properties. The partnership commenced operations following an initial closing of its private placement in June 2009. We are maintaining a 20% interest in this year's program and will earn an additional 15% reversionary interest after program payout.

• Horizontal Drilling Initiatives. Recent advances in horizontal drilling and completion technology have enhanced the value proposition for our operated properties by substantially increasing our recovery volumes and rates at dramatically lower finding costs. Horizontal drilling also gives us access to areas where natural gas development would otherwise be delayed or constrained by coal mining activity or challenging terrain. We focused these initiatives during 2008 in our Leatherwood field, where we completed 20 horizontal wells last year. Each well has a single lateral leg up to 3,500 feet through the Devonian shale formation, which is present throughout our Appalachian operating areas. Initial 30-day flow rates for our Leatherwood horizontals averaged 309 Mcf per day. We achieved comparable results for our first two New Albany shale horizontals drilled late in 2008 on our Illinois Basin acreage and our initial Devonian shale horizontals completed this year in our Straight Creek, Fonde and Martin's Fork fields. We plan to continue this transition throughout our operated properties, including 25 horizontal wells planned this year in Leatherwood.

• Advantages from Restructured Infrastructure Position. Although the sale of our Gathering System during the third quarter of 2009 eliminated the closed-access status for most of our field-wide infrastructure, we retained long-term capacity rights for the system, currently established at 30,000 Mcf per day. This ensures continued deliverability from our operated Appalachian properties serviced by these facilities. We also retained operating rights for the Gathering System, which provides deliverability from 90% of our Appalachian properties directly from the wellhead to major east coast natural gas markets through an interconnect with Spectra Energy Partners' East Tennessee Interstate pipeline network. Our operating and capacity rights also preserve our competitive advantages from control of regional gas flow, enhancing our opportunities to acquire undeveloped acreage near our core producing fields upon completion of coal mining activities. We continue to own a 50% interest in a liquids extraction plant for production serviced by the Gathering System, located in Rogersville, Tennessee. This is within 5.5 miles of the proposed site for a 880-megawatt gas-fired power plant to be constructed by the Tennessee Valley Authority, which may provide us with opportunities for long-term gas sales arrangements.

Drilling Operations
General. As of September 30, 2009, we had interests in over 1,400 wells, concentrated on our Appalachian properties. We believe our long and successful operating history and proven ability to drill a large number of wells year after year have positioned us as a leading producer in this region. Historically, we conducted most of our drilling operations through sponsored drilling partnerships with outside investors, enabling us to assemble our acreage positions on the strength of our drilling commitments, while also funding infrastructure development on acquired acreage for our own account. Beginning in the second half of 2007, with our core Appalachian infrastructure in place, we changed our business model to limit our use of drilling partnerships to participation in non-operated plays, retaining all of our available working interest in wells drilled on operated properties through the end of 2008. To address part of the capital requirements for meeting this year's drilling commitments and objectives, we are sponsoring a drilling partnership for up to $53.1 million to participate in our horizontal wells during 2009 and the first quarter of 2010. The partnership commenced operations in June 2009 following the initial closing of its private placement.
Geological Factors. Although mineral development in Appalachia has historically been dominated by coal mining interests, it is also one of the oldest and most prolific natural gas producing areas in the United States. Most of our vertical wells in this region were drilled to relatively shallow total depths averaging 4,500 feet, generally encountering several predictable natural gas pay zones. The primary pay zone throughout our Appalachian acreage is the Devonian shale formation. This is considered an unconventional target due to its low permeability, requiring effective treatment to enhance natural fracturing in these reservoirs. Estimated ultimately recoverable volumes (EURs) of natural gas reported for vertical gas wells in this part of Appalachia range between 100 to 450 Mmcf, with modest initial volumes offset by low annual decline rates, resulting in a reserve life index of over 25 years. Our New Albany shale play in the Illinois Basin has similar geological, production and reserve characteristics.

Horizontal Drilling. Air-driven horizontal drilling advances and staged completion technology optimized for our operating areas have dramatically improved the economics of our shale plays in the Appalachian and Illinois Basins. In general, our horizontal wells use directional air drilling to create a lateral leg up to 3,500 feet through the target formation. This allows the well bore to stay in contact with the reservoir longer and to intersect more fractures in the formation than conventional vertical wells. While up to four times more expensive than vertical wells, horizontal drilling is improving overall performance by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area through conventional drilling and reducing the costs and surface disturbances of multiple vertical wells. Typically, one horizontal well replaces between three to four vertical locations, reducing the total footprint by drilling fewer wells. Additional economies are being achieved with multiple horizontal wells on a single drilling location. In addition to these operational advantages, the initial recovery rates for our horizontals are averaging six to eight times the rates for vertical Devonian shale wells in the same fields. Although not fully reflected in our 2008 year-end reserve estimates, we anticipate substantial upside in both production and EURs from our ongoing transition to horizontal drilling.
Staged Completion Technology. Upon completion of drilling the lateral leg of our horizontal wells, we run 4.5-inch casing and packers to the end of the leg. The packers are set at intervals, allowing the well to be completed in up to eight separate stages within the horizontal leg. A staged treatment process is then performed on our horizontal wells to enhance natural fracturing with large volumes of nitrogen, generally over one-million standard cubic feet per stage. After the well is blown back for approximately seven days, it is connected to our existing field-wide gathering facilities to commence gas sales.
New Albany Shale Play. In addition to the recent expansion of our Leatherwood acreage and our Chesapeake farmout, we are continuing to develop our New Albany shale play within the southcentral portion of the Illinois Basin in western Kentucky. We began producing this project to sales in September 2008 upon completion of our gas gathering and processing infrastructure for the acreage, with a total of 33 wells on line at September 30, 2009. Based on encouraging results from our New Albany shale horizontals, we have expanded our lease position and plan to drill up to five horizontal wells on this acreage through our 2009 drilling partnership.
Drilling Results. The following table shows the number of gross and net development and exploratory wells we drilled during 2008 and the first nine months of 2009. Drilling results shown in the table for 2008 include 55 gross (24.18 net) wells that were drilled by year-end but were awaiting installation of gathering lines or extensions prior to completion, primarily on non-operated properties. Gross wells are the total number of wells in which we have a working interest. Net wells reflect our working interests, without giving effect to any reversionary interest we may subsequently earn in wells drilled through our sponsored drilling programs.

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

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

Total                                       184        74.5776              -             9        8.8125              -


Nine Months Ended September 30, 2009

Vertical                                     10         1.6972              -             -             -              -
Horizontal                                   14         2.7588              -             -             -              -

Total                                        24         4.4560              -             -             -              -

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

Liquids Extraction. During 2007, in response to regulatory tariffs limiting the upward range of pipeline throughput to 1.1 Dth per Mcf, we constructed a processing plant with Seminole Energy in Rogersville, Tennessee for liquids extraction from our Appalachian production delivered through the Gathering System. The plant was brought on line in February 2008, ensuring our compliance with the new energy content standard. Sales of extracted natural gas liquids (NGL) have partially offset the reduction in energy-related yields from our Appalachian gas production. In addition, our margins for sales of extracted NGL have benefited from lower hauling costs achieved through recently implemented rail shipping arrangements.
Oil and Gas Production. Our production revenues and estimated oil and gas reserves are substantially dependent on prevailing market prices for natural gas, which comprised 78% of our proved reserves on an energy equivalent basis at the end of 2008. The following table shows the average sales prices for our natural gas, crude oil and NGL production during 2008 and the interim reporting periods.

                                            Three Months Ended                    Nine Months Ended                 Year Ended
                                              September 30,                         September 30,                  December 31,
                                         2009               2008               2009               2008                 2008
Production volumes:

Natural gas (Mcf)                         816,393            760,401          2,521,223          2,268,929             3,087,596
Oil (Bbl)                                  11,887             16,235             37,313             44,718                57,291
Natural gas liquids (gallons)           1,458,541          1,202,292          3,895,199          2,930,974             3,895,649

Equivalents (Mcfe)                        997,103            947,986          3,037,238          2,778,668             3,745,124

Average sales prices:

Natural gas (per Mcf)                 $      5.67        $      9.80        $      6.31        $      9.40        $         8.89
Oil (per Bbl)                               60.76             110.26              48.03             106.06                 95.07
Natural gas liquids (per gallon)             0.61               1.65               0.64               1.64                  1.41

Future Gas Sales Contracts. We use fixed-price, fixed-volume physical delivery contracts that cover portions of our natural gas production at specified prices during varying periods of time to address commodity price volatility. Our physical delivery contracts are not treated as financial hedging activities and are not subject to mark-to-market accounting. The financial impact of these contracts is included in our oil and gas revenues at the time of settlement. As of the date of this report, we have contracts in place for the following portions of our anticipated natural gas production for each quarter of 2010 and the fourth quarter of 2009.
Fixed-Price Contracts for Natural Gas Production

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

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

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

Contract drilling                                 $  3,831,250               34 %      $  9,799,561             (61 )%
Oil and gas production                               6,239,324               56          11,222,879             (44 )
Gas transmission, compression and processing         1,123,921               10           2,567,852             (56 )

Total                                             $ 11,194,495              100 %      $ 23,590,292             (53 )

Our total revenues for the third quarter of 2009 reflect the impact of declining commodity prices, reduced drilling activity and our sale of the Gathering System. In view of our reduction in capital expenditures for 2009, we do not expect this trend to reverse without a significant recovery in commodity prices and an increase in the level of drilling activity, which is directly linked to partnership sales under our current business model. Although sales of partnership interests are typically concentrated in the fourth quarter, they may continue to be impacted this year by the challenging economic environment.
Contract drilling revenues reflect the size and timing of our drilling partnership initiatives. Although we receive the proceeds from private placements in sponsored partnerships as customers' drilling deposits under our program drilling contracts, we recognize revenues from the interests of outside investors in these programs on the completed contract method as the wells are drilled, rather than when funds are received. Our contract drilling revenues in the third quarter of 2009 reflect continued operations of our 2009 drilling partnership, which participated in six horizontal wells during the quarter. We plan to drill a total of up to 53 horizontals on our operated properties though that program, depending on the level of partnership participation.
Production revenues for the third quarter of 2009 reflect an increase of 5% in production output to 997 Mmcfe, compared to 948 Mmcfe in the year-earlier period, offset by declines of 42% in natural gas prices, 45% in oil prices and 63% for sales of natural gas liquids. Our volumetric growth reflects strong performance from our horizontal wells and the commencement of production from our Haley's Mill field in western Kentucky during August 2008, along with our share of production from non-operated wells drilled for our 2008 drilling partnership. Approximately 50% of our natural gas production in the current quarter was sold under fixed-price physical delivery contracts, and the balance primarily at prices determined monthly under formulas based on prevailing market indices. Realized natural gas prices in the 2009 third quarter averaged $6.53 per Mcf for our Appalachian production and $5.67 per Mcf overall, compared to an average overall realization of $9.80 per Mcf in the third quarter of 2008.
The contraction of gas transmission, compression and processing revenues for the current quarter was driven our sale of a 50% interest in the Gathering System in mid-July and the balance in mid-August 2009. See "Recent Developments." Following the sale, our gas transmission, compression and processing revenues were limited primarily to gas utility sales and our share of third-party fees for liquids extraction through our Rogersville plant, which we continue to co-own with Seminole Energy.
Expenses. The following table shows the components of our direct and other expenses for the three months ended September 30, 2009 and 2008. Percentages listed in the table reflect margins for each component of direct expenses and percentages of total revenue for each component of other expenses.

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

Contract drilling                                 $ 2,913,418             24 %      $  7,570,698             23 %
Oil and gas production                              2,658,985             57           3,922,629             65
Gas transmission, compression and processing          960,879             15           1,039,597             60

Total direct expenses                               6,533,282             42          12,532,924             47




                                                                      % Revenue                             % Revenue
Other Expenses (Income):

Selling, general and administrative                 2,601,514                 23 %        3,551,908                 15 %
Options, warrants and deferred compensation           285,309                  3            229,209                  1
Depreciation, depletion and amortization            3,304,139                 30          3,318,320                 14
Bad debt expense                                            -                N/A            342,195                  1
Interest expense, net of interest income            1,138,711                 10          1,446,526                  6
Gain on sale of assets                             (3,356,177 )              N/A                  -                N/A
Other, net                                            292,073                  3             87,584                  -

Total other expenses                             $  4,265,569                           $ 8,975,742

Contract drilling expenses reflect the level and timing of drilling initiatives conducted through our sponsored partnerships. These expenses represented 76% of contract drilling revenues in the current quarter, compared to 77% in the year-earlier period. Margins for contract drilling operations reflect our cost-plus pricing model, which we adopted in 2006 to address price volatility for drilling services, equipment and steel casing requirements.

Production expenses represent lifting costs, field operating and maintenance expenses, related overhead, severance and other production taxes, third-party transportation fees and processing costs. Historically, our ownership of the Gathering System eliminated transportation costs for our share of Leatherwood, Straight Creek, Fonde and Stone Mountain production delivered through the system. The increase in production expenses on a period-over-period basis primarily reflects higher transportation costs following our sale of the Gathering System, which will further impact these costs in future periods. See "Recent Developments." As a percentage of revenues, overall production expenses in the current quarter benefitted from lower severance taxes and various cost-cutting measures for our field operations.
Our gas transmission and compression expenses, as well as capitalized costs for this part of our business, were substantially reduced in the third quarter of 2009 following our sale of the Gathering System. Our remaining infrastructure position is comprised of 100% interests in the gas gathering facilities for our Haley's Mill and Kay Jay fields, 50% interests in our Haley's Mill and Rogersville processing plants and a 25% interest in the gathering system for our non-operated Arkoma properties. Our gas transmission, compression and processing expenses in future periods will reflect this reduction in our infrastructure asset base.
Selling, general and administrative (SG&A) expenses are comprised primarily of selling and promotional costs for our sponsored drilling partnerships and general overhead costs. Our SG&A expenses in the current quarter decreased by 27% from the same period last year, primarily due to the timing of partnership sales, and represented 23% of revenues in the current quarter, compared to 15% in the third quarter of 2008.
Non-cash charges for options, warrants and deferred compensation reflect the fair value method of accounting for employee stock options. Under this method, employee stock options are valued at the grant date using the Black-Scholes valuation model, and the compensation cost is recognized ratably over the vesting period. We also recognized an accrual of $153,637 for deferred compensation cost in the current quarter.
Depreciation, depletion and amortization (DD&A) is recognized under the . . .