CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain of the matters discussed under the captions "Business and Properties," "Legal Proceedings," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and elsewhere in this annual report may constitute "forward-looking" statements for purposes of the Securities Act of 1933, and the Securities Exchange Act of 1934 and, as such, may involve known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. When used in this report, the words "anticipates," "estimates," "plans," "believes," "continues," "expects," "projections," "forecasts," "intends," "may," "might," "could," "should," and similar expressions are intended to be among the statements that identify forward-looking statements. Various factors could cause the actual results, performance or achievements to differ materially from our expectations. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements disclosed in this annual report ("Cautionary Statements"), including, without limitation, those statements made in conjunction with the forward-looking statements included under the captions identified above and otherwise herein. All written and oral forward-looking statements attributable to us are qualified in their entirety by the Cautionary Statements. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law and you are cautioned not to place undue reliance on any forward-looking statement.

Overview

Introduction

We are an independent oil and natural gas company. Our strategy is to exploit our current undeveloped reserves and acquire, where economically prudent, assets suitable for enhanced oil recovery at a low cost. We intend to convert our proved undeveloped and/or unproved reserves into proved producing reserves by applying water, gas and/or chemical flooding and other EOR techniques. Our assets are located onshore U.S. in Texas, New Mexico and Oklahoma.

During our first three years of operations, our primary objective was to achieve growth through acquiring existing, mature crude oil and natural gas fields. The last two years we have focused on building the infrastructure and commencing waterflood operations in our two largest properties, Panhandle and Cato. These development activities are more clearly described below under "Drilling Capital Development and Operating Activities Update."

We believe our portfolio of crude oil and natural gas properties provides opportunities to apply our operational strategy. Additionally, we will continue to evaluate acquisitions that are consistent with our operational strategy.

Overall estimated proved oil and natural gas reserves decreased by 4.1 MMBOE, or 7.7%, to 49.1 MMBOE as of June 30, 2009, as compared to 53.2 MMBOE as of June 30, 2008. Our June 30, 2009 proved reserves of 49.1 MMBOE, were comprised 7.7 MMBOE of PDP, 2.4 MMBOE of PDNP, and 39.0 MMBOE of PUD. Crude oil reserves accounted for 79% of our total reserves at June 30, 2009. Additional detail of our proved reserves is presented in "Items 1 and 2 Business and Properties-Proved Reserves."

At our Cato Properties, we added approximately 2,623 MBOE of new reserves in extensions and discoveries due to better than expected initial waterflood response in the Phase I area of the project. Cato's production increased from roughly 200 BOEPD to over 400 BOEPD as injection into the waterflood pattern commenced in the 19 injection wells and direct crude oil production increases occurred in 29 pattern producing wells. Ultimately, this led to the conversion of approximately 1,181 MBOE of PUD to PDP reserves. Approximately 724 MBOE of prior year PUD to PDP reserve conversions at our Panhandle Properties waterflood were reclassified back to PUD based upon actual response realized through June 30, 2009 (which has been slower than originally estimated). Offsetting the positive extensions and discoveries at our Cato Properties (2,623 MBOE) were the divestitures of our Corsicana and Pantwist Properties, as discussed in Note 8 to our Consolidated Financial Statements, totaling 2,554 MBOE, the impairment of 2,269 MBOE at our Desdemona Barnett Shale Properties due to the decline in commodity prices during the year ended June 30, 2009 (the "2009 Fiscal Year"), as discussed in Note 14 to our Consolidated Financial Statements, and other revisions primarily driven by the decline in commodity prices and forecast changes which changed the estimated economic lives of our assets (1,435 MBOE). A summary of the year-on-year changes to our proved reserves is shown in the following table:

                 Summary of Changes in Proved Reserves     MBOE
                 Reserves at June 30, 2008                 53,189
                 Extensions and Discoveries                 2,623
                 Forecast Revisions                        (1,435 )
                 Financial Revisions (impairment)          (2,269 )
                 Sales of Assets                           (2,554 )
                 Production                                  (457 )

                 Reserves at June 30, 2009                 49,097

Reserves were estimated using crude oil and natural gas prices and production and development costs in effect on June 30, 2009. On June 30, 2009, crude oil and natural gas prices were $69.89 per barrel and $3.71 per MMBtu, respectively. The values reported may not necessarily reflect the fair market value of the reserves.

Drilling Capital Development and Operating Activities Update

For the 2009 Fiscal Year, we incurred $52.6 million of capital expenditures ($56.2 million spent) to develop our existing fields. The $3.6 million difference between the $52.6 million incurred and the $56.2 million spent is primarily timing differences related to expenditures incurred during the 2008 Fiscal Year and the payments for those capital expenditures during the 2008 Fiscal Year. At June 30, 2009, we had accrued capital expenditures of $1.9 million that were paid during the 2010 Fiscal Year.

The goal for the 2009 Fiscal Year was to convert existing PUD reserves to PDP reserves and increase production. The company drilled and completed 18 wells: four ASP observation wells at the Nowata Field, five wells in the Panhandle Field (four Harvey Unit waterflood development wells and

one Cockrell ranch infill well), and nine wells at Cato (six waterflood producers and three waterflood injectors).

For the year ending June 30, 2010 (the "2010 Fiscal Year"), our Board of Directors has approved a capital development budget of $13.9 million as follows:

º •
º $5.4 million at the Cato Properties;

º •
º $7.8 million at the Panhandle Properties; and

º •
º $0.7 million at the remaining Properties.

Our 2010 Fiscal Year capital development program does not include the drilling of new wells. The financing of our capital expenditures is discussed below under "Liquidity and Capital Resources." The following reviews our capital development activity during the 2009 Fiscal Year and planned activity during the 2010 Fiscal Year.

Cato Properties. Proved reserves as of June 30, 2009 attributable to the Cato Properties were 16.0 MMBOE, of which 1.9 MMBOE were PDP, 0.5 MMBOE were PDNP and 13.6 MMBOE were PUD. These properties include roughly 20,000 acres across three fields in Chavez and Roosevelt Counties, New Mexico. The prime asset is the roughly 15,000 acre Cato Field, which produces from the historically prolific San Andres formation, which has been successfully waterflooded in the Permian Basin for over 30 years. There were two successful waterflood pilots conducted in the field in the 1970's by Shell and Amoco.

We have experienced encouraging initial waterflood response at the Cato Field. The first phase of development (Phase I) includes 19 water injection wells ("injectors") and 29 producing wells ("producers"). Once the injection permits were received in September 2008, we began injecting 7,000 barrels of water per day ("BWIPD"). As we continued injecting water into the field, waterflood production has grown from five producers during December 2008 offsetting a prior Amoco waterflood pilot to 29 producers experiencing production as of June 30, 2009. During January 2009, we increased the injection rate to approximately 12,000 BWIPD. During February 2009, we expanded the footprint of Phase 1 of the Cato waterflood from 550 to roughly 640 acres and announced an increased capital expenditures budget to $49.8 million, of which $27.0 million was intended for the Cato Properties. We currently have ten sub-pumps operating in the field and plan to install additional sub-pumps to support increasing production and corresponding higher levels of fluid production. The sustained production gains at the Cato Properties are the result of an earlier than expected waterflood production response.

The 2009 Fiscal Year drilling program at Cato, which comprised drilling nine wells (six waterflood producers and three waterflood injectors), was completed in October 2008. Normal production declines were experienced outside of the Phase I waterflooded area, but these declines were more than offset by increased production from the waterflood.

At June 30, 2009, we booked proved reserves extensions and discoveries at Cato as Phase I results were better than initially expected. Field production increased from roughly 200 BOEPD to over 400 BOEPD after we commenced injection into 19 injection wells of the waterflood pattern which led to increased crude oil production in 29 producers. When we increased the waterflood footprint from 550 acres to 640 acres, the rate of water injection per acre decreased leading to a temporary decrease in production. We added approximately 2.6 MMBOE of new reserves based on the responses experienced through June 30, 2009. Additionally,
1.1 MMBOE of PUD reserves were reclassified to PDP reserves as a result of the responses experienced in Phase I. We plan to increase the number of injection wells and enlarge the waterflood footprint in the 2010 Fiscal Year. Net production at Cato averaged 316 BOEPD in June 2009.

Panhandle Properties. Proved reserves as of June 30, 2009 attributable to the Panhandle Properties were 28.9 MMBOE, of which 3.5 MMBOE were PDP and 25.4 MMBOE were PUD. These

properties include roughly 20,000 acres in Carson, Gray and Hutchinson Counties, Texas. They are delineated in thirty-three leases-the largest of which are Cockrell Ranch, Pond, Harvey, Mobil Fee, Cooper, Block and Schafer Ranch.

During the quarter ended June 30, 2009, we maintained our average daily water injection rate at the Cockrell Ranch Unit (our first Panhandle Properties waterflood) at roughly 75,000 barrels per day. This resulted in increasing our average daily production at the Cockrell Ranch Unit from approximately 80-100 net BOEPD between June and December 2008 to maintaining 100-120 net BOEPD production through June 30, 2009. While crude oil production continues to increase at Cockrell Ranch, the gains are below our expectations. Based on actual performance of the waterflood through June 30, 2009, we reclassified 724 MBOE of PDP reserves back to PUD at June 30, 2009. After this reclassification, the remaining amount of the prior year conversion of PUD to PDP reserves is 674 MBOE. We have retained Netherland, Sewell & Associates, Inc. to assist us with reservoir analysis and simulation work at Cockrell Ranch. We are establishing a controlled injection pattern to gauge the effects of optimizing water injection into the highest remaining crude oil saturation intervals of the Brown Dolomite formation (our target producing formation). The result of this field observation, coupled with rigorous reservoir simulation modeling, should allow us to move the project forward into a more predicable production response profile. Moreover, the analysis will improve our planning of future capital development programs for the remaining Panhandle Properties leases. Waterflood production will be curtailed from the previously reported 100-120 BOEPD to 60-80 BOEPD during the test period. As of the end of September 2009, all previously curtailed production will have been restored.

Our original 2009 Fiscal Year waterflood capital development plan for the Panhandle Properties included six separate mini-floods on reduced well spacing to enable us to accelerate field development. Tighter well-spacing and smaller development patterns should accelerate permitting and response times, allowing a larger development footprint over a greater acreage position. The amended 2009 capital development plan provided for the development of only one mini-flood phase through June 2009 (the Harvey Unit). The Harvey Unit had its waterflood permit application approved by the Texas Railroad Commission on October 20, 2008. The Harvey Unit mini-flood consists of six injection wells and 13 producing wells (which required four new wells to be drilled among the existing wells at the field). The drilling of the four replacement injector wells was completed on January 5, 2009, thus completing the mini-flood pattern. We initiated injection at the Harvey Unit on March 30, 2009 at a rate of 2,500 barrels per day. During the 2009 Fiscal Year, we received approval of the mini-flood permits at the Pond Lease and at the Olive-Cooper Lease. As a result of the reduction in our capital plan and a focus on our Cato Properties, we slowed the filing of Panhandle mini-flood permits. We now expect to file the appropriate waterflood permits for the remaining three mini-floods by the quarter ending December 31, 2009. Net production at the Panhandle Properties for June 2009 was 627 BOEPD.

Desdemona Properties. Proved reserves as of June 30, 2009 attributable to the Desdemona Properties were 1.4 MMBOE, of which 0.1 MMBOE were PDP and 1.3 MMBOE were PDNP. Approximately 1.3 MMBOE of the reserves were attributable to the Duke Sand reservoir.

Desdemona Properties-Waterflood. We drilled and completed 11 required replacement wells to initiate the development of the Duke Sand Waterflood on the Desdemona Properties during the 2008 Fiscal Year having procured and completed infrastructure of the waterflood facilities in September 2007. Water injection commenced in September 2007. Through June 30, 2009, we have injected over 1.5 million barrels of water into a pilot location of the Duke Sand reservoir. The primary source of water for the waterflood was from our Barnett Shale natural gas wells. During July 2009, we shut-in our remaining Barnett Shale producing wells due to continued low natural gas prices. Accordingly, the source for water injection for our Duke Sand waterflood pilot ceased. Without a known economic source of water, we will not continue to defer expenditures associated with this waterflood. Therefore, we expensed $11.4 million during June 2009 for the aggregate deferred expenditures spent to implement this waterflood pilot, as discussed

in Note 9 to our Consolidated Financial Statements. We continue to believe that this reservoir is an excellent secondary and tertiary recovery candidate; however, we do not have current plans to recommence injection for the foreseeable future. We had no proved reserves for the Duke Sand Waterflood pilot project.

Desdemona Properties-Barnett Shale. We drilled and completed 15 vertical and 8 horizontal wells in the Barnett Shale during the 2007 and 2008 Fiscal Years. Due to the decline in natural gas commodity prices and based upon operating performance, there was uncertainty in the likelihood of developing PUDs associated with our Barnett Shale Properties. Therefore, during the quarter ended December 31, 2008, we recorded a $22.4 million pre-tax impairment to our Barnett Shale Properties and a $0.7 million pre-tax impairment to the goodwill associated with our subsidiary which holds the equity in our Barnett Shale Properties. During the quarter ended June 30, 2009, we recorded an additional $4.3 million pre-tax impairment to our Barnett Shale Properties as the forward outlook for natural gas prices continued to decline, as discussed in Note 9 to our Consolidated Financial Statements. During July 2009, we shut-in our Barnett Shale natural gas wells, and, based upon the current and near-term outlook of natural gas prices, we have no plans to return these wells to production in the foreseeable future.

Net production for June 2009 at the Desdemona Properties was 54 BOEPD. Based upon the previously discussed shut-in wells, the production rates are estimated to be 30-35 BOEPD for the foreseeable future.

Nowata Properties. Proved reserves as of June 30, 2009 attributable to the Nowata Properties were 1.5 MMBOE, all of which were PDP. Our ASP tertiary recovery pilot project has been in full operation since December 2007. Through June 30, 2009, we have injected approximately .40 PVI of ASP and polymer flush. We drilled and completed four observation wells in December 2008, to enable us to test flood-front results in the pilot project. We completed injecting of our Polymer flush during June 2009. We anticipate completing the full ASP Pilot performance analysis within the next three to six months, and we estimate additional completion costs to total $0.3 million. There are currently no proved reserves associated with the ASP Pilot. Net production for June 2009 at the Nowata Properties was 229 BOEPD.

Davenport Properties. Proved reserves as of June 30, 2009 attributable to the Davenport Properties were 1.3 MMBOE, of which 0.7 MMBOE were PDP and 0.6 MMBOE were PDNP. Net production at the Davenport Properties for June 2009 was 79 BOEPD.

Industry Conditions

We operate in a competitive environment for (i) acquiring properties,
(ii) marketing oil and natural gas and (iii) attracting trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. Some of our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and obtain capital for investment in the oil and natural gas industry.

We do believe significant acquisition opportunities exist and will continue to exist as major energy companies and larger independents continue to focus their attention and resources toward the discovery and development of large fields and smaller companies are faced with decreasing margins and access to capital.

Our Strategy

º •
º Exploit and Develop Existing Properties. We believe we have an attractive portfolio of assets to implement our business plan. We intend to add proved reserves to, and increase production from, our existing properties through the application of commonly used EOR technologies, including water, gas and chemical flooding and other techniques.

º •
º Acquire Strategic Assets. We seek to acquire low-cost assets with reserves suitable for EOR techniques in the onshore U.S. We will continue to target acquisitions that meet our engineering and operational standards in a financially prudent manner.

º •
º Drill Known Formations. Our portfolio is composed of mature fields with proved primary and/or secondary reserves, existing infrastructure and abundant technical information. Accordingly, our production growth is not dependent on wildcat exploration drilling of new formations and the high degree of speculation associated with making new discoveries, but the application of commonly used secondary and/or tertiary recovery methods to increase production and reserves.

EOR techniques involve significant capital investment and an extended period of time, generally a year or longer, until production increases. Generally, surfactant-polymer injection is regarded as more risky as compared to waterflood operations. Our ability to successfully convert PUD reserves to PDP reserves will be contingent upon our ability to obtain future financing and/or raise additional capital. Further, there are inherent uncertainties associated with the production of crude oil and natural gas, as well as price volatility. See "Item 1A.Risk Factors."

Liquidity and Capital Resources

Our primary sources of capital and liquidity have been issuance of securities, borrowings under our credit agreements, and cash flows from operating activities. These sources are discussed in greater detail below.

For the twelve months ended June 30, 2009, our primary sources of cash were receipts from the sale of crude oil and natural gas production, issuances of common stock, net borrowings under our credit agreements, sales of oil and gas properties, payments for in-the-money commodity derivative contracts, settlements from third parties and the W.O. Settlement pertaining to the Panhandle fire litigation as discussed in Note 17 to our Consolidated Financial Statements. Our cash receipts from sales are discussed in greater detail under "Results of Operations-Operating Revenues." The non-revenue sources of cash are discussed in greater detail below:

º •
º On July 1, 2008, we received net proceeds of $53.9 million from the issuance of 7.0 million shares of our common stock. The net proceeds were used to pay down long-term debt due under our senior credit agreement (See Note 4 to our Consolidated Financial Statements).

º •
º On October 1, 2008, we sold our wholly-owned subsidiary, Pantwist, LLC ("Pantwist"), for $42.7 million ($40.0 million net of closing adjustments of $2.1 million of discontinued operating income recorded in the first quarter of the 2009 Fiscal Year and $0.6 million in advisory fees-(See Note 8 to our Consolidated Financial Statements).

º •
º During October 2008, we sold certain uncovered "floor price" commodity derivative contracts covering July 2010 to December 2010 for $0.6 million to our counterparty, and during November 2008, we sold all remaining uncovered "floor price" commodity derivative contracts covering November 2008 through June 2010 for $2.6 million to our counterparty. We recorded a realized gain of $0.7 million and an unrealized gain of $1.3 million as a result of these transactions.

º •
º On October 31, 2008, an independent electrical contractor paid us $6.0 million (its full insurance policy limit) in exchange for a full release of any existing or future claims related to wildfires that began on March 12, 2006 in Carson County, Texas. The $6.0 million has been fully

expended to cover the settlements discussed in Note 17 to our Consolidated Financial Statements.

º •
º On December 2, 2008, we sold our interests in the Corsicana Properties for $0.3 million (See Note 8 to our Consolidated Financial Statements).

º •
º On December 17, 2008, we finalized new senior and subordinated credit facilities, as discussed in Note 6 to our Consolidated Financial Statements. For the senior credit facility, the initial and current borrowing base, based upon our proved reserves, is $60.0 million and has an outstanding balance of $46.2 million as of September 28, 2009. We have fully drawn the $15.0 million borrowing under the subordinated credit facility. Our two credit facilities are discussed in greater detail below.

During the twelve month period ended June 30, 2009, our cash outlays were primarily for:

º •
º Lease operating expense, general and administrative expenses, and the settlement and legal fees associated with the fire litigation claims, which are discussed in greater detail in Note 17 to our Consolidated Financial Statements and under "Results of Operations-Operating Expenses."

º •
º Capital expenditures, which are discussed in greater detail under "Drilling Capital Development and Operating Activities Update."

º •
º The repurchase of 22,948 shares of Series D Convertible Preferred Stock, including accrued and unpaid PIK dividends relating to such shares for approximately $10.4 million, which is discussed in greater detail in Note 5 to our Consolidated Financial Statements.

As discussed under "Drilling Capital Development and Operating Activities," we have $52.6 million of capital expenditures during the twelve month period ended June 30, 2009. $4.8 million of the incurred $52.6 million pertains to secondary and tertiary exploration activities (new projects where no secondary or tertiary reserves have previously been recorded). As of June 30, 2009, we had implemented one tertiary exploration project that has existing reserves associated with secondary recovery activities-the ASP tertiary recovery pilot project at the Nowata Properties. This project is considered exploratory as it entails more risk compared to our development activities where proved secondary or tertiary reserves exist since this project did not have proved tertiary reserves prior to its implementation. We estimate the crude oil price necessary to sustain the long-term economic viability of this project is approximately $45-$50 per barrel. This price could vary based on several factors, including actual recovery rates and chemical costs.

Liquidity

At June 30, 2009, we had cash and cash equivalents of $0.4 million and working capital of $0.3 million. Our working capital balance included a $5.0 million derivative current asset and a $1.4 million deferred tax current liability. For the year ended June 30, 2009, we had net income applicable to common stock of $7.9 million and a loss from operations of $59.0 million, including a $26.7 million impairment of long-lived assets (see Note 14 to our Consolidated Financial Statements), $11.4 million of exploration expense (see Note 9 to our Consolidated Financial Statements) and $6.6 million of legal and settlement expenses in connection with the Panhandle fire litigation (see Note 17 to our Consolidated Financial Statements). For the year ended June 30, 2009, our cash used in operations of $6.6 million was negatively impacted by $10.7 million of settlement payments, net of reimbursements, related to the resolution of the Panhandle fire litigation.

We depend on our credit agreements, as described in Note 6 to our Consolidated Financial Statements, to fund a portion of our operating and capital needs. Under our senior credit agreement, the initial and current borrowing base, based upon our proved reserves, is $60.0 million. At June 30, 2009, our remaining available borrowing capacity under the senior credit agreement was $19.3 million,

. . .