connection with the closing under the APA, covering monthly production volumes ranging from 55,000 to 120,00 Mcf for one year beginning in April 2010 at $5.94 per MMBtu plus regional basis adjustments. See "Recent Developments." Fixed-Price Contracts for Natural Gas Production

                                                               2009
                                                           Q3         Q4        2010
     Average price per Mcf                              $ 8.38     $ 7.82       $6.71
     Percent of anticipated gas production contracted     50.7 %     55.3 %      45.4 %

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

                                                             Three Months Ended June 30,
                                                                        % of                                  %
                                                      2009             Revenue             2008             Change
Revenue:

Contract drilling                                 $  5,172,998               35 %      $  7,625,356             (32 )%
Oil and gas production                               6,891,644               47          11,179,620             (38 )
Gas transmission, compression and processing         2,599,229               18           2,536,560               2


Total                                             $ 14,663,871              100 %      $ 21,341,536             (31 )

Our revenue mix for the second quarter of 2009 reflects the impact of declining commodity prices and reduced drilling activity on our strategy for transitioning to a more production based business. During the 2009 second quarter, our oil and gas sales accounted for 47% of total revenues, compared to 52% of total revenues for the second quarter of 2008 and 46% for the year as a whole. In view of our reduction in capital expenditures for 2009, we do not expect this trend to reverse without a significant recovery in commodity prices.

Contract drilling revenues reflect the size and timing of our drilling partnership initiatives. Although we receive the proceeds from private placements in sponsored partnerships as customers' drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. 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 the second quarter of 2009 reflect the completion of drilling operations for that program and the commencement of operations for our 2009 drilling partnership, which participated in three horizontal wells through the end of the second quarter. We plan to drill up to an additional 50 horizontal wells on our operated properties though our 2009 drilling partnership during the balance of the year and the first quarter of 2010.
Production revenues for the second quarter of 2009 reflect an increase of 5.4% in production output to 1,002 Mmcfe, compared to 950 Mmcfe in the year-earlier period, offset by a 35% decline in natural gas prices, 55% in oil prices and 60% for sales of natural gas liquids. Our volumetric growth reflects strong performance from our horizontal wells and the commencement of production from our Haley's Mill field in western Kentucky during August 2008. Approximately 45% of our natural gas production in the current quarter was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in the 2009 second quarter averaged $7.68 per Mcf for our Appalachian production and $6.47 per Mcf overall, compared to an average overall realization of $9.88 per Mcf in the second quarter of 2008.
Gas transmission, compression and processing revenues for the current quarter were driven by fees totaling $820,856 for moving our drilling program investors' share of gas through the field-wide portions of the Gathering System and $397,939 for third-party deliveries through the open-access portion of the system, along with $232,202 in related processing fees for liquids extraction through our Rogersville plant, which is co-owned with Seminole Energy. This component of revenues also includes contributions of $72,210 from gas utility sales. We expect our sale of a 50% interest in the Gathering System under our APA with Seminole to result in a significant contraction in our total gas transmission, compression and processing revenues beginning in the third quarter of 2009, with further reductions following any exercise of the Seminole Option. See "Recent Developments."
Expenses. The following table shows the components of our direct and other expenses for the three months ended June 30, 2009 and 2008. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

                                                                     Three Months Ended June 30,
                                                     2009              Margin             2008              Margin
Direct Expenses:

Contract drilling                                 $ 3,873,266                25 %      $ 5,756,997                25 %
Oil and gas production                              2,614,094                62          3,107,095                72
Gas transmission, compression and processing        1,025,408                61            957,548                62


Total direct expenses                               7,512,768                49          9,821,640                54


                                                                      % Revenue                            % Revenue

Other Expenses:

Selling, general and administrative                 2,552,740                17 %        3,442,094                16 %
Options, warrants and deferred compensation           319,192                 2            234,803                 1
Depreciation, depletion and amortization            3,687,621                25          3,261,192                15
Bad debt expense                                            -                 -             59,000                 -
Interest expense, net of interest income            1,453,630                10          1,346,550                 6
Other, net                                            216,377                 1             34,632                 -


Total other expenses                              $ 8,229,560                          $ 8,378,271

Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses decreased by 33% on a period-over-period basis and represented 75% of contract drilling revenues in both periods. 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. The decrease in production expenses on a period-over-period basis primarily reflects lower severance taxes and the adoption of

various cost-cutting measures for our field operations. Our margins in both periods reflect cost savings realized from ownership of our Appalachian Gathering System. Historically, this eliminated transportation and processing fees for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system. With the sale of a 50% interest in these facilities during July 2009 under our APA with Seminole, our overall production expenses in future periods will be impacted by higher transportation costs, which will be further increased from the sale of our remaining 50% interest in the Gathering System upon any exercise of the Seminole Option. See "Recent Developments."
Gas transmission, compression and processing expenses in the second quarter of 2009 were 39% of associated revenues, compared to 38% in the same quarter last year. These expenses do not include capitalized costs of approximately $500,000 in the current quarter for extensions of our field-wide gas gathering systems and additions to dehydration and compression capacity required to bring new wells on line. Our gas transmission and compression expenses as well as capitalized costs for this part of our business will be substantially reduced by . . .