BUSINESS OVERVIEW

The Company's principal line of business is to explore for, develop, produce and sell oil, NGL and natural gas. Results of operations are dependent primarily upon: reserve quantities and associated exploration and development costs in finding new reserves; production quantities and related production costs; and oil, NGL and natural gas sales prices. In the 2012 first quarter the Company acquired certain assets in the core of the Fayetteville Shale which included an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold containing approximately 240 future infill drilling locations. This acquisition contributed to both increased drilling activity and increased natural gas production during 2012. During 2012, net wells drilled increased 69% over net wells drilled in 2011. However, capital expenditures only increased approximately 11% due to the average drilling and completion cost per well being lower in 2012 than in 2011. The lower drilling cost per well is primarily the result of drilling more wells in the Arkansas Fayetteville Shale during 2012 and less wells in the Anadarko Woodford Shale play where a typical well costs two and one half to three times that of a typical Fayetteville Shale well.

Natural gas production was 9% higher in 2012 than in 2011. This production increase is the combined effect of added natural gas production from Fayetteville Shale acquisitions and continued drilling on the Company's mineral and leasehold acreage.

Ongoing development in the following oily plays has resulted in a 47% increase in 2012 oil production, as compared to 2011:

• Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

• Horizontal Cleveland in western Oklahoma and the Texas Panhandle

• Horizontal Marmaton in western Oklahoma

• Horizontal Tonkawa in western Oklahoma

• Vertical Mississippian in northern Oklahoma

• Vertical Spraberry in West Texas

• Vertical Yeso in southeastern New Mexico

• Horizontal Anadarko Basin Woodford Shale in western Oklahoma

• Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

As of September 30, 2012, the Company owned an average 3.6% net revenue interest in 62 wells that were drilling or testing. As these wells begin producing and other scheduled wells are drilled and completed in the abovementioned plays, the Company expects fiscal 2013 oil and natural gas production to increase over that of 2012.

Although oil, NGL and natural gas production increased in 2012, oil, NGL and natural gas sales revenues decreased 6% as a result of sharply lower natural gas prices, partially offset by a slight increase in oil prices. Based on recent forward strip pricing for 2013, the Company expects average natural gas prices to be higher and average oil prices to be slightly lower than the average prices of 2012.

The Company's proved developed oil, NGL and natural gas reserves increased in 2012, compared to 2011, by 6.7 Bcfe. The increase is due to the Fayetteville Shale acquisitions and successful drilling of exploratory and developmental wells (in excess of PUD reserves previously presented), partially offset by negative natural gas pricing revisions. The overall increase in oil, NGL and natural gas production combined with the negative price revisions to 2012 proved developed natural gas reserves and higher finding cost experienced in the oil and liquids-rich areas resulted in higher DD&A in 2012.

Management currently expects drilling on the Company's acreage to result in capital expenditures for oil and natural gas activities of approximately $25 million during 2013. The Company will also continue to evaluate opportunities to acquire mineral acreage or producing properties. Acquisitions, if any, will be financed by a combination of cash flows and the bank credit facility.

The Company had no off balance sheet arrangements during 2012 or prior years.

The following table reflects certain operating data for the periods presented:

                                                                   For the Year Ended September 30,
                                                         Percent                                      Percent
                                    2012            Incr. or (Decr.)             2011            Incr. or (Decr.)             2010
Production:
Oil (Bbls)                           153,143                       47 %           104,141                        2 %           102,379
NGL (Bbls)                            98,714                       -                    *                       -                    *
Natural Gas (Mcf)                  9,072,298                        9 %         8,297,657                        0 %         8,302,342
Mcfe                              10,583,440                       19 %         8,922,503                        0 %         8,916,616
Average Sales Price:
Oil (per Bbl)                   $      90.13                        2 %       $     88.00                       21 %       $     72.83
NGL (per Bbl)                   $      33.23                       -                    *                       -                    *

(1) Proceeds from the sale of NGL in 2011 and 2010 were included in natural gas sales, and were therefore included in the price per Mcf of natural gas.

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last two years in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and 2012 production volumes. In quarters prior to 2012, all NGL sales revenues were included with natural gas sales revenues.

RESULTS OF OPERATIONS

Fiscal Year 2012 Compared to Fiscal Year 2011

Overview

The Company recorded net income of $7,370,996, or $0.88 per share, in 2012, compared to net income of $8,493,912, or $1.01 per share, in 2011. Revenues increased in 2012 primarily due to increased lease bonuses and higher oil and natural gas sales volumes, partially offset by lower natural gas prices.

Expenses increased due to higher DD&A, LOE and G&A in 2012, partially offset by decreases in the provision for impairment and exploration costs. Significant well additions through acquisition and drilling in 2012 increased production volumes and lifting costs, resulting in higher DD&A and LOE in 2012.

Oil, NGL and Natural Gas Sales

Oil, NGL and natural gas sales revenues decreased $2,650,696 or 6% for 2012, as compared to 2011. The decrease was due to lower natural gas prices of 37%, partially offset by increased oil volumes of 47%, increased natural gas volumes of 9% and a 2% increase in oil prices in 2012.

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Cleveland, Tonkawa, Marmaton, Anadarko Basin Woodford Shale and other plays in Oklahoma, West Texas, Texas Panhandle and southeastern New Mexico. The natural gas production increase is mainly a result of production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011. As of September 30, 2012, the Company owned an average 3.6% net revenue interest in 62 wells that were drilling or testing.

Production by quarter for 2012 and 2011 was as follows:

                                    2012                    2011
               First quarter       2,559,524     Mcfe      2,208,218     Mcfe
               Second quarter      2,654,485     Mcfe      2,152,011     Mcfe
               Third quarter       2,649,351     Mcfe      2,129,160     Mcfe
               Fourth quarter      2,720,080     Mcfe      2,433,114     Mcfe

               Total              10,583,440     Mcfe      8,922,503     Mcfe

Lease Bonus and Rentals

Lease bonuses and rentals increased $6,800,234 in 2012. The increase was mainly due to the Company leasing 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million. The rights leased were from the surface to 100 feet below the base of the Virgilian (commonly referred to as the Tonkawa). The Company also leased 2,431 net mineral acres in the horizontal Mississippian play in northern Oklahoma for $1.7 million. There were no large leases of the Company's mineral acreage in 2011.

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:



                 Gains (Losses) on
                 Derivative Contracts      2012             2011
                 Realized               $  462,033      $  2,138,685
                 Unrealized               (388,211 )      (1,404,386 )

                 Total                  $   73,822      $    734,299

The decrease in gains was mainly due to the natural gas basis protection swaps being less beneficial in 2012, as the basis differentials between NYMEX and CEGT and PEPL declined significantly. As of September 30, 2012, the Company's natural gas basis protection swaps have expiration dates of December 2012; the natural gas costless collar contracts have expiration dates of October 2012 and January 2013; the oil costless collar contracts have expiration dates of December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $700,216 or 8% in 2012. LOE costs per Mcfe of production decreased from $.95 in 2011 to $.86 in 2012. The total LOE increase is primarily related to increased field operating costs of $487,388 in 2012 compared to 2011. Field operating costs increased mainly due to the large addition of wells through acquisition and drilling in 2012. Field operating costs were $.42 per Mcfe in 2012 compared to $.44 per Mcfe in 2011, a 5% decrease. This decrease in rate is principally the result of fewer well workovers performed in 2012.

The increase in LOE related to field operating costs was also coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $212,828 in 2012, as compared to 2011. On a per Mcfe basis, these fees were down $.06 due to lower natural gas prices and the addition of significant oil production, which is unencumbered by these fees. Handling fees are mainly charged as a percent of natural gas sales but can also be charged based on natural gas production volumes.

Exploration Costs

Exploration costs were $979,718 in 2012 compared to $1,025,542 in 2011, a $45,824 decrease. During 2012, leasehold impairment and expired leasehold totaled $377,942 compared to $482,491 during 2011, a $104,549 decrease. The decline was driven by lower provisions for expected lease expirations in 2012, as compared to 2011. Charges on three exploratory dry holes totaled $601,776 during 2012; whereas, in 2011 the Company incurred exploratory dry hole costs on two wells totaling $543,051.

Depreciation, Depletion and Amortization (DD&A)

DD&A increased $4,349,051 or 30% in 2012. DD&A per Mcfe was $1.80 in 2012 compared to $1.65 in 2011. DD&A increased $2,738,695 due to oil, NGL and natural gas production volumes increasing 19% in the 2012 period compared to the 2011 period. The remaining increase of $1,610,356 was caused by a $.15 increase in the DD&A rate. This rate increase is mainly due to negative price revisions reducing ultimate reserves on a significant number of wells in reserves reported at September 30, 2012, as well as higher finding cost experienced in oil and liquids-rich areas where the Company is drilling and has had new wells come on line.

Provision for Impairment

The provision for impairment decreased $901,654 in 2012, as compared to 2011. During 2012, impairment of $826,508 was recorded on twelve small fields in Oklahoma. These fields have one to a few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions, or when a newly completed well with little production history is added to one of these fields. During the 2011 period, impairment of $1,728,162 was recorded on nine small fields in Oklahoma and Texas.

General and Administrative Costs (G&A)

G&A increased $394,193 or 7% in 2012. The increase is primarily related to increases in the following expense categories: personnel $419,166 and legal fees $118,245. These were partially offset by decreases in technical consulting, Board fees, company insurance and other expenses of $143,218 in 2012. The increase in 2012 personnel related expenses was the result of additional employees and annual increases in salaries and bonuses totaling $206,806, restricted stock expense increase of $178,441 and higher ESOP expense of $25,475. The increase in legal expenses resulted from increased acquisition activity and a quiet title defense settlement in 2012.

Provision (Benefit) for Income Taxes

The 2012 provision for income taxes of $3,274,000 was based on a pre-tax income of $10,644,996, as compared to a provision for income taxes of $3,192,000 in 2011, based on a pre-tax income of $11,685,912. The effective tax rate for 2012 was 31%, compared to an effective tax rate for 2011 of 27%. The 2012 effective tax rate increase of 4% was due to increased state income taxes of $553,926, partially offset by an excess percentage depletion benefit increase of $112,524. The 2012 state income tax increase was a result of significantly higher lease bonus income in Oklahoma, combined with lower intangible drilling cost deductions from Oklahoma taxable income. The Company's utilization of excess percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. The benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant.

Fiscal Year 2011 Compared to Fiscal Year 2010

Overview

The Company recorded net income of $8,493,912, or $1.01 per share, in 2011, compared to net income of $11,419,690, or $1.36 per share, in 2010. Decreased revenues in 2011 were primarily due to lower realized and unrealized gains on derivative contracts and lower lease bonuses and rentals. Actual and forward looking prices were lower than the Company's derivative contracts during 2011, resulting in net gains on derivative contracts; however, the variation during 2011 was not as significant as in 2010, therefore, gains on derivative contracts during 2011 were significantly less. The renewal of leases on certain of the Company's Arkansas undeveloped mineral acreage generated significant lease bonuses during 2010; whereas there were no such renewals in 2011.

Expenses decreased due to lower DD&A and exploration costs in 2011, partially offset by increases in the provision for impairment, general and administrative costs and a decrease in gain on asset sales, interest and other. The positive performance revisions recognized in the reserves reported at September 30, 2010, resulted in lower 2011 DD&A.

Oil and Natural Gas Sales

Oil and natural gas sales revenues decreased $599,817 or 1% for 2011, as compared to 2010. A decline in natural gas prices of 6% from 2010 to 2011, partially offset by a 21% increase in oil prices in 2011, caused the reduction of oil and natural gas sales revenues. Production from wells that came on line in 2011 offset the natural decline of existing wells such that oil and natural gas production volume in 2011 was relatively flat compared to 2010 volumes.

Drilling activity increased during the last quarter of 2010 and continued at a much higher rate throughout 2011, as compared to the first nine months of fiscal 2010. This increase in drilling activity resulted in 2011 production volumes (on an Mcfe basis) that were flat compared to those of 2010. The increased drilling activity is primarily on the Company's mineral acreage in the Arkansas Fayetteville Shale and in the oil and natural gas liquids-rich plays such as the Anadarko Woodford Shale, Horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and other similar plays in western Oklahoma. As of September 30, 2011, the Company owned an average 2.6% net revenue interest in 48 wells that were drilling or testing.

Production by quarter for 2011 and 2010 was as follows:

                                 2011                        2010
             First quarter      2,208,218       Mcfe        2,278,133       Mcfe
             Second quarter     2,152,011       Mcfe        2,090,154       Mcfe
             Third quarter      2,129,160       Mcfe        2,236,236       Mcfe
             Fourth quarter     2,433,114       Mcfe        2,312,093       Mcfe

             Total              8,922,503       Mcfe        8,916,616       Mcfe

Lease Bonus and Rentals

Lease bonus and rentals decreased $767,917 for 2011, as compared to 2010. Lease bonus and rental revenues in 2010 included lease bonuses of approximately $723,000 from certain of the Company's Arkansas mineral acreage, whereas there were no large leases of Company acreage in 2011.

Gains (Losses) on Derivative Contracts

Realized and unrealized gains and losses are scheduled below:



                 Gains (Losses) on
                 Derivative Contracts       2011             2010
                 Realized               $  2,138,685      $ 2,209,900
                 Unrealized               (1,404,386 )      4,133,761

                 Total                  $    734,299      $ 6,343,661

The Company's natural gas fixed price swap contracts had expiration dates of October 2011; the oil costless collar contracts have expiration dates of December 2011; the natural gas basis protection swaps have expiration dates of December 2011 and December 2012.

Lease Operating Expenses (LOE) and Production Taxes

LOE increased $248,435 or 3% in 2011. LOE costs per Mcfe of production increased from $.92 in 2010 to $.95 in 2011. The total LOE increase and the LOE per Mcfe increase were primarily related to increased field operating costs of approximately $276,000 in 2011 compared to 2010. Field operating costs were $.44 per Mcfe in 2011 compared to $.41 per Mcfe in 2010, a 7% increase. These increases were principally the result of well workovers performed in 2011.

Handling fees (primarily gathering, transportation and marketing costs) on natural gas in 2011 were slightly less than those of 2010. These fees decreased LOE approximately $28,000 in 2011.

Production taxes increased $10,210 or 1% in 2011. Some wells previously eligible for production tax credits or reductions, primarily in Oklahoma and Arkansas, lost their eligibility during 2011 due to meeting either time or payout thresholds stipulated in Oklahoma and Arkansas production tax laws.

Exploration Costs

Exploration costs were $1,025,542 in 2011 compared to $1,583,773 in 2010, a $558,231 decrease. During 2011, leasehold impairment and expired leasehold totaled $482,491 compared to $1,191,598 during 2010, a $709,107 decrease. The decline was driven by lower provisions for expected lease expirations in 2011, as compared to 2010. Charges on two exploratory dry holes totaled $543,051 during 2011; whereas, in 2010 the Company incurred minor exploratory dry hole costs totaling $4,541. During 2010, $387,634 was charged to exploration costs related to geological and geophysical costs paid upon the execution of a joint exploration agreement with a privately held independent operator to explore for oil in eastern Oklahoma.

Depreciation, Depletion and Amortization (DD&A)

Total DD&A decreased $4,509,935 or 24% in 2011, while DD&A per Mcfe decreased to $1.65 in 2011, as compared to $2.16 in 2010. The DD&A decrease was attributable to the $.51 decline in the DD&A rate per Mcfe. This rate decline in 2011 was due to the positive performance revisions recognized in the reserves reported at September 30, 2010.

Provision for Impairment

The provision for impairment increased $1,122,547 in 2011, as compared to 2010. During 2011, impairment of $1,728,162 was recorded on nine small fields in Oklahoma and Texas. These fields had few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions, or when a newly completed well with little production history is added to one of these fields. On one of these fields, a new material well began production on September 27, 2011. The well's early production was significantly impacted by the recovery of large volumes of water utilized in the fracture treatment. Since the well's early production had been low, while at the same time producing large volumes of load water, the calculated reserves and future net cash flows were calculated to be significantly less than was previously attributed to the well, resulting in a material impairment to the field of $590,629. Wells such as this are subject to performance revisions going forward as more is known of their production history and pattern. During the 2010 period, impairment of $605,615 was recorded on six small fields.

Included in the 2011 total above, was an impairment charge of $716,448 on the Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma. The first well was drilled and completed during the first quarter of 2011 and is currently producing commercial quantities of oil and natural gas. As of September 30, 2011, this well had a net book value of $503,960 after impairment. Costs on this well were extraordinarily high due to this well being the first and only horizontal well drilled in the field.

Loss (Gain) on Asset Sales, Interest and Other

In 2010, the Company received $1,124,682 from the settlement of a lawsuit related to one well in western Oklahoma. No interest expense was incurred during 2011, compared to interest expense of $60,912 recorded in 2010.

General and Administrative Costs (G&A)

G&A increased $400,164 or 7% in 2011. The increase was primarily related to increases in the following expense categories: personnel $346,331; Board fees $92,674; computer consulting fees $20,000; and reservoir engineering fees $71,000. The above were partially offset by a decrease in legal fees of $228,837 in 2011. The increase in 2011 personnel related expenses was the result of annual increases in salaries and bonuses totaling approximately $113,000, a restricted stock expense increase of $140,454, a rise in employee insurance costs of $22,713 and higher ESOP expense of $20,220. The increase in Board fees resulted from the addition of one director in May 2010 (resulting in partial year retainer and meeting fees during 2010, but a full year's fees during 2011) combined with increases in annual retainer fees and meeting fees paid to directors during 2011.

Non-recurring legal fees of approximately $230,000 were expensed during 2010 related to a lawsuit on one well in western Oklahoma and to the 2008 bankruptcy of SemGroup, L.P., which owed the Company for crude oil they had purchased.

Provision (Benefit) for Income Taxes

The 2011 provision for income taxes of $3,192,000 was based on a pre-tax income of $11,685,912, as compared to a provision for income taxes of $4,901,000 in 2010, based on a pre-tax income of $16,320,690. Income taxes in 2010 were reduced by the removal of the $278,000 valuation allowance on Oklahoma NOLs which reduced the effective tax rate by 2%. The effective tax rate for 2011 was 27%, compared to an effective tax rate for 2010 of 30%. The Company's utilization of excess percentage depletion (which is a permanent tax benefit) decreases the provision for income taxes. The benefit of excess percentage depletion is not directly related to the amount of recorded income or loss. Accordingly, in cases where the recorded income or loss is relatively small, the proportional effect of the excess percentage depletion on the effective tax rate may become significant.

LIQUIDITY AND CAPITAL RESOURCES

At September 30, 2012, the Company had positive working capital of $3,995,103, as compared to positive working capital of $7,314,096 at September 30, 2011.

Liquidity

Cash and cash equivalents were $1,984,099 as of September 30, 2012, compared to
$3,506,999 at September 30, 2011, a decrease of $1,522,900. Cash flows for the
12 months ended September 30 are summarized as follows:

Net cash provided (used) by:



                                              2012                2011               Change
Operating activities                      $  25,371,195       $  29,283,929       $  (3,912,734 )
Investing activities                      $ (38,288,959 )     $ (27,200,816 )     $ (11,088,143 )
Financing activities                      $  11,394,864       $  (4,173,372 )     $  15,568,236

Increase (decrease) in cash and cash
equivalents                               $  (1,522,900 )     $  (2,090,259 )     $     567,359

Operating activities:

The decrease of $3,912,734 in cash provided by operating activities is primarily the effect of the following:

Decreased collections of oil, NGL and natural gas sales (net of withheld production taxes and handling fees) for the 2012 period compared to the 2011 period resulted in less cash provided by operating activities of $2,436,566.

Realized gains on derivative contracts decreased $1,676,652 in 2012, as compared to 2011.

Income tax payments in 2012 were $1,356,706 compared to payments of $2,584,172 in 2011, a decrease of $1,227,466.

Cash expenditures for lease operating expenses (other than handling fees) increased $841,408 in 2012 compared to 2011.

Expenditures for G&A, interest and other expenses during 2012 increased . . .