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EPM > SEC Filings for EPM > Form 10-Q on 10-May-2013All Recent SEC Filings

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Form 10-Q for EVOLUTION PETROLEUM CORP


10-May-2013

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

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 Third Quarter Fiscal 2013 and Project Update

"Q3-13" & "current quarter" is the three months ended March 31, 2013, the company's 3th quarter of fiscal 2013.

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

"Q3-12" & "year-ago quarter" is the three months ended March 31, 2012, the company's 3th quarter of fiscal 2012.


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Operations

† Q3-13 posted record earnings per share from recurring operations*, increasing 24% sequentially and 72% over the year-ago quarter. Increases were largely driven by the growth of crude oil's share of revenues, causing BOE prices to increase 21% sequentially and 24% over the year-ago quarter.

† Revenues set an all-time record, increasing 6% sequentially and 24% over the year-ago quarter despite the sale of producing properties in the Giddings Field in the prior quarter. Crude oil volumes increased 3% sequentially and 32% over the year-ago quarter, while crude prices were 8% higher sequentially and 1% less than the year-ago quarter.

† Record crude oil volumes increased to 95% of total product volumes, compared to 82% of volumes in the prior quarter and 72% in the year-ago quarter, and Louisiana Light Sweet ("LLS") priced volumes were an increasing proportion of total volumes reflecting the prior quarter sale of gassy properties in the Giddings Field. Including NGL's, liquids volumes were 97% of total volumes in the current quarter, compared to 85% in the prior quarter and 77% in the year-ago quarter.

† Field margins increased 7% sequentially and 35% over the year-ago quarter to $5.2 million. On a BOE basis, field margins (product revenue less lifting costs, severance tax, DD&A and asset retirement expense) increased 21% sequentially and 35% over the year-ago quarter to $92/BOE.



* Excludes the effect of a gain on an asset sale recorded in a fiscal year 2006.

Projects

Delhi EOR Project - Northeast Louisiana

† Delhi Field daily sales volumes increased 11% over the prior quarter and 40% over the year-ago quarter to a record 566 BOPD net to our 7.4% royalty interest (7,645 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 reflecting capital expenditures made during calendar 2011 and 2012.

† Record Delhi oil production is currently exceeding the projected level in our D&M June 2012 reserve report, potentially accelerating 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 production to increase to approximately 11,800 gross BOPD by late 2017.

† Realized oil prices at Delhi were 7% higher sequentially and 2% lower from the year-ago quarter, averaging $111.41/BO in the current quarter. Realized prices were $104.43/BO in the previous quarter and $113.47 in the year-ago quarter.

† Delhi's LLS pricing continued to command a narrowing premium. Realized Delhi prices were 13%, 16% and 20% 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 proposed by the operator now target further development of the western half of the Field where the flood has already been installed. The operator is finalizing new maps of the field reservoirs incorporating extensive 3-D seismic evaluation that has identified a more complex reservoir system, and the 2013 expenditures are intended to more efficiently develop the reservoirs. We believe the new maps may quantify a portion of the upside potential in the Field not reflected in the June 2012 reserves.

Mississippian Lime - Kay County, OK

† Initial Development. The operator completed the drilling and hydraulic fracturing and initiated dewatering of the Sneath #1H and Hendrickson #1H horizontal wells in the latter part of the prior quarter. These wells are the first two of 114 gross probable drilling locations assigned by our independent reservoir engineer. We own a 45% non-operating working interest in the Sneath and a 36.6% non-operating working interest in the Hendrickson, as well as a 45% working interest in a nearby salt water disposal well.


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† 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. The Sneath and Hendrickson wells were horizontally drilled by the joint venture operating partner in the middle of the formation followed by 10-12 stages of hydraulic fracturing each with the goal of fracturing the bulk of the formation matrix. The types of hydraulic fracturing utilized followed the best practices of industry in the play. At the time of drilling, we had limited information and drilling results for wells in our area, but did observe that the two wells drilled in our area with poor reported results were located low in the formation. In our area, horizontal wells reported by industry as successful have been drilled into the upper section of the Mississippi Lime.

† Results to Date. Our Sneath and Hendrickson wells exhibited two characteristics we believe are prerequisites for a successful horizontal MS Lime producer, those being a large initial rate of salt water production that suggests a large reservoir, and declining bottom-hole pressures that suggest the necessary depressurization is occurring that would release the desired oil and gas production. Both wells began producing water at rates of less than 3,000 barrels per day. The operator gradually increased dewatering rates and reservoir pressure declined as expected with small 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. However, to date we have not yet achieved our targeted oil and gas production rates and have been analyzing results in comparison to good and poor Mississippian Lime wells drilled by other operators. Based on this analysis, we have identified the major difference to be our laterals' location relatively 40-50 feet lower than the wells with reported good results.

† Next Step. Our joint venture agreement with Orion Exploration called for a drilling commitment of at least six gross wells by mid-April 2013, only three of which had been drilled (including the disposal well). As of April 17, 2013, that commitment had lapsed, leaving either party free to propose the drilling of additional wells within the area of mutual interest (AMI). Accordingly, we recently proposed the drilling of a third evaluation well in the AMI to more fully test the play and our leasehold by applying the information we have learned. Spudding is expected this summer. Also subsequent to the end of the current quarter, we elected to forego payment of the remaining $1.2 million balance of the original leasehold purchase cost and reduce our JV interest in the initial leasehold not yet drilled from 45% to 33.9%. Those funds will be redeployed to the drilling of the third producer well.

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 and a separate web site, www.GARPLIFT.COM, dedicated to the business. We reached 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. To date, we have acquired 684 net acres in this effort associated with one well and anticipated the first related installation in June 2013.

Other Fields

† Two sales of noncore assets in the Giddings Field were completed during the previous quarter, including a portion of our producing assets and most of our undeveloped reserves in the Giddings Field. The divested properties provided 10,534 BOE and $383,000 of revenue in Q2-13 and 13,743 BOE and $429,000 in the year-ago quarter.

† Other noncore assets in Giddings Field and South Texas are in discussions for divestment. The remaining nonGARP® properties in the Giddings Field are tentatively scheduled for sale during our Fiscal Fourth Quarter and we are considering the sale of our Lopez Field assets due to their long lead time for development.


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Liquidity and Capital Resources

At March 31, 2013, our working capital was $21.2 million, compared to working capital of $11.7 million at June 30, 2012. The $9.5 million increase in working capital since June 30, 2012 was due primarily to increases of $7.3 million in cash and $0.7 million in accounts receivable together with a decrease of $1.9 million in due joint interest partner.

Cash Flows from Operating Activities

For the nine months ended March 31, 2013, cash flows provided by operating activities were $9.1 million, reflecting $9.6 million provided by operations before $0.5 million was used in working capital. Of the $9.6 million provided before working capital changes, $5.5 million was due to net income, $2.1 million from non-cash expenses and $2.0 million from deferred income taxes.

For the nine months ended March 31, 2012, cash flows provided by operating activities were $7.3 million, reflecting $8.0 million provided by operations before $0.7 million was used in working capital. Of the $8.0 million provided, $4.0 million was attributable to net income, $2.0 million from non-cash expenses and $2.0 million from deferred income taxes.

Cash Flows from Investing Activities

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2013 was $4.4 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 our Giddings exploration and production properties. In December 2012, an expiring $0.25 million CD was rolled over beginning a new annual term.

Cash paid for oil and gas capital expenditures during the nine months ended March 31, 2012 was $2.7 million, primarily for development activities concentrated in the Lopez Field where four new wells were drilled with ancillary development in the Giddings Field, including a workover on the Dodd well and installation of our GARP® technology. During the nine months ended March 31, 2012, we received $0.1 million for the sale of a portion of our Woodbine lease rights. In December 2011, an expiring $0.25 million CD was rolled over commencing a new annual term.

Oil and gas capital expenditures incurred were $3.9 million and $2.6 million, respectively, for the nine months ended March 31, 2013 and 2012. 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 nine months ended March 31, 2013, we paid preferred dividends of $0.5 million.

During the nine months ended March 31, 2012, we received $6.9 million of net proceeds from the issuance of 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock after all offering costs and we paid $0.5 million of dividends thereon. In connection with the unsecured revolving credit agreement entered into February 2012, the company expended deferred loan costs of $159,494.

Capital Budget

Our approved fiscal 2013 Base Plan provided for up to $10 million of capital expenditures of which $3.9 million has been incurred in the nine months ended March 31, 2013. Due to the delay in drilling additional Mississippian Lime wells, a substantial portion of the 2013 Plan expenditures may carry over into fiscal 2014, but are elective. For fiscal year 2014, our estimated capital maintenance expenditures, which reflect anticipated Delhi post-reversion expenditures, can be funded from our existing working capital of $21.2 million at March 31, 2013, while additional elective capital expenditures may be funded by future internally generated funds from operations (including expanded post-reversion operating cash flows from Delhi), joint ventures, project financing, selective divestments of noncore assets or other appropriate financing vehicles we believe may available to us.


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Results of Operations

Three month period ended March 31, 2013 and 2012

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

                                       Three Months Ended
                                           March 31,                                %
                                      2013           2012         Variance       Change

Sales Volumes, net to the
Company:

Crude oil (Bbl)                         53,699         40,576         13,123         32.3 %

NGLs (Bbl)                                 857          3,044         (2,187 )      (71.8 )%

Natural gas (Mcf)                       10,743         76,244        (65,501 )      (85.9 )%
Crude oil, NGLs and natural gas
(BOE)                                   56,347         56,327             20          0.0 %

Revenue data:

Crude oil                          $ 5,947,015    $ 4,532,942    $ 1,414,073         31.2 %

NGLs                                    27,067        128,319       (101,252 )      (78.9 )%

Natural gas                             36,485        187,273       (150,788 )      (80.5 )%
Total revenues                     $ 6,010,567    $ 4,848,534    $ 1,162,033         24.0 %

Average price:
Crude oil (per Bbl)                $    110.75    $    111.71    $     (0.96 )       (0.9 )%
NGLs (per Bbl)                           31.58          42.15         (10.57 )      (25.1 )%
Natural gas (per Mcf)                     3.40           2.46           0.94         38.2 %
Crude oil, NGLs and natural gas
(per BOE)                          $    106.67    $     86.08    $     20.59         23.9 %

Expenses (per BOE)
Lease operating expenses           $      9.32    $     11.76    $     (2.44 )      (20.7 )%
Production taxes                   $      0.25    $      0.27    $     (0.02 )       (7.4 )%
Depletion expense on oil and
natural gas properties (a)         $      4.81    $      5.38    $     (0.57 )      (10.6 )%



(a) Excludes depreciation of office equipment, furniture and fixtures, and other assets of $10,305 and $10,242, for the three months ended March 31, 2013 and 2012, respectively.

Net Income Available to Common Shareholders. For the three months ended March 31, 2013, we generated net income of $2,228,467, or $0.07 per diluted share, (which includes $392,433 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $6,010,567. This compares to a net income of $1,299,525, or $0.04 per diluted share, (which includes $354,469 of non-cash stock-based compensation expense) on total oil and natural gas revenues of $4,848,534 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 March 31, 2013 were 56,347 BOE's compared to 56,327 BOE's for the year-ago quarter. Volume increases of 14,065 BOE at Delhi, 935 BOE at the Lopez Field and 682 BOE for Oklahoma were offset by a Giddings Field decrease of 15,662 BOE, of which 13,743 BOE of year-ago quarter volume were from properties that were divested in the second quarter of fiscal year 2013.

Our crude oil sales volumes for the current quarter include 50,951 barrels from our interests in Delhi and 2,748 barrels primarily from the Giddings and Lopez fields. Our crude oil sales volumes for the year-ago quarter included 36,886 barrels from our interests in Delhi and 3,690 barrels from our properties in the Giddings and Lopez fields. Our NGL volumes for the three months ended March 31, 2013 and 2012, primarily from the Giddings Field, declined 72% to 857 barrels, while natural gas volumes, virtually all produced at


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Giddings, decreased 86% to 11 MMCF from 76 MMCF in the year-ago quarter. Declines in NGL and natural gas volumes were largely attributable to producing properties we divested in late December 2012.

Petroleum Revenues. Crude oil, NGL and natural gas revenues totaling $6.0 million for the current quarter increased $1.2 million, or 24%, from $4.8 million in the year-ago quarter due to an increased proportion of higher value crude oil volumes. Accordingly, blended BOE prices increased to $107 from $86 in the year-ago quarter.

Lease Operating Expenses (including production severance taxes). Lease operating expenses and production taxes for the current quarter decreased $138,306 or 20%, to $539,320 compared to the year-ago quarter. This decrease is due to higher year-ago quarter Lopez Field expense due to then recently drilled wells and salt water disposal optimization, higher year-ago Giddings Field expenses, and higher year-ago Woodford expense for wells shut in fiscal 2013, partially offset by increased expenses for Mississippi Lime wells completed in fiscal 2013. Approximately, $102,000 of the total expense variance is attributable to Giddings properties sold in the second quarter of fiscal 2013. Lease operating expense and production tax per barrel of oil equivalent decreased 20% from $12.03 per BOE during the year-ago quarter to $9.57 per BOE in the current quarter.

General and Administrative Expenses ("G&A"). G&A expenses increased 14% to $1.8 million during the three months ended March 31, 2013 from $1.6 million in the year-ago quarter. The increase reflects $175,000 for higher bonus and other personnel costs, $38,000 for increased stock compensation, $26,000 for legal and litigation expenses and $26,000 for franchise taxes, partially offset by $52, 000 of lower consulting expense. Stock-based compensation was $392,433 (22% of total G&A) for the current quarter compared to $354,469 (23% 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 decreased by 11% to $281,306 for the three months ended March 31, 2013, compared to $316,665 for the year-ago quarter. This decrease was due to a decline in the per BOE amortization rate, reflecting the effect of the sale of properties in the second quarter of fiscal 2013. The current quarter's depletion rate was $4.81 compared to $5.38 in the year-ago quarter.

Nine month period ended March 31, 2013 and 2012

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

                                        Nine Months Ended
                                            March 31,                                 %
                                       2013            2012         Variance       Change

Sales Volumes, net to the
Company:

Crude oil (Bbl)                         145,051         111,250         33,801         30.4 %

NGLs (Bbl)                                6,616           9,711         (3,095 )      (31.9 )%

Natural gas (Mcf)                       132,822         206,841        (74,019 )      (35.8 )%
Crude oil, NGLs and natural gas
(BOE)                                   173,804         155,435         18,369         11.8 %

Revenue data:

Crude oil                          $ 15,331,836    $ 12,212,738    $ 3,119,098         25.5 %

NGLs                                    233,234         499,745       (266,511 )      (53.3 )

Natural gas                             385,101         667,609       (282,508 )      (42.3 )%
Total revenues                     $ 15,950,171    $ 13,380,092    $ 2,570,079         19.2 %

Average price:
Crude oil (per Bbl)                $     105.70    $     109.78    $     (4.08 )       (3.7 )%
NGLs (per Bbl)                            35.25           51.46         (16.21 )      (31.5 )%
Natural gas (per Mcf)                      2.90            3.23          (0.33 )      (10.2 )%
Crude oil, NGLs and natural gas
(per BOE)                          $      91.77    $      86.08    $      5.69          6.6 %

Expenses (per BOE)
Lease operating expenses           $       7.25    $       8.22    $     (0.97 )      (11.8 )%
Production taxes                   $       0.32    $       0.31    $      0.01          3.2 %
Depletion expense on oil and
natural gas properties (a)         $       5.13    $       5.17    $     (0.04 )       (0.8 )%

. . .

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