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March 4, 2009

Via Facsimile and EDGAR

Mr. H. Roger Schwall

Assistant Director

U.S. Securities and Exchange Commission

Division of Corporation Finance

100 F Street, NE — Mail Stop 7010

Washington, D.C. 20549-7010

Re:                             Evolution Petroleum
Corporation

Form 10-K for Fiscal Year Ended June 30, 2008

Filed September 24, 2008

Form 10-Q for Fiscal Quarter Ended September 30, 2008

Filed November 14, 2008

Amended Schedule 14A

Filed November 4, 2008

File No. 001-32942

Dear Mr. Schwall:

On behalf of Evolution Petroleum Corporation (the “Company”, “we”, “our”
or “us”), I am responding to comments received in a letter dated January 30,
2009 from you with respect to the filings listed above.  For your convenience, I have repeated in bold
type the comments and requests for additional information as set forth in your
letter.  My response follows each
applicable comment or request.

Form 10-K for the Fiscal Year Ended June 30, 2008

General

1.                                     We
direct your attention to Item 601(b)(10) of Regulation S-K.  Please confirm that all material contracts
have been filed.  We note, in particular,
that it does not appear that the agreements with your customers from whom you
derive 10 percent or more of your net oil and natural gas revenues referenced
on pages 7 and 53, have been filed.
If you do not believe that such contracts fall within the purview of
Item 601(b)(10), please explain why.

Evolution Petroleum Corporation   ·     2500 CityWest Blvd., Suite 1300   ·   Houston, Texas  77042

Tel:
713-935-0122      FAX:  713-935-0199

Response:

Item 601(b)(10) of Regulation S-K
requires that contracts made in the ordinary course of business should
be filed as an exhibit for those contracts for which the company is:

substantially dependent as in the case of
continuing contracts to sell the major part of registrant’s products  or services or to purchase the major part of
registrant’s requirements of goods, services or raw materials . . .

Our crude oil contracts are in the ordinary course of business, are of
short duration and we believe we are not overly dependent on the performance of
the contract or on the purchaser.
Although our contracts are with purchasers who buy 10 percent or more of
our production of crude oil, the contracts themselves are not substantial as we
believe there would be numerous other purchasers of our oil production if we
lost or were unable to renew any of our current contracts.

Although our natural gas contracts are in the ordinary course of
business, our relationships with our purchasers could be considered
significant, in that there are not as many alternatives to market our natural
gas.  Based on this,  we believe our sales contracts with DCP
Midstream, LP, and ETC Texas Pipeline, LTD may be considered material contracts
as defined by Item 601(b) (10), and as such we will file the contracts as
exhibits to a Form 8-K to be filed based on your concurrence.

Item 2. Properties, page 16

2.                                     Please
provide support for the statement that the companies that submitted offers to
participate with you in the Delhi Bryant Unit, “believe that the Delhi Bryant
Unit is an excellent candidate for a CO2
EOR project…..”

Response:

Prior to our June 2006 sale of the Delhi Holt Bryant Unit through
a farmout to Denbury Resources, we conducted a competitive offering process soliciting
major participants with CO2-EOR expertise, funding and operating
abilities.  During the process, we
offered analyses of three CO2 pilot tests successfully completed in our field
by a prior operator, along with comparisons to analogous full scale projects in
the same geological formation.  The
solicitation was made primarily on the basis of the EOR potential of a CO2
flood and not on the relatively immaterial associated proved reserves existing
at that time. After considerable analyses by three parties and extensive
negotiations with two of them, two confidential competitive offers were made to
us in writing that focused on the CO2-EOR potential.  Of these, we accepted Denbury’s offer,
wherein they paid us $50 million in cash and committed to develop, at their
sole cost and expense, an EOR flood with dedicated proved CO2 reserves from
Denbury’s Jackson Dome property, including the construction of the necessary
pipeline to transport the CO2 approximately 100 miles to the Delhi Field.  Based on the two competitive offers,

we believe that both offering parties considered the field to be an
excellent candidate for such, due to their willingness to pay us substantial
funds, up front for an immaterial amount of proved reserves, combined with
their commitment to fund hundreds of millions of dollars in capital
expenditures.

In total, Denbury has expended over $190 million on the Delhi CO2-EOR
project through November 2008, in addition to the $50 million they paid us
at closing.  We understand through public
presentations by Denbury that the CO2 delivery pipeline from the Jackson Dome
to the Delhi Field is complete, except for the crossing at the Mississippi
River.  Well preparations in the field
have begun, with CO2 injection expected to begin by mid-year 2009.

Controls and Procedures, page 57

3.                                     We
note your statement that you “… carried out an evaluation… of the effectiveness
of the design and operation of our disclosure controls and procedures as of the
end of the quarter covered by this report.” (emphasis
added).  Please revise to state whether
your evaluation of the effectiveness of the design and operations of your
disclosure controls and procedures as of the end of the fiscal year
covered by your Form 10-K.

Response:

We carried out an evaluation of the effectiveness of the design and
operation of our disclosure controls and procedures as of June 30, 2008,
the last day of our fiscal year.  In our Form 10-K
filed with the Securities and Exchange Commission (“SEC”) on September 24,
2009, which covered our fiscal period July 1, 2007 through June 30,
2008, we stated in our statement on Disclosure Controls and
Procedures under Item 9A. Controls and Procedures  that
the report covered the  fiscal quarter
ended June 30, 2008 instead of the fiscal year ended June 30,
2008.  Although this did not correctly state the
period covered by our report, it correctly identified the date of our
evaluation of the effectiveness of the design and operation of our disclosure
controls and procedures in effect as of June 30, 2008.  We respectfully suggest prospectively
correcting the statement in our Annual Report on Form 10-K for the year
ended June 30, 2009.

Financial Statements

Note 2 — Summary of Significant Accounting Policies, page 41

Limitation on Capitalized Costs, page 41

4.                                     The
ceiling test that you describe does not reflect differentiation between
unproved property costs excluded from costs to be amortized, and unproved
property costs that are subject to amortization.  The test required by Rule 4-10(c)(4) of
Regulation S-X stipulates that you must utilize the lower of cost or

estimated fair value for this latter group of
costs.  Please tell us the extent to
which you have followed this guidance for each of the periods presented, and
submit the disclosures that you propose to clarify your practice.

Response:

We have followed the guidance referenced for all accounting periods
presented in our Form 10-K filed as of June 30, 2008.  During those periods, no amounts exceeding
the lower of cost or estimated fair value for unproved property costs subject
to amortization have been included in the “ceiling amount”.

We suggest prospectively clarifying our current policy on “Limitation
on Capitalized Costs” with the following:

Limitation on Capitalized Costs. Under the full-cost method of accounting, we
are required on a quarterly basis to perform a “ceiling test” which determines
a limit on the book value of our oil and natural gas properties. If the
capitalized cost of our oil and natural gas properties, net of accumulated
depreciation, depletion, and amortization, and net of related deferred income
taxes, exceed the “ceiling amount”, the excess is charged to expense and
reflected as additional accumulated depreciation, depletion and amortization or
as a credit to oil and natural gas properties.
The “ceiling amount” is defined as the sum of: (a) the present
value, discounted at 10 percent, of estimated future net revenues from proved
reserves, which is computed using oil and natural gas prices in effect at the
balance sheet date (with consideration of price changes only to the extent
provided by contractual arrangements), less estimated future expenditures
(based on current costs) to be incurred in developing and producing the proved
reserves; plus (b) the cost of unproved oil and gas properties not subject
to amortization; plus (c) the lower of cost or estimated fair value of
unproven properties included in the costs being amortized; net of (d) the
related tax effects.   We did not have a “ceiling
test” impairment during the years ended June 30, 2008 and 2007.

Note 5 — Property and Equipment, page 45

5.                                     Please
expand your note to add disclosures pertaining to unproved properties and major
development projects as required by Rule 4-10(c)(7)(ii) of Regulation
S-X.  This guidance requires that you
disclose the current status of properties and projects for which costs are
excluded from amortization, the anticipated timing of the inclusion of such
costs in amortization, and a table indicating the nature of costs by category and
identifying the periods in which the costs were incurred.  Please ensure that your totals per the table
agree to the corresponding amounts presented in this note and Note 16.

Response:

We respectfully request that we prospectively provide additional disclosures
pertaining to unproved properties in all future filings, including our
quarterly reports on Form 10-Q.
Below is our property and equipment footnote for the year ended June 30,
2008, as if the expanded disclosures were included in Note 5 of our financial
statements included in our fiscal 2008 Annual Report on Form 10-K.

Note 5 — Property and Equipment

As
of June 30, 2008 and 2007 our oil and natural gas properties and other
property and equipment consisted of the following:

  June 30,

  2008

  June 30,

  2007

  Oil and natural gas properties

  Property costs subject to amortization

  $

  15,105,766

  $

  4,187,440

  Less: Accumulated depreciation, depletion,
  and amortization

  (632,040

  )

  (652,439

  )

  Unproved properties not subject to
  amortization

  7,573,507

  1,924,552

  Oil and natural gas properties, net

  $

  22,047,233

  $

  5,459,553

  Other property and equipment

  Furniture, fixtures and equipment, at cost

  231,841

  173,205

  Less: Accumulated depreciation

  (70,814

  )

  (18,333

  )

  Other property and equipment, net

  $

  161,027

  $

  154,872

Unproved
properties not subject to amortization are excluded from our full-cost pool
until it is determined that proved reserves can be assigned to such properties
or until such time as we have made an evaluation that impairment has occurred.
Unproved properties not subject to amortization include unevaluated acreage of
$5.6 million as of June 30, 2008, consisting of properties in the Giddings
Field and our projects in the Woodford Shale trend in Oklahoma.  Unproved properties not subject to
amortization also consist of approximately $2.0 million and $1.9 million as of June 30,
2008 and 2007, respectively, of participating interests through separately
acquired royalty and overriding royalty interests aggregating 7.4% of the Delhi
Holt Bryant Unit in the Delhi Field in Louisiana.  Evaluation of these properties is currently
expected to be completed within three years.
Our evaluation of impairment of unproved properties occurs, at a
minimum, on a quarterly basis.

The
following table provides a summary of costs that are not being amortized as of June 30,
2008, by the fiscal year in which the costs were incurred:

  For the Year Ended June 30,

  Total

  2008

  2007

  2006 and

  Prior

  Costs excluded from amortization

  Leasehold acquisition costs

  $

  5,622,766

  $

  4,893,690

  $

  729,076

  $

  —

  Royalty and overriding royalty interests

  1,950,741

  —

  966,794

  983,947

  $

  7,573,507

  $

  4,893,690

  $

  1,695,870

  $

  983,947

Certifications, exhibits 31.1 and 31.2

6.                                     We
note, in both certifications, you still referred to yourself as a “small
business issuer.”  Please revise your
certifications to match the exact form set
forth in Item 601(b)(31) of Regulation S-K.
We note that your current certifications also include other deviations
from the exact language of the form.

Response:

During our transition from the disclosure requirements of Regulation S-B to the scaled
disclosure requirements for smaller reporting companies under Regulation S-K, we inadvertently failed to
make the necessary changes to the verifications as set forth in Item
601(b)(31).  However, these changes were
implemented in our Form 10-Q for the fiscal quarter ended September 30,
2008.  We will continue to follow the certification
requirement set forth in Item 601(b)(31) of Regulation S-K.

Amended
Schedule 14A filed November 4, 2008

Legal
Proceedings, page 5

7.                                     Please
provide a confirmation, if true, that none of your directors or executive
officers have been involved in any legal proceeding listed in Section 401(f) of
Regulation S-K within the last five years, instead of limiting your statement
to only whether they are not currently involved in a legal proceeding.

Response:

Our executive officers and directors have verified through their annual
Directors’ and Officers’ questionnaires that they have not been involved in any
legal proceeding listed in Section 401(f) of Regulation S-K within
the last five years.  In compliance with
the rules of Section 401(f), we suggest prospectively limiting our
disclosure to positively affirming if any director or executive officers have
been involved in such legal proceedings in the last five years, failing which
there will be no confirmation or disclosure.

Executive Compensation and Related Information, page 10

Short Term Incentive Bonuses, page 11

8.                                     Provide
us with an explanation, in table format or otherwise, as to how the committee
determines the quantitative amount of these short term incentive bonuses for each named executive officer.  Explain what the payout factor is and how it
was determined for each named executive officer.  Further, explain the weighting of each of the
performance goals.  See Item 402(b)(1)(v) of
Regulation S-K.

Response:

We request to prospectively clarify how we determine the amount of
short-term incentive bonus for each executive officer in our 2009 proxy
statement.  The paragraph on short-term
incentive bonus in our Amended Schedule 14A filed on November 4, 2008,
would be modified in our 2009 proxy statement as follows:

Short Term Incentive Bonus.  Short term incentive bonuses, generally and historically paid
in cash, are a major portion of total compensation paid and are intended to
vary with individual and Company performance against pre-determined goals.  The bonus targets are 100% of base pay for
the chief executive officer and 75% of base salary for other named executive
officers. The Committee determines awards of short term incentive bonuses to
our executive officers based upon overall performance against those goals on a qualitative
basis, wherein individual and corporate performances are equally weighted, then
multiplied to reach a payout factor. Since the two factors are multiplied, a 0%
factor on either results in