The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 2012 (the "Form 10-K"), along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K. Any terms used but not defined herein have the same meaning given to them in the Form 10-K.

This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words "plan," "expect," "project," "estimate," "assume," "believe," "anticipate," "intend," "budget," "forecast," "predict" and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 2012 Annual Report on Form 10-K for the year ended June 30, 2012 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.

We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation.

Executive Overview

General

We are a petroleum company engaged primarily in the acquisition, exploitation and development of properties for the production of crude oil and natural gas, onshore in the United States. We acquire known, underdeveloped oil and natural gas resources and exploit them through the application of capital, sound engineering and modern technology to increase production, ultimate recoveries, or both.

We are focused on increasing underlying net asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain financial control of our assets for the benefit of our shareholders, including approximately 24% beneficially owned by all of our directors, officers and employees.

Our strategy is intended to generate scalable, low unit cost, development and re-development opportunities that minimize or eliminate exploration risks. These opportunities involve the application of modern technology, our own proprietary technology and our specific expertise in overlooked areas of the United States.

The assets we exploit currently fit into three types of project opportunities:

† Enhanced Oil Recovery (EOR),

† Bypassed Primary Resources, and

† Unconventional Reservoir Development.

We expect to fund our base fiscal 2013 development plan from working capital, with any increases to the base plan funded out of working capital, net cash flows from our properties and appropriate financing vehicles, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Highlights for our Second Quarter Fiscal 2013 and Project Update

"Q2-13" & "current quarter" is the three months ended December 31, 2012, the company's 2nd quarter of fiscal 2013.

"Q1-13" & "prior quarter" and "sequential" prior quarter is the three months ended September 30, 2012, the company's 1st quarter of fiscal 2013.

"Q2-12" & "year-ago quarter" is the three months ended December 31, 2011, the company's 2nd quarter of fiscal 2012.

Operations

† Q2-13 posted record earnings per share from recurring operations*, increasing 81% sequentially and 42% over the year-ago quarter. Increases were largely driven by higher crude oil volumes, partially offset by declining prices compared to the year-ago quarter.

† Revenues set an all-time record, increasing 32% sequentially and 22% over the year-ago quarter. Crude oil volumes increased 34% sequentially and 39% over the year-ago quarter, while crude prices were unchanged sequentially and 9% less than the year-ago quarter.

† Record crude oil volumes increased to 82% of total volumes from 73% in the prior quarter and 72% in the year-ago quarter. Including NGL's, liquids volumes were 85% of total volumes, compared to 80% in the prior quarter and 78% in the year-ago quarter.

† Field margins increased 33% sequentially and 24% over the year-ago quarter to $4.8 million. On a BOE basis, field margins increased 11% sequentially and 1% over the year-ago quarter to $76/BOE.

Projects

Delhi EOR Project - Northeast Louisiana

† Delhi Field sales volumes increased 36% over the prior quarter and 39% over the year-ago quarter to a record 509 BOPD net to our 7.4% royalty interest (6,872 gross BOPD). Sequential and comparable year-ago improvements were due to record high oil production in response to CO2 injections across a larger part of the field. Sequential improvement also resulted from restoring production volumes that were cut back by the operator during most of the first fiscal quarter due to high ambient temperatures that limited the plant's ability to recycle CO2 for re-injection. Continued lower ambient temperatures that began in September 2012 remedied the issue in the near term, while additional cooling capacity is expected to be installed by the operator before the resumption of hot weather next summer.

† Record Delhi oil production is currently exceeding the projected level in our D&M June 2012 reserve report, potentially impacting the working interest reversion date previously estimated for late calendar 2013. At reversion, our net revenue interest will more than triple from 7.4% to 26.5%, while our cost bearing interest will increase from 0% to 23.9%. The D&M report projects a steady increase in production to approximately 11,800 gross BOPD by late 2017.

† Realized oil prices at Delhi were sequentially unchanged and 9% lower from the year-ago quarter, averaging $104.43/BO in the current quarter. Realized prices were $103.78/BO in the previous quarter and $115.07 in the year-ago quarter.

† Delhi's LLS pricing continues to command a premium. Realized Delhi prices were 16%, 12% and 24% higher than average realized oil prices in our other fields during the current, previous and year-ago quarters, respectively.

2013 development revised. Calendar 2013 capital expenditures were recently refocused by the operator to further develop the western half of the Field where the flood has already been installed. The operator is currently remapping the field reservoirs to incorporate extensive 3-D seismic evaluation, and we believe this work may quantify upside potential in the Field not reflected in the June 2012 reserves.

Mississippian Lime - Kay County, OK

† Initial Development. We completed the drilling and hydraulic fracturing of the Sneath #1H horizontal production well and began dewatering operations at the end of October 2012. The Hendrickson #1H horizontal well was similarly completed and dewatering operations began at the end of November. These wells are the first two of 114 gross probable drilling locations assigned by our independent reservoir engineer. We own a 45% working interest in the Sneath and a 36.6% working interest in the Hendrickson.

† Mississippian Lime Background. Our play targets a limestone (carbonate) formation on the east flank of the Nemaha Ridge in central Kay County, OK, an area considered oilier and shallower than the west side of the Ridge. Historically, both sides of the Ridge have experienced considerable vertical well development over several decades that defines the formation, while current development utilizes horizontal drilling and staged hydraulic fracture completions to increase productivity, ultimate recoveries and return on investment.

In our general area, we believe the Mississippian Limestone is a highly layered, fractured carbonate, typically with the fractures containing salt water and the matrix porosity containing hydrocarbons. In order to produce the hydrocarbons, we believe that the water within the fractures first must be produced and reservoir pressure reduced. As this occurs, hydrocarbons (being a compressible fluid) can expand out of the matrix into the high permeability fractures and then to the producing well.

† Current drilling and completion practices. In our area, industry has largely drilled horizontal wells into the upper section of the Mississippi Lime and completed with multiple stage hydraulic fracture treatments. The Sneath and Hendrickson wells were completed in this fashion, both wells being horizontally drilled high in the formation and targeting the formation just below the "Cherty" top layers of the Mississippi Limestone, followed by 10-12 stages of hydraulic fracturing each.

† Necessary de-pressuring continues. Our Sneath and Hendrickson wells are exhibiting two characteristics we believe are prerequisites for a successful horizontal MS Lime producer, those being large initial volumes of salt water production, with minimal amounts of hydrocarbons, and declining bottom-hole pressures. Declining pressure suggests that the well's completion is contained within the target formation, as desired, and not connected to a water filled formation outside of the MS Lime, which is unfavorable. When declining pressure is present, larger amounts of salt water production suggest a potentially large, interconnected fracture system that provides access to the oil and gas reservoir, which is very favorable.

† Results to Date. Both wells began producing water, as expected, at rates of less than 3000 barrels per day. The operator has gradually increased dewatering rates and reservoir pressure has gradually declined as expected with small, but generally increasing, amounts of entrained oil and gas production. We subsequently learned from another operator of successful MS Lime wells that dewatering rates up to 10,000 barrels per day for an extended period are not unusual in our prospect area. Accordingly, our operator is further increasing dewatering rates to match best practices in the play. We are cautiously encouraged by the high water production rates entrained with some hydrocarbons, and steady but slow pressure decline, that suggest, but do not guarantee, our wells are connected to a large and contained fracture system within the MS Lime hydrocarbon bearing reservoir.

† We patiently wait and watch before allocating more capital. Our joint venture agreement with Orion Exploration initially called for the drilling of at least six gross wells by mid-April 2013. Due to the longer than expected dewatering and depressuring phase we are experiencing with the Sneath and Hendrickson wells, we expect to delay the beginning of additional drilling until later this fiscal year, pending results of those first two wells, with significant development drilling projected for Fiscal 2014.

GARP ®

† Our two commercial joint venture demonstrations on 3 wells in the Giddings Field continue to prove our patented technology. Commercialization efforts for GARP®, our artificial lift technology, continue under the corporate name NGS Technologies, with fulltime staff dedicated to the business. We reached tentative agreement to add one well to one of the previous joint ventures. While discussions continue with the second joint venture partner, we are in discussions with other operators to apply GARP® in oil and gas, horizontal and certain types of vertical wells in other Texas fields.

† Efforts expanded through property acquisitions. As applications to date continue to demonstrate the effectiveness of our technology, we recently began a program to acquire abandoned wells that offer good potential for renewed production utilizing our technology.

Other Fields

† Two sales of noncore assets in the Giddings Field were completed during the quarter, including a portion of our producing assets and most of our undeveloped reserves in the Giddings Field. Consistent with our election to divest noncore assets in order to better focus capital and staff on projects with higher near term value potential, we initiated a formal sales process for our nonGARP® assets in the Giddings Field in Texas. Two Giddings Field asset sales were completed during Q2-13, including most of our non-GARP® production and undeveloped reserves in the Giddings Field. The combined adjusted sales price was approximately $3.1 million before transaction costs, plus contingent payments based on future drilling activity. The larger sale for $2.8 million was completed December 24th, while the smaller sale was completed in early November. Accordingly, Q2-13 results included most of the production, revenue and operating expense for the divested assets. Had the divestments been completed at the beginning of the quarter, net production in the Giddings Field would have been reduced by 75%, or 125 net BOE per day, to 42 net BOE per day. Similarly, approximately $400,000 of revenue, $145,000 of direct well expense (using the company's average $5.24/BOE depletion rate) and $255,000 of pre-tax well income ($22/BOE) would have been absent in the current quarter's results. The divested properties were high in natural gas and NGL content, averaging 80% of production volumes in the current quarter, and included approximately 350 MBOE of proved developed reserves and 1.8 MMBOE of proved undeveloped reserves as of June 30, 2012. Sale proceeds and staff are already being redeployed to our Mississippian Lime and GARP® projects. The remaining noncore assets in the Giddings Field are being offered for sale, excluding certain wells in which our GARP® technology has been installed, and excluding our minor royalty and reversionary interests in the Woodbine play in northern Grimes County.

Liquidity and Capital Resources

At December 31, 2012, our working capital was $18 million, compared to working capital of $11.7 million at June 30, 2012. The $6.3 million increase in working capital since June 30, 2012 was due primarily to increases of $3.6 million in cash and $0.8 million in accounts receivable together with decreases of $1.8 million in due joint interest partner and $0.4 million in accrued compensation.

Cash Flows from Operating Activities

For the six months ended December 31, 2012, cash flows provided by operating activities were $5.0 million, reflecting $6.0 million provided by operations before $1.0 million was used in working capital. Of the $6.0 million provided before working capital changes, $3.1 million was due to net income and $2.9 million was due primarily to non-cash expenses.

For the six months ended December 31, 2011, $4.3 million of cash flows was provided by operating activities, reflecting $5.1 million provided by operations before $0.8 million was used in working capital. Of the $5.1 million provided before working capital changes, $2.6 million was due to net income and $2.5 million was attributable primarily to non-cash expenses.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2012 was $4.0 million. Development activities were predominantly in the Mississippi Lime, where one salt water disposal well and two producer wells were completed. In Giddings, expenditures were centered on installing GARP® on a fourth commercial demonstration well. An inflow of $3.1 million was received for proceeds from the sales of a portion of its Giddings exploration and production properties.

Cash paid for oil and gas capital expenditures during the six months ended December 31, 2011, was $1.5 million, primarily for a work over on the Dodd well in Grimes County and the drilling of four new wells in the Lopez Field in South Texas.

Oil and gas capital expenditures incurred were $3.6 million and $2.0 million, respectively, for the six months ended December 31, 2012 and 2011. These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for changes in accounts payable and amounts owed to joint venture partners for capital expenditures as represented in the supplemental information.

Cash Flows from Financing Activities

In the six months ended December 31, 2012, we paid preferred dividends of $0.3 million.

During the six months ended December 31, 2011, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A perpetual preferred stock after all offering costs and we paid $0.3 million of dividends thereon.

Capital Budget

Our approved fiscal 2013 Base Plan provides for up to $10 million of capital expenditures. Due to the delay in drilling additional Mississippian Lime wells, a substantial portion of the 2013 Plan is likely to carry over into Fiscal 2014, and the remaining balance of expected Fiscal 2013 capital expenditures can be funded from our existing working capital of $18.1 million at December 31, 2012. We expect to fund any increases over the fiscal 2013 Base Plan out of working capital, internally generated funds from operations, joint ventures, project financing, selective divestments of noncore assets or other appropriate financings, including possible additional issuances of our Series A perpetual non-convertible preferred stock.

Results of Operations

Three month period ended December 31, 2012 and 2011

The following table sets forth certain financial information with respect to our oil and natural gas operations:

                                       Three Months Ended
                                          December 31,                              %
                                      2012           2011         Variance       Change

Sales Volumes, net to the
Company:

Crude oil (Bbl)                         52,270         37,514         14,756         39.3 %

NGLs (Bbl)                               2,378          3,145           (767 )      (24.4 )%

Natural gas (Mcf)                       56,210         69,880        (13,670 )      (19.6 )%
Crude oil, NGLs and natural gas
(BOE)                                   64,016         52,306         11,710         22.4 %

Revenue data:

Crude oil                          $ 5,379,399    $ 4,231,201    $ 1,148,198         27.1 %

NGLs                                    86,556        182,971        (96,415 )      (52.7 )%

Natural gas                            182,103        232,530        (50,427 )      (21.7 )%
Total revenues                     $ 5,648,058    $ 4,646,702    $ 1,001,356         21.5 %

Average price:
Crude oil (per Bbl)                $    102.92    $    112.79    $     (9.87 )       (8.8 )%
NGLs (per Bbl)                           36.40          58.18         (21.78 )      (37.4 )%
Natural gas (per Mcf)                     3.24           3.33          (0.09 )       (2.7 )%
Crude oil, NGLs and natural gas
(per BOE)                          $     88.23    $     88.84    $     (0.61 )       (0.7 )%

Expenses (per BOE)
Lease operating expenses           $      6.55    $      7.89    $     (1.34 )      (17.0 )%
Production taxes                   $      0.33    $      0.36    $     (0.03 )       (8.3 )%
Depletion expense on oil and
natural gas properties (a)         $      5.24    $      5.20    $      0.04          0.8 %

Net Income Available to Common Shareholders. For the three months ended December 31, 2012, we generated net income of $1,790,696, or $0.06 per diluted share, (which includes $393,579 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $5,648,058. This compares to a net income of $1,259,950, or $0.04 per diluted share, (which includes $354,871 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,646,702 for the year-ago quarter. This increase in net income is primarily due to higher oil revenue partially offset by increased operating expenses. Additional details of the components of net income are explained in greater detail below.

Sales Volumes. Crude oil, NGLs, and natural gas sales volumes, net to our interest, for the three months ended December 31, 2012 increased 22.4% to 64,016 BOE's compared to 52,306 BOE's for the year-ago quarter. This 11,710 volume increase primarily reflects production and sales volumes increases in Delhi and South Texas fields, partially offset by a decrease in our Giddings properties reflecting a decrease in natural gas volume. Our crude oil sales volumes for the current quarter include 46,815 from our interests in Delhi and 5,455 barrels from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 33,698 barrels from our interests in Delhi and 3,816 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the three months ended December 31, 2012 and 2011, all from the Giddings Field, and declined 24% to 2,378 barrels. Current quarter natural gas volumes, virtually all produced at Giddings, decreased 20% to 56,210 mcf from 69,880 in the year-ago quarter. For the current quarter, there was no gas production from our now shut in Woodford properties that produced 1,256 mcf during the year-ago quarter.

Petroleum Revenues. Crude oil, NGL and natural gas revenues totaling $5.6 million for the current quarter increased $1.0 million, or 22%, from $4.6 million in the year-ago quarter due to 22% higher sales volumes with virtually no change in price. Prices per BOE were $88.23 and $88.84 respectively, for the current and year-ago quarter.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes for the current quarter increased $8,996 or 2%, to $440,191 compared to the year-ago quarter. This increase is principally due to increased expenses at the Mississippi Lime field, where three wells were completed during the current quarter, and the Giddings field, partially offset by lower expenses at the Lopez and Woodford fields. Lease operating expense and production tax per barrel of oil equivalent decreased 17% from $8.24 per BOE during the year-ago quarter to $6.88 per BOE in the current quarter.

General and Administrative Expenses ("G&A"). G&A expenses increased 22% to $1.8 million during the three months ended December 31, 2012 from $1.5 million in the year-ago quarter. The increase reflects $96,000 for higher bonus and other personnel costs, $72,000 of transaction expenses related to recent oil and gas property sales, increased legal and litigation expenses of $65,000 and $40,000 for board of director fees. Stock-based compensation was $393,579 (22% of total G&A) for the current quarter compared to $354,871 (24% of total G&A) for the year-ago quarter. Non-cash stock-based compensation is an integral part of total staff compensation utilized to recruit quality staff from other, more established companies and retain staff and, as a result, likely will continue to be a significant component of our G&A costs.

Depreciation, Depletion & Amortization Expense ("DD&A"). DD&A increased by 25% to $350,119 for the three months ended December 31, 2012, compared to $280,795 for the year-ago quarter. This change was principally due to a 22% volume increase. The current quarter's depletion rate was $5.24 compared to $5.20 in the year-ago quarter.

Six month period ended December 31, 2012 and 2011

The following table sets forth certain financial information with respect to our oil and natural gas operations:

                                        Six Months Ended
                                          December 31,                              %
                                      2012           2011         Variance       Change

Sales Volumes, net to the
Company:

Crude oil (Bbl)                         91,352         70,674         20,678         29.3 %

NGLs (Bbl)                               5,759          6,666           (907 )      (13.6 )%

Natural gas (Mcf)                      122,079        130,597         (8,518 )       (6.5 )%
Crude oil, NGLs and natural gas
(BOE)                                  117,457         99,106         18,351         18.5 %

Revenue data:

Crude oil                          $ 9,384,821    $ 7,679,796    $ 1,705,025         22.2 %

NGLs                                   206,167        371,426       (165,259 )      (44.5 )%

Natural gas                            348,616        480,336       (131,720 )      (27.4 )%
Total revenues                     $ 9,939,604    $ 8,531,558    $ 1,408,046         16.5 %

Average price:
Crude oil (per Bbl)                $    102.73    $    108.67    $     (5.93 )       (5.5 )%
NGLs (per Bbl)                           35.80          55.72         (19.92 )      (35.8 )%
Natural gas (per Mcf)                     2.86           3.68          (0.82 )      (22.2 )%
Crude oil, NGLs and natural gas
(per BOE)                          $     84.62    $     86.09    $     (1.47 )       (1.7 )%

Expenses (per BOE)
Lease operating expenses           $      6.26    $      6.21    $      0.05          0.8 %
Production taxes                   $      0.36    $      0.33    $      0.03          9.1 %
Depletion expense on oil and
natural gas properties (a)         $      5.28    $      5.06    $      0.22          4.3 %