UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q /A
(Amendment No. 1)

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

Commission file number 000-52506

ESP RESOURCES, INC.
(Exact name of registrant as specified in its charter)

1255 Lions Club Road, Scott LA 70583
(Address of principal executive offices) (Zip Code)

(337) 706-7056
(Issuer’s telephone number)

PANTERA PETROLEUM, INC.
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Actof 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]    No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [   ]    No[   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [   ]    No [X]

APPLICABLE ONLY TO CORPORATE ISSUERS

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

22,859,689 common shares issued and outstanding as of May 15, 2009.

EXPLANATORY NOTE

In November 2009, we concluded that it was necessary to amend this Quarterly Report on Form 10-Q in order to reflect the following items:

• We revised the accounting for the reverse acquisition of Pantera by ESP Resources on December 29, 2008. We initially determined that Pantera did not qualify as a business and that the acquisition should be valued based on the fair value of the net assets acquired. These financial statements have been restated to account for the acquisition based on the fair value of the common stock retained by the Pantera shareholders as determined by the trading price of the stock. As a result, additional paid-in capital was increased by $2,559,879 which represents the value of goodwill acquired in the transactions. As of December 31, 2008, the Company determined that the goodwill acquired in the reverse acquisition was fully impaired and it was written off. As a result, retained deficit as of March 31, 2009 decreased by $2,559,879.
• We noted that the statements of operations and cash flow for the predecessor had not been included in the consolidated financial statements for the periods prior to its acquisition by the Company.
• We provided additional discussion about the process employed by the Company to evaluate oil and gas properties for impairment.
• We expanded the explanation of the material weaknesses in our internal control in Item 4T to disclose our conclusions regarding the effectiveness of our disclosure controls and procedures at March 31, 2009.
• We modified the Certification Pursuant to 18 U.S.C. Section 1350, Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 to correct the date of the Form 10-Q referred to in the certification from November 30, 2008 to the correct date of March 31, 2009.

This Amendment No. 1 is stated as of the file date of the Original Filing and does not reflect events occurring after the filing date of the Original Filing, or modify or update the disclosures therein in any way other than as required to reflect the amendment described above

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

     It is the opinion of management that the interim financial statements for the quarter ended March 31, 2009 include all adjustments necessary in order to ensure that the interim financial statements are not misleading.

ESP Resources, Inc
Consolidated Balance Sheets
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

ESP Resources, Inc.
Consolidated Statements of Operations
For the Three Months Ended March 31, 2009 and 2008
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

ESP Resources, Inc.
Statement of Stockholders’ Equity
For the three months ended March 31, 2009
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

ESP Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flow
(Unaudited)

The accompanying notes are an integral part of these consolidated financial statements.

ESP Resources, Inc.
Notes to Unaudited Consolidated Financial Statements
March 31, 2009

Note 1 – Basis of Presentation, Nature of Operations and Significant Accounting Policies

Basis of Presentation

ESP Resources, Inc. (“ESP Nevada”, and collectively with its subsidiaries, the “Company”) was incorporated in the State of Nevada on October 27, 2004. The accompanying unaudited consolidated financial statements include the accounts of ESP Resources, Inc. and its wholly owned subsidiaries, ESP Petrochemicals, Inc. and ESP Resources, Inc. (“ESP Delaware”). All significant inter-company balances and transactions have been eliminated in the consolidation. The financial statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States of America.

Interim Financial Statements

The condensed unaudited consolidated financial statements presented herein have been prepared by the Company in accordance with U.S. generally accepted accounting principles (“GAAP”) and the accounting policies set forth in its audited financial statements for the period ended December 31, 2008 as filed with the Securities and Exchange Commission (the “SEC”) in the Company’s Annual Report on Form 10-K and should be read in conjunction with the notes thereto.

In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments (consisting only of normal recurring adjustments) which are necessary to provide a fair presentation of operating results for the interim periods presented. Certain information and footnote disclosures, normally included in the financial statements prepared in accordance with generally accepted accounting principles, have been condensed or omitted. The results of operations presented for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the year. These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008.

Accounts Receivable and Allowance for Doubtful Accounts

The Company generally does not require collateral, and the majority of its trade receivables are unsecured. The carrying amount for accounts receivable approximates fair value.

Accounts receivable consisted of the following as of March 31, 2009 and December 31, 2008:

In February 2009, the Company entered into a non-binding letter of intent (“Letter of Intent”) to acquire 100% of the outstanding stock of a petrochemicals company (the “Target”).¹ Included in accounts receivable at December 31, 2008 are amounts due from the Target for sales of petrochemicals during 2008. These accounts receivable have exceeded the normal 30-day payment terms. Under the terms of our Letter of Intent, if the acquisition is not consummated these receivables will be repaid with five percent interest. Management believes that the accounts receivable from the Target are fully collectible.

ESP began discussions with the Target concerning a potential acquisition of the assets and business of the Target in early July, 2008. An approximate value of the acquisition was reviewed between the principals of the Target and ESP along with descriptions of the assets, receivables, current customer base, payables, debt structures, notes, and inventories of the Target. The principals agreed that any purchase price of the Target’s business would have a cash component and a stock component of ESP stock. The principals of ESP agreed to supply wholesale chemicals to the Target to assist the Target in increasing their business prospects and supplying their current and potential customer base while ESP continued the due diligence necessary to complete the Target acquisition.

_______________________________
1 The Target is owned by a 6% shareholder of ESP who is also the cousin of one of ESP’s major shareholders. 

The principals of both companies agreed that any wholesale chemicals supplied by ESP to the Target and invoiced during this period would be deducted from the cash portion of the transaction at closing. During the period from July 22, 2008 through December 29, 2008, ESP supplied the Target with $202,192 of wholesale chemicals and storage equipment tanks. During this period, the price of oil declined from $143 per barrel to below $35 per barrel. The decline in oil product pricing caused several of the clients for the Target and ESP to scale back their use of petrochemicals at their field locations. This event hampered the ability of ESP to raise additional equity funds through the sale of securities of the company. Discussions between the principals of the Target and ESP continued and a letter of intent outlining the terms and conditions of a purchase of the Target was executed in February 2009. At the time of signing of the LOI, ESP anticipated the sale of company securities to raise approximately $1,000,000 in new equity for the company. To date, we have not been successful in the capital raise. The LOI with the Target has been extended indefinitely in anticipation of a successful equity raise by ESP. During the three months ended March 31, 2009, ESP provided an additional $22,188 of wholesale chemicals to the Target. The LOI with the Target provides that in the event that a transaction is not completed, the Target would begin making payments on the outstanding invoices and an interest rate of 5% per annum would be added to the outstanding receivable until paid.

ESP and the Target have agreed verbally that the purchase of the Target business will no longer have a hard cash component, and will now consist of all of the outstanding invoices and amounts due ESP as the cash portion of the final negotiated purchase price plus ESP stock to fulfill the remainder of the total purchase price. We anticipate closing the transaction during the first quarter of 2010.

Concentrations

The Company has three major customers that together account for 31% of accounts receivable at March 31, 2009 and three major customers that together account for 64% of the total revenues earned for the three months ended March 31, 2009.

The Company has a published agreed upon price for Customer A which is reviewed and revised annually. Currently, approval of proposed price increases are pending for this customer, thus the first quarter sales have been recorded at the 2008 prices.

The Company has three vendors that accounted for 60% of purchases and 33% of the ending accounts payable at March 31, 2009.

Impairment

Unevaluated properties which are excluded from amortization are assessed at least annually to ascertain whether impairment has occurred. Unevaluated properties whose costs are individually significant shall be assessed individually. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties may be grouped for purposes of assessing impairment. Management considers the following factors in assessing properties for impairment:

Impairment may be estimated by applying factors based on historical experience and other data such as primary lease terms of the properties, average holding periods of unproved properties, and geographic and geologic data to groupings of individually insignificant properties and projects. The amount of impairment assessed under either of these methods shall be added to the costs to be amortized. In addition, management assesses the availability of financing on commercially viable terms in order to finance the development of the property. The Company individually evaluated the Block 83 and 84 Project and the Baker 80 Lease. These are the only unevaluated properties owned by the Company; therefore, no properties were evaluated as a group.

At March 31, 2009, the Company determined that there was no impairment of its investments in unevaluated properties.

Revenue and Cost Recognition

The Company through its wholly owned subsidiary, ESP Petrochemicals, Inc., is a custom formulator of petrochemicals for the oil & gas industry. Since the products are specific to each location, the receipt of an order or purchase order starts the production process. Once the blending takes place, the order is delivered to the land site or dock. When the containers of blended petrochemicals are off-loaded at the dock, or they are stored on the land site, a delivery ticket is obtained, an invoice is generated and Company recognizes revenue. The invoice is generated based on the credit agreement with the customer at the agreed-upon price.

Revenue is recognized when title and risk of loss have transferred to the customer and when contractual terms have been fulfilled. Transfer of title and risk of loss occurs when the product is delivered in accordance with the contractual shipping terms, generally to a land site or dock. Revenue is recognized based on the credit agreement with the customer at the agreed upon price.

Note 2 – Going Concern

The Company has net losses for the three months ended March 31, 2009 as well as negative cash flows and negative working capital.

These factors raise substantial doubt about the Company's ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

The Company's ability to continue operations will likely require additional capital. The condition raises substantial doubt about the Company to continue as a going concern. We expect cash flows from operating activities to improve, primarily as a result of an increase in revenue, although there can be no assurance thereof. The accompanying consolidated financial statements do not include any adjustments that might be necessary should we be unable to continue as a going concern. If we fail to generate positive cash flow or obtain additional financing, when required, we may have to modify, delay, or abandon some or all of our business and expansion plans.

Note 3 – Unevaluated oil and gas properties

Block 83 and 84 Project, JV

On March 6, 2008, our predecessor entity Pantera purchased a 10% interest in a joint venture formed pursuant to a joint venture agreement dated February 24, 2008 with Trius Energy, LLC, as the managing venturer, and certain other joint venturers, in consideration for $800,000. The joint venture was formed for the purpose of drilling certain oil and gas fields in Texas, USA. Upon entering into this agreement, a director of Trius Energy, LLC was appointed as a director of the Company. The initial well, the Sibley 84#1, was drilled and re-entered on the property. On April 1, 2008, the joint venture began re-entry operations on the Sibley 84 #1 Well. On August 16, 2008, the Sibley 84 #1 well of Block 83 84 Project JV entered production from the Devonian and Fusselman zones and began to sell natural gas. Sales were suspended to allow the well to unload fluid, and a separator was put in line with the stack-pak to better handle the formation water. In addition, the operator performed an acidization procedure on the perforations, or holes made in the production formation through which formation gas enters the wellbore. While bottom hole pressure remained strong after the acidization procedure, formation water from an undetermined zone continued to cause a significant decrease in the natural gas production rates, and caused the Block 83 84 Project JV to shut in the well for evaluation. While evaluating solutions from service providers to decrease the water production, on November 12, 2008, there was a reported well-head blowout. Multiple service companies were mobilized on location to control the well and place a Blow Out Preventer on the casing head at the surface of the well. The well is currently shut in due to the blow out. Work to repair the blowout began in August 2009. The Company expects that the operator will receive insurance reimbursement to cover the cost of the repairs of the damage from the blow out.

Although the Sibley 84#1 ("84#1") was tied to the gas gathering sale line and sold small amounts of natural gas, because of the blowout, Trius Energy LLC acting as managing venturer has verbally extended the carried interest for the Company in the Sibley 84#1 for the Fusselman or Devonian zones. Trius is working to obtain additional funding for this well for this purpose and is contractually committed to fund the remaining two wells, Gulf Baker 83#1 ("83#1") and the Sibley 84#2 ("84#2"), according to the joint venture agreement and private placement agreement to completion.

Under the definition of 17 CFR Section 210.4 -10, Subsection A(2), the Block 83 84 Project JV’s three well project does not meet the definition of proved reserves. While true there was production in 84#1 from the Devonian and Fusselman zones, it was so limited as to not rise to the definitional level of being economical to a reasonable certainty, especially in light of the unexpected water problem very shortly after production began, in addition to the subsequent blowout. The target zones in the 84#1 and 83#1 have not produced in these particular wells, aside from the small production in 84#1 before the water inflow and blowout. For 84#1, along with 83#1 and the undrilled prospect 84#2, the recovery of natural gas and crude oil is subject to reasonable doubt because of uncertainty as to economic factors, geology, and reservoir characteristics. As an example, 84#1’s target zones of the Devonian and Fusselman produced an uneconomical amount of water unexpectedly, and the economical producibility of those zones does not rise to the level of reasonable certainty. It is intended to obtain an independent reserve analysis once economic producibility is supported to the level of a reasonable certainty, if and when that occurs. At that time, we intend to obtain the analysis from an independent, third party reserve engineer. Until that time, the properties are classified as unproven.

In assessing the fair value of the Block 83 84 Project JV, the Company evaluated several factors and considered each factor according to its probability of its occurrence and its importance in the valuation processes. There are qualitative and quantitative considerations in each factor, and the Company combined its own professional experience with that of external parties to assess each factor. The first factor to be evaluated was the blow-out on the Sibley 84#1. While impossible for any operator or individual to definitively assess the full extent of the damage without beginning the repair work, estimates were made by the operator in its professional opinion. The operator carries a $5 million policy which covers blow-outs, and the estimate for the repair does not amount to 25% of the policy. Although work has begun to repair the blowout, there is a risk that damage to the well may exceed the value of the insurance coverage. In the Company’s assessment of the policy and the repair work, this risk is not inconsequential, but it does not rise to the threshold of more likely than not. If it is in fact the case that the damage exceeds the value of the insurance policy, there is a risk that there will not be additional financing above the insured amount to repair the well with the result that the value of the Company’s interest in the project would likely be impaired. This risk would fall upon Trius Energy LLC acting as managing venturer and all other joint venturers in the Sibley 84#1 for the Fusselman or Devonian zones. As above, it is the assessment that the insurance policy will more than likely cover the entire repair work.

There is the risk that upon completion of the work to repair the well from the blow-out that there will be additional water from either the Devonian or Fusselman that limits economic production. According to the perforation reports, the well was producing from both the Devonian and the Fusselman. While is it not uncommon for these formations to produce water, there is the risk that the water does not decrease as expected over time. This risk is assessed against the solution of testing and blocking off the formation causing the water so as to produce the available gas unimpeded. If it is found that neither the Devonian nor the Fusselman is commercially productive, then a possible solution and recommendation is that the operator perforate in the Lower Wolfcamp. The probability of both the Fusselman and Devonian zones producing water is limited due to the high shut in tubing pressure reading and casing pressure readings over time, in addition to the high down hole pressure readings. The risk in both the Sibley 84#1 and the Gulf Baker 83#1 is mitigated by the fact that they have multiple potential producible zones including the Fusselman, Devonian, Wolfcamp, and Atoka. Based upon an analysis of area production, well logs, and drilling and completion reports, while the risk exists that no zone is economically producible, it is assessed as not rising to the level of more likely than not because of the multiplicity of potential production zones.

An additional factor in assessing the carrying value is the ability of Trius Energy LLC as managing venturer to extend the carried interest for the Company in the Sibley 84#1. This factor is assessed on two levels, one for completing the Sibley 84#1 above the insurance policy maximum, and second, for completion should there be excessive water produced. As stated above, it is the second risk that is more probable, but is mitigated by two considerations. The first consideration is that if Trius cannot or will not extend the carried interest, then all joint venturers will be called for the capital. In this instance, the Company would be required to give 10% of the completion costs, and if not, it will be considered non-consent and lose rights to the well’s cash flow until such time as allowed under the non-consent provisions of the joint operating agreement. Although Trius is a third party, privately held company and does not allow access to its financial statements, it has verbally stated that it is contractually obligated to extend the carried interest as it relates to the Company and is in the process of liquidating other interests to fund the testing and blocking off of formation water, if necessary. The risk that Trius can liquidate interests can be assessed as higher than other risks, The Company would need to have 10% to preserve its rights, and the Company would need to either divert funds from ongoing operations or raise additional money in the form of debt or equity. There is no assurance that this will occur.

Similar to the assessment of the Sibley 84#1, the Company assessed the risk for the completion of the Sibley 84#2, a new oil drill, and the Baker 83#1 in evaluating the carrying value of the project. The main risk here is the credit risk of Trius Energy. Although information is not complete, and sales prices have declined, other factors such as drilling input costs, have also declined, making it less expensive to drill new wells and re-enter shut-in wells.

Another factor used in assessing the project is the price of natural gas and oil. The two gas re-entry wells are longer term assets with estimated remaining useful lives in multiple zones of over 10 years. The Company has stressed each well with lower prices and projected volumes. The stressed values were compared to sales prices of working interests at volumes and prices comparable to stressed prices. As the market for working interests is an illiquid market and may not necessarily be relied upon, the Company also compared the results using traditional present value analysis. The 84#2 is a new oil drill. The Company has also stressed the production and pricing models, and compared them to area production. For impairment purposes only, the Company used an expected value analysis, which is the weighted average of the present value of a downside, base, and upside cases, along with a total failure case, where the weights are the probabilities of occurrence of those values. Material assumptions for all cases included a $3.00/mmbtu for gas prices and $60/barrel oil price, which are below the U.S. Government Energy Information Administration’s Annual Energy Outlook 2009 Reference Case (Updated). The 84#1 assumed a base case of 2.5 million cubic feet per day production with a target Devonian zone while the 83#1 base case was the same from the target Lower Wolfcamp zone, based upon the log analysis and area production, along with the operator’s experience in the field. An 80 barrel per day production assumption from the Yates/7-Rivers formation was used for the 84#2. Additional assumptions included a 20% decline rate for the re-entry wells, and a 10% discount rate, applied to our 10% working interest, the same being a 7.5% net revenue interest.

At March 31, 2009, management determined that its investment in the Block 83 and 84 joint venture was not impaired.

Baker 80 Lease

By an agreement dated August 11, 2008, our predecessor entity Pantera acquired a 95% working interest and 71.25% revenue interest, in the Baker 80 Lease located in Pecos County, Texas (the “Property”) from Lakehills Production, Inc. (“Lakehills”) in consideration for $10,000 previously advanced and $726,000 to be paid as follows:

$150,000 on or before August 11, 2008– 15.66% (paid)
$200,000 on or before August 20, 2008 – 27.55% (paid)
$376,000 on or before September 30, 2008 – 51.79% (not paid)

The Company was given an indefinite verbal extension on the payment of the $376,000 to acquire an additional 51.79% . The Company negotiated a reduction in the purchase price for the final 51.79% to $87,190. On October 30, 2008, the Company borrowed $87,190 from a private equity drilling fund (the “Investor”) to purchase the remaining 51.79% working interest in the Property. The Investor advanced the funds directly to Lakehills, and the Company issued a promissory note to Investor for $87,190. The Company’s ownership in the Property is governed by the drilling program described below.

On October 30, 2008, we entered into and closed the definitive documents for the transaction with Lakehills and a private equity drilling fund (“the Investor”). Pursuant to the terms of the Agreement, we, along with Lakehills, entered into drilling arrangements with the Investor whereby we and Lakehills granted the Investor an exclusive option to fund the drilling, re-entry and completion of certain wells located in the West Gomez field (Baker Ranch) located in Pecos County, Texas. According to the terms of the Agreement, the Company and Lakehills transferred to the Investor a combined 100% working interest in the wells. Upon tie-in of each well, the Investor will own a 95% working interest in such well and the Investor will grant to Lakehills a 5% working interest. The Investor’s working interest shall remain 95% until such time as the Investor has achieved a 12% internal rate of return from its investment (“IRR”) in the well. Thereafter, the Investor will grant to us a 5% working interest and the Investor’s working interest percentage will be reduced to 90% until such time as the Investor has achieved a 20% IRR from its investment in the Well Program. Thereafter, the Investor will grant to us an additional 10% working interest such that our working interest will be 15% and the Investor’s working interest will be reduced to 80% until such time as the Investor has achieved a 25% IRR from its investment in the Well Program. Thereafter, the Investor will grant to us an additional 6% working interest such that our interest in such Well will be 21% and the Investor’s working interest will be reduced to 74% accordingly. In all cases, Lakehills’ working interest will remain at 5%.

The Investor shall receive 100% of the cash flows on the initial well (the “Initial Well”) until such cash flow received exceeds the $87,190 plus interest represented by a promissory note that we executed in favor of the Investor, which bears interest at 5% per year and was due April 30, 2009.

This note has been verbally extended indefinitely. No cash distributions shall be paid to us or to Lakehills until the Note has been paid in full. Upon full payment of the Note, we shall receive 100% of the cash flow from the Initial Well until the aggregate amount of such cash flow received by us totals $350,000. No cash distributions shall be made or otherwise accrue to the Investor or Lakehills during this period. Thereafter, the Investor will receive 50% of the Initial Well’s operating cash flow and we will receive 50% of the Initial Well’s operating cash flow until each party receives $175,000 (i.e., an aggregate of $350,000). No cash distributions shall be made or otherwise accrue to Lakehills during this period. Thereafter, cash distributions shall be calculated in accordance with the then current working interest ownership percentages associated with the Initial Well as outlined in the paragraph above. The distributions that would otherwise be payable to us pursuant to the immediately preceding sentence shall be paid to the Investor until the aggregate of such distributions paid to the Investor totals $175,000. The first $525,000 of cash flow received by us under the transaction documents shall be used to satisfy its obligations to certain investors under an oil and gas certificate agreement.

At March 31, 2009, management determined that its investment in the Baker 80 lease was not impaired.

Note 4 – Long term debt

On February 12, 2009, the Company borrowed $41,415 for the purchase of a vehicle. The note bears interest at 6.75% per year, is secured by the vehicle purchased and is payable in 60 monthly payments of $817.

On February 15, 2009, the Company borrowed $4,343 for the purchase of equipment. The note bears interest at 12% per year, is secured by the equipment purchased and is payable 36 monthly payments of $145.

Note 5 – Stockholders’ Equity

On March 4, 2009, the Company entered into consulting agreements with two individuals to provide strategic planning and financial consulting services for a period of six months. The Company issued a total of 1,653,000 shares of common stock to these individuals in payment for these services. The shares have fair value of $843,030 and vest over the service period. The Company valued the shares based on market value on the date of the agreement, and recognized compensation expense of $126,455 for the three months ended March 31, 2009. The fair value of the unvested shares is $716,575 as of March 31, 2009.

On March 23, 2009, the Company entered into consulting agreements with two individuals to provide services to the Company for a period of two years. The Company issued a total of 2,000,000 shares of common stock to these individuals in payment for the services. The shares have a fair value of $800,000 and vest over the service period. The Company valued the shares based on market value on the date of the agreement, and recognized compensation expense of $11,111 for the three months ended March 31, 2009. The fair value of the unvested shares is $788,889 as of March 31, 2009.

Note 6 – Related party transaction

During the three months ended March 31, 2009, the Company borrowed $25,000 from DDA Corporation LLC, which is wholly owned by the Company’s president. The note bears interest at 5% per year and matures January 23, 2010.

During the three months ended March 31, 2009, shareholders and management have advanced the company $145,000 for the Company’s expanding operations, and the Company has repaid $20,000 on the loan from our investor. The loans are unsecured, bear no interest, and are due on demand.

At March 31, 2009, the Company had balances due to stockholders and related parties as follows:

During the current period, the Company accrued consulting expenses to a related entity in the amount of $ 31,500. The amount is included in accrued expenses at March 31, 2009.

Note 7 – Restatement

The balance sheets presented herein as of March 31, 2009 and December 31, 2008 have been restated for an error in the valuation of the net assets acquired in the reverse acquisition of Pantera Petroleum. We initially determined that Pantera did not qualify as a business and that the acquisition should be valued based on the fair value of the net assets acquired. These financial statements have been restated to account for the acquisition based on the fair value of the common stock retained by the Pantera shareholders as determined by the trading price of the stock. As a result, the net assets acquired have increased by $2,559,879 which represents the value of goodwill acquired in the transactions. Based on this change, goodwill and additional paid-in capital increased by $2,559,879 at both March 31, 2009 and December 31, 2008. As of December 31, 2008, the Company determined that the goodwill acquired in the reverse acquisition was fully impaired and it was written off. Based on this change, goodwill decreased by $2,559,879 and retained deficit increased by $2,559,879 at both March 31, 2009 and December 31, 2008.

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

FORWARD-LOOKING STATEMENTS

     This quarterly report contains forward-looking statements as that term is defined in Section 27A of the United States Securities Act of 1933 and Section 21E of the United States Securities Exchange Act of 1934. These statements relate to future events or our future financial performance. In some cases, you can identify forward-looking statements by terminology such as “may”, “should”, “expects”, “plans”, “anticipates”, “believes”, “estimates”, “predicts”, “potential” or “continue” or the negative of these terms or other comparable terminology. These statements are only predictions and involve known and unknown risks, uncertainties and other factors, including the risks in the section entitled “Risk Factors”, that may cause our or our industry’s actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by these forward-looking statements. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results.

     Financial information contained in this quarterly report and in our unaudited interim financial statements are stated in United States dollars and are prepared in accordance with United States generally accepted accounting principles. The following discussion should be read in conjunction with our unaudited interim financial statements and the related notes that appear elsewhere in this quarterly report.

     As used in this quarterly report, and unless otherwise indicated, the terms “we”, “us” and “our” mean ESP Resources, Inc., unless otherwise indicated.

Corporate History

     We were incorporated on October 27, 2004, in the State of Nevada. Our principal offices are located at 1255 Lions Club Road, Scott, LA 70583.

     Effective September 28, 2007, we completed a merger with our subsidiary, Pantera Petroleum Inc., a Nevada corporation. As a result, we changed our name from “Arthro Pharmaceuticals, Inc.” to “Pantera Petroleum Inc.” We changed the name of our company to better reflect the direction and business of our company.

In addition, effective September 28, 2007, we effected a sixteen (16) for one (1) forward stock split of our authorized, issued and outstanding common stock. As a result, our authorized capital increased from 75,000,000 common shares to 1,200,000,000 common shares - with the same par value of $0.001. At that time, our issued and outstanding share capital increased from 6,970,909 common shares to 111,534,544 common shares. The name change and forward stock split became effective with the OTC Bulletin Board at the opening for trading on September 28, 2007 under the new stock symbol “PTPE”.

In December 2008, the Company entered into an agreement with ESP Resources, Inc., a Delaware corporation (ESP Delaware), whereby the Company acquired 100% ownership of ESP Delaware in exchange for 292,682,297 common shares. As a result of this acquisition, we changed our name from “Pantera Petroleum, Inc.” to “ESP Resources, Inc.” On January 27, 2009, we effected a one (1) for twenty (20) reverse stock split of our common stock and received a new ticker symbol. The name change and reverse stock split became effective with the OTC Bulletin Board at the opening of trading on January 27, 2009 under the new symbol “ESPI”. Our new CUSIP number is 26913L104.

Our Current Business

     We are engaged in the acquisition of prospective oil and gas properties, and through our wholly owned subsidiary, ESP Petrochemicals, Inc. (“ESPPI”), we are a custom formulator of specialty chemicals for the energy industry.

ESP Petrochemicals, Inc.

Through our wholly owned subsidiary, ESP Petrochemicals Inc., we are a custom formulator of specialty chemicals for the energy industry. ESPPI’s more specific mission is to provide applications of surface chemistry to service all facets of the fossil energy business via a high level of innovation. ESPPI is focusing its efforts on solving problems in a highly complex integration of processes to achieve the highest level of quality petroleum output. Listening to its customers with their changing demands and applying its skills as chemical formulators enables ESPPI to measure its success in this endeavor.

ESPPI acts as manufacturer, distributor and marketer of specialty chemicals. ESPPI supplies specialty chemicals for a variety of oil field applications including separating suspended water and other contaminants from crude oil, pumping enhancement, and cleaning, as well as a variety of fluids and additives used in the drilling and production process. At each drilling site or well that is in production, there exist a number of factors that make each site unique. These include the depth of the producing formation, the bottom-hole temperature of the producing well, the size of the well head through which the producing fluids flow, the size and pressure ratings of the production equipment, including the separators, heater-treaters, compression equipment, size of production tubulars in the wellbore, size of the storage tanks on the customers location, and pressure ratings of the sales lines for the oil and gas products. Wells that are operating short distances from each other in the same field can have very different characteristics. This variance in operating conditions, chemical makeup of the oil, and the usage of diverse equipment requires a very specific chemical blend to be used if maximum drilling and production well performance is to be attained.

ESPPI's goal is first, to solve the customer’s problem at the well and optimize drilling or production, and secondly, the sale of product. Typically, the ESPPI team may gather information at a well site and enter this data into the analytical system at the company’s labs in Lafayette, Louisiana. The system provides testing parameters and reproduces conditions at the wellhead. This allows the ESPPI chemist to design and test a new chemical blend in a very short time. In many cases, a new blend may be in service at the well in as little as 24 hours.

Oil and Gas Exploration

Chaco Basin Concessions: Share Purchase Agreement

Following the change in our business in late 2007, we conducted due diligence on potential acquisitions of suitable oil and gas properties in Paraguay, South America. On November 21, 2007, we entered into a share purchase agreement, as amended March 17, 2008 and July 30, 2008 (the “Original Agreement”), among our company, Artemis Energy PLC, formerly Pantera Oil and Gas PLC (“Artemis”), Aurora Petroleos SA (“Aurora”) and Boreal Petroleos SA (“Boreal”). To more effectively align the interests of our company with Artemis, Aurora and Boreal, and to provide for a potentially more efficient accounting and tax treatment for our company, Artemis, Aurora and Boreal under their respective tax and accounting regimes, the parties entered negotiations and further revised the Original Agreement. On September 9, 2008, we amended the agreement (“Restated Purchase Agreement”) as follows.

In addition, each of Aurora and Boreal agreed to use all funds that they respectively receive from our company in connection with the amended agreement exclusively towards the exploration and development of the concessions held by each of Aurora and Boreal. Each of Aurora and Boreal have agreed to (i) consult and work together with our company to plan and execute any exploration and development activities either of them conduct; (ii) provide our company with annualized budgets with monthly cost projections; and (iii) not incur costs in excess of $5,000 for any transactions without the prior written consent of either our company or Artemis.

Subsequent to the Company’s amended agreement with Aurora, Boreal and Artemis Energy PLC in September 2008, the Company has no ownership in Aurora or Boreal or their underlying assets. The Company holds notes receivable from Aurora and Boreal with a face value of $680,371. These notes are due September 9, 2013. The notes represent a conversion of the Company’s previous ownership interests in Aurora and Boreal. The Company made cash advances totaling $670,000 to acquire the ownership interests which were later converted into notes receivable.

The notes have been reduced by an allowance of $402,000 and interest income is not being accrued on the notes based on the uncertainty of the collectability of the notes. In addition the Company has nominal options to purchase 27% of Aurora and 30% of Boreal from a third party, Artemis Energy PLC, at an exercise price of £10 for a term of 30 years; provided the fair market value of the shares subject to the option exceeds the value of the debt held by the Company under the aforementioned note receivable issued by such entity. The valuation requirement has not been met for either option and we do not expect that requirement to be met in the near future. Each option expires October 13, 2048 and carries and exercise price of £10. The options are considered nominal and are valued at $- on the balance sheet of the Company.

The Company does not expect to exercise its option under the amended agreement to provide Aurora a $500,000 investment in exchange for a note and an additional option for 38% of its equity, or to provide Boreal a $500,000 investment in exchange for a note and an additional option for 35% of its equity by the April 30, 2009 deadline, as per the agreement. This deadline was verbally extended indefinitely. However, in order to focus on its core petrochemical business and existing and potential domestic exploration assets in a tight credit environment, the Company has elected to not pursue additional investments under the amended agreement.

We believe that it is probable that the notes receivable from Aurora and Boreal are impaired. The amount of the impairment has been estimated based on management’s judgment of the liquidation value of the underlying assets in the companies. In determining the amount of the valuation allowance, management considered the following factors:

• Estimated potential sale prices of Aurora and Boreal’s concessions compared to other concession properties in Paraguay. While no exact comparisons are available as each concession is unique in geography and data available, potential liquidation value of the concessions is a factor. Management has reviewed concessions in the area where possible; however, the availability of data is limited because each concession is privately held. In addition, each concession is unique and objective comparisons of value are virtually impossible. Management uses this information as a subjective indicator of value and trends in the area, matched with the value of the data available for the concessions held by Aurora and Boreal. While substantive quantitative work has been done to analyze the data available on the concessions from Aurora and Boreal, it is a unique property. Because of the lack of objective data from comparative properties, management has used its judgment and the review of qualitative information in order to value these notes.

• Our limited ability to compel Aurora and Boreal to sell the concessions in order to repay the notes

• Precipitous fall in oil and gas prices

• Contraction in credit and financing

• Curtailing of exploration activities by major oil and gas companies

Management used its experience and judgment to weigh these factors and determine the amount of the allowance.

Aurora and Boreal Chaco Basin Concessions

Aurora has acquired the rights to concessions in northern Paraguay consisting of three tracts: Tagua, Toro, and Cerro Cabrera. They are located in the eastern extensions of the Chaco Basin, where, in Bolivia and Argentina significant reserves of natural gas, oil and condensate have been discovered. The Chaco Basin extends across Paraguay, Bolivia and Argentina, and in Paraguay, the Chaco Basin is composed of two Sub-Basins, the Curupayty and Carandayty Sub-Basins. The sources for most of the known hydrocarbons in the Chaco Basin are the Devonian Los Monos and Silurian Kirusillas shales. Both are mixed oil and gas prone source rocks. The amalgamated fans and channel sandstones of the Carboniferous Tarija and Tupambi formations are the main producing reservoirs in the Chaco Basin. The Tagua tract, approximately 116 square miles in area, is located in the Carandayty Sub-Basin on the border with Bolivia. The Curupayty Sub-Basin is located along the southern margin of the Chaco Basin. The Toro tract, approximately 927 square miles in area, is located in the Curupayty Sub-Basin in north central Paraguay. The Cerro Cabrera Block, approximately 1,996 square miles in area, is located in northern Paraguay on the Bolivian border. Aurora entered into a Concession Contract with the government of Paraguay on March 2, 2007. This Concession Contract is assigned Law Number 3,551, dated July 16, 2008, having been duly ratified by the Congress of Paraguay and signed by President Nicanor Duarte Frutos.

Boreal has acquired the rights to concessions in northern Paraguay consisting of two tracts: Pantera and Bahia Negra. They are also located in the eastern extensions of the Chaco Basin. The Pantera tract, approximately 1,158 square miles in area, is located in the Curupayty Sub-Basin on the border with Bolivia. The Bahia Negra tract, approximately 1,853 square miles in area, is located at the southern end of the Curupayty Sub-Basin in north central Paraguay. Boreal entered into a Concession Contract with the government of Paraguay on March 2, 2007. This Concession Contract is assigned Law Number 3,478, dated December 13, 2008, having been duly ratified by the Congress of Paraguay and signed by President Nicanor Duarte Frutos.

On January 30, 2008, we entered into an agreement with T.B. Berge, P.G., for the reprocessing of 1993 vintage Phillips Petroleum 2D seismic data and 1971 vintage Texaco 2D seismic data, located on our Pantera concession, consisting of approximately 988,000 acres in northern Paraguay. On July 10, 2008, Mr. Berge completed the reprocessing and interpretation of approximately 178 miles of 2-D seismic data and submitted his processing report to our company. The reprocessed data, along with well, surface, and cultural information, were loaded and mapped in an SMT project. Mr. Berge submitted relevant horizons and maps to show hydrocarbon systems and prospects and determined a probabilistic range for identified prospects, as well as a mean outcome for economics, using SPE (Society of Petroleum Engineers), WPC (World Petroleum Council), and AAPG (American Association of Petroleum Geologists) guidelines. Existing well files from the Pantera #1 well, drilled by Phillips Petroleum in 1995, were recovered from storage in Paraguay and fully digitized and incorporated into the report. The Pantera #1 well tops and intervals were tied to existing seismic lines and correlated around the rest of the reprocessed data grid.

Possible additional steps could include the processing of a number of large seismic displays on paper that are from the older Texaco surveys through a process called seismic vectorization (or SEGY conversion) to recover and reprocess that data as if we had the tapes. The process should allow us to do post-stack processing (migration) and then load the data with our existing data. This may be useful information of a more regional nature that would help put the regional perspective together. We have accumulated additional well data to aid in this survey. This survey would be intended to further add to our evaluation of identified prospects and aid in the formulation of the drilling plan.

However, commensurate with our acquisition of ESP Resources (Delaware) and the strategic focus of those assets on specialty chemicals for the energy industry, we are currently evaluating this project for viability and strategic fit. Given the global downturn in oil and gas prices and the severe contraction in the equity and credit markets for financing, we have been actively seeking a lead joint venture partner or purchaser for the property to move forward with exploration plans. However, there is no guarantee that a financial partner or purchaser may be discovered for the property which will lead to our inability to move forward with the exploration project.

Block 83 84 Joint Venture

In addition, on February 24, 2008, we purchased a 10% interest in a joint venture formed pursuant to a joint venture agreement, with Trius Energy, LLC, as the managing venturer, and certain other joint venturers, in consideration for $800,000. Pursuant to the joint venture agreement, our company and the other joint venturers agreed, among other things, (a) to form a joint venture for the limited purpose of (i) securing, re-entering, re-opening, managing, cultivating, drilling and operating the Gulf-Baker 83 #1 Well, the Sibley 84 #1 Well and the Sibley 84 #2 Well located in West Gomez oil and gas fields in Pecos County, Texas, (ii) such other business agreed to by the joint venturers, and (iii) all such actions incidental to the foregoing as the joint venturers determine; (b) that the joint venturers shall have equal rights to manage and control the joint venture and its affairs and business, and that the joint venturers designate Trius Energy, LLC, as the managing venturer and delegate to the managing venturer the day-to-day management of the joint venture; (c) that distributions from and contributions to the joint venture shall be made in a prescribed manner; and (d) that all property acquired by the joint venture shall be owned by the joint venture, in the name of the joint venture, and beneficially owned by the joint venturers in the percentages of each joint venturer from time to time. On April 1, 2008, the joint venture began re-entry operations on the Sibley 84 #1 Well.

On August 16, 2008, the Sibley 84 #1 well of Block 83 84 Project JV entered production from the Devonian and Fusselman zones and began to sell natural gas. Sales were suspended to allow the well to unload fluid, and a separator was put in line with the stack-pak to better handle the formation water. In addition, the operator performed an acidization procedure on the perforations, or holes made in the production formation through which formation gas enters the wellbore. While bottom hole pressure remained strong after the acidization procedure, formation water from an undetermined zone continued to cause a significant decrease in the natural gas production rates, and caused the Block 83 84 Project JV to shut in the well for evaluation. While evaluating solutions from service providers to decrease the water production, on November 12, 2008, there was a reported well-head blowout. Multiple service companies were mobilized on location to control the well and place a Blow Out Preventer on the casing head at the surface of the well. The well is currently shut in due to the blow out. The Company expects that the operator will receive insurance reimbursement to cover the cost of the repairs of the damage from the blow out.

Although the Sibley 84#1 was tied to the gas gathering sale line and sold small amounts of natural gas, because of the blowout, Trius Energy LLC acting as managing venturer has verbally extended the carried interest for the Company in the Sibley 84#1 for the Fusselman or Devonian zones. Trius is working to obtain additional funding for this well for this purpose and is contractually committed to fund the remaining two wells, Gulf Baker 83#1 and the Sibley 84#2, according to the joint venture agreement and private placement agreement to completion.

Under the definition of 17 CFR Section 210.4 -10, Subsection A(2), the Block 83 84 Project JV’s three well project does not meet the definition of proved reserves. While true there was production in 84#1 from the Devonian and Fusselman zones, it was so limited as to not rise to the definitional level of being economical to a reasonable certainty, especially in light of the unexpected water problem very shortly after production began, in addition to the subsequent blowout. The target zones in the 84#1 and 83#1 have not produced in these particular wells, aside from the small production in 84#1 before the water inflow and blowout. For 84#1, along with 83#1 and the undrilled prospect 84#2, the recovery of natural gas and crude oil is subject to reasonable doubt because of uncertainty as to economic factors, geology, and reservoir characteristics. As an example, 84#1’s target zones of the Devonian and Fusselman produced an uneconomical amount of water unexpectedly, and the economical producibility of those zones does not rise to the level of reasonable certainty. It is intended to obtain an independent reserve analysis once economic producibility is supported to the level of a reasonable certainty, if and when that occurs. At that time, we intend to obtain the analysis from an independent, third party reserve engineer. Until that time, the properties are classified as unproven.

In assessing the fair value of the Block 83 84 Project JV, the Company evaluated several factors and considered each factor according to its probability of its occurrence and its importance in the valuation process. There are qualitative and quantitative considerations in each factor, and the Company combined its own professional experience with that of external parties to assess each factor. The first factor to be evaluated was the blow-out on the Sibley 84#1. While impossible for any operator or individual to definitively assess the full extent of the damage without beginning the repair work, estimates were made by the operator in its professional opinion. The operator carries a $5 million policy which covers blow-outs, and the estimate for the repair does not amount to 25% of the policy. Although work has begun to repair the blowout, there is a risk that damage to the well may exceed the value of the insurance coverage. In the Company’s assessment of the policy and the repair work, this risk is not inconsequential, but it does not rise to the threshold of more likely than not. If it is in fact the case that the damage exceeds the value of the insurance policy, there is a risk that there will not be additional financing above the insured amount to repair the well with the result that the value of the Company’s interest in the project will likely be impaired. This risk would fall upon Trius Energy LLC acting as managing venturer and all other joint venturers in the Sibley 84#1 for the Fusselman or Devonian zones. As above, it is the assessment that the insurance policy will more than likely cover the entire repair work.

There is the risk that upon completion of the work to repair the well from the blow-out that there will be additional water from either the Devonian or Fusselman that limits economic production. According to the perforation reports, the well was producing from both the Devonian and the Fusselman. While is it not uncommon for these formations to produce water, there is the risk that the water does not decrease as expected over time. This risk is assessed against the solution of testing and blocking off the formation causing the water so as to produce the available gas unimpeded. If it is found that neither the Devonian nor the Fusselman is commercially productive, then a possible solution and recommendation is that the operator perforate in the Lower Wolfcamp, which is a productive zone in the Gomez Field. The probability of both the Fusselman and Devonian zones producing water is limited due to the high shut in tubing pressure reading and casing pressure readings over time, in addition to the high down hole pressure readings. The risk in both the Sibley 84#1 and the Gulf Baker 83#1 is mitigated by the fact that they have multiple producible zones including the Fusselman, Devonian, Wolfcamp, and Atoka. Based upon an analysis of area production, well logs, and drilling and completion reports, while the risk exists that no zone is economically producible, it is assessed as not rising to the level of more likely than not because of the multiplicity of production zones.

An additional factor in assessing the carrying value is the ability of Trius Energy LLC as managing venturer to extend the carried interest for the Company in the Sibley 84#1. This factor is assessed on two levels, one for completing the Sibley 84#1 above the insurance policy maximum, and second, for completion should there be excessive water produced. As stated above, it is the second risk that is more probable, but is mitigated by two considerations. The first consideration is that if Trius cannot or will not extend the carried interest, then all joint venturers will be called for the capital. In this instance, the Company would be required to give 10% of the completion costs, and if not, it will be considered non-consent and lose rights to the well’s cash flow until such time as allowed under the non-consent provisions of the joint operating agreement. Although Trius is a third party, privately held company and does not allow access to its financial statements, it has verbally stated that it is contractually obligated to extend the carried interest as it relates to the Company and is in the process of liquidating other interests to fund the testing and blocking off of formation water, if necessary. The risk that Trius can liquidate interests can be assessed as higher than other risks, but the Company assesses it as more probable than not that Trius will be able to perform. Even if it cannot, this risk is mitigated by the number of joint venturers and relatively low amount of assessed additional work. The Company would need to have 10% to preserve its rights, and the Company assesses that it would be able to either divert funds from ongoing operations or raise additional money in the form of debt or equity. However, there is no assurance that this will occur.

Similar to the assessment of the Sibley 84#1, the Company assessed the risk for the completion of the Sibley 84#2, a new oil drill, and the Baker 83#1 in evaluating the carrying value of the project. The main risk here is the credit risk of Trius Energy. Although information is not complete, and sales prices have declined, other factors such as drilling input costs, have also declined, making it less expensive to drill new wells and re-enter shut-in wells. The Company has assessed that at this time it is more probable than not that Trius will be able to perform. There is no assurance that this will occur, and the Company is monitoring this factor carefully and is prepared to make the appropriate impairments should conditions change.

Another factor used in assessing the project is the price of natural gas and oil. The two gas re-entry wells are longer term assets with estimated remaining useful lives in multiple zones of over 10 years. According to the Energy Information Administration, U.S. Natural Gas Wellhead monthly prices were $8.29 per thousand cubic feet in March 2008 and averaged $3.90 for the first six months of 2009. The Company’s longer term projections assume a higher price per thousand cubic feet rather than incorporating short term, highly volatile prices. Although the Company believes this average over time is appropriate, the Company has stressed each well with lower prices and projected volumes. The stressed values were compared to sales prices of working interests at volumes and prices comparable to stressed prices and found not to be impaired. As the market for working interests is an illiquid market and may not necessarily be relied upon, the Company also compared the results using traditional present value analysis and found the carrying value not to be impaired. As the project is inherently designed to have failures in any one well or zone, the Company assesses the value in light of the potential failures of completion. For impairment purposes only, the Company used an expected value analysis, which is the weighted average of the present value of a downside, base, and upside cases, along with a total failure case, where the weights are the probabilities of occurrence of those values. The 84#2 is a new oil drill. Despite the drop in oil prices, the original expected value per barrel of oil is comparable to prices today. The Company has also stressed the production and pricing models, and compared them area production, and assessed that projected pricing and production projections associated with this well would not impair its contribution to the project.

Material assumptions for all cases included a $3.00/mmbtu for gas prices and $60/barrel oil price, which are below the U.S. Government Energy Information Administration’s Annual Energy Outlook 2009 Reference Case (Updated). The 84#1 assumed a base case of 2.5 million cubic feet per day production with a target Devonian zone while the 83#1 base case was the same from the target Lower Wolfcamp zone, based upon the log analysis and area production, along with the operator’s experience in the field. An 80 barrel per day production assumption from the Yates/7-Rivers formation was used for the 84#2. Additional assumptions included a 20% decline rate for the re-entry wells, and a 10% discount rate, applied to our 10% working interest, the same being a 7.5% net revenue interest.

Taking in totality the risks and their likelihood, at this time, the Company assessed that it is more likely than not that impairment has not occurred, given the stress tests on volumes and gas prices, combined with the technical data on Sibley 84#1, the probability of payment with the insurance coverage, and commitments from Trius Energy according to the joint venture agreement and private placement agreement to fund to completion. If, however, the Sibley 84#1 cannot be completed for any reason, the Project value would likely be impaired and result in a write-off. The maximum exposure to loss would be assessed to the carrying value of the Project.

Baker Ranch Block 80

By an agreement dated August 11, 2008, we agreed to acquire a 95% working interest and 71.25% revenue interest, in the Baker 80 Lease located in Pecos County, Texas (the “Property”) from Lakehills Production, Inc. (“Lakehills”) in consideration for $10,000 previously advanced and $726,000 to be paid as follows:

In the event that we make less than the required investment amount to complete any of the payments, we shall be entitled to receive a percentage of the Property lease assignments per the above described percentages.

We were given an indefinite verbal extension on the payment of the $376,000 to acquire an additional 51.79% . We negotiated a reduction in the purchase price for the final 51.79% to $87,190. On October 30, 2008, we borrowed $87,190 from a private equity drilling fund (the “Investor”) to purchase the remaining 51.79% working interest in the Property. The Investor advanced the funds directly to Lakehills, and we issued a promissory note to Investor for $87,190. Our ownership in the Property is governed by the drilling program described below.

On October 30, 2008, we entered into and closed the definitive documents for the transaction with Lakehills and a private equity drilling fund (the "Investor”). Pursuant to the terms of the Agreement, we, along with Lakehills, entered into drilling arrangements with the Investor whereby we and Lakehills granted the Investor an exclusive option to fund the drilling, re-entry and completion of certain wells located in the West Gomez field (Baker’s Ranch) located in Pecos County, Texas. According to the terms of the Agreement, we and Lakehills transferred to the Investor a combined 100% working interest in the wells. Upon tie-in of each well, the Investor will own a 95% working interest in such well and the Investor will grant to Lakehills a 5% working interest. The Investor’s working interest shall remain 95% until such time as the Investor has achieved a 12% internal rate of return from its investment (“IRR”) in the well. Thereafter, the Investor will grant to us a 5% working interest and the Investor’s working interest percentage will be reduced to 90% until such time as the Investor has achieved a 20% IRR from its investment in the Well Program. Thereafter, the Investor will grant to us an additional 10% working interest such that our working interest will be 15% and the Investor’s working interest will be reduced to 80% until such time as the Investor has achieved a 25% IRR from its investment in the Well Program. Thereafter, the Investor will grant to us an additional 6% working interest such that our interest in such Well will be 21% and the Investor’s working interest will be reduced to 74% accordingly. In all cases, Lakehills’ working interest will remain at 5%.

The Investor shall receive 100% of the cash flows on the initial well (the “Initial Well”) until such cash flow received exceeds the $87,190 plus interest represented by a promissory note that we executed in favor of the Investor, which bears interest at 5% per year and is due April 30, 2009.. No cash distributions shall be paid to us or to Lakehills until the Note has been paid in full. Upon full payment of the Note, we shall receive 100% of the cash flow from the Initial Well until the aggregate amount of such cash flow received by us totals $350,000. No cash distributions shall be made or otherwise accrue to the Investor or Lakehills during this period. Thereafter, the Investor will receive 50% of the Initial Well’s operating cash flow and we will receive 50% of the Initial Well’s operating cash flow until each party receives $175,000 (i.e., an aggregate of $350,000). No cash distributions shall be made or otherwise accrue to Lakehills during this period. Thereafter, cash distributions shall be calculated in accordance with the then current working interest ownership percentages associated with the Initial Well as outlined in the paragraph above. The distributions that would otherwise be payable to us pursuant to the immediately preceding sentence shall be paid to the Investor until the aggregate of such distributions paid to the Investor totals $175,000. The first $525,000 of cash flow received by us under the transaction documents shall be used to satisfy its obligations to certain investors under an oil and gas certificate agreement. Re-entry operations on Block 80 began in November 2008 with the goal of placing the well back into production in the near future. Due to the current re-entry operations and the uncertainty regarding its production levels, its classification will remain as an unproven property.

Principal Products

Petrochemicals: Through ESPPI, we are a custom formulator of specialty chemicals for the energy industry. ESPPI’s more specific mission is to provide applications of surface chemistry to service all facets of the fossil energy business via a high level of innovation. ESPPI is focusing its efforts on solving problems in a highly complex integration of processes to achieve the highest level of quality petroleum output. Listening to its customers with their changing demands and applying its skills as chemical formulators enables ESPPI to measure its success in this endeavor.

ESPPI acts as manufacturer, distributor and marketer of specialty chemicals. ESPPI supplies specialty chemicals for a variety of oil field applications including separating suspended water and other contaminants from crude oil, pumping enhancement, and cleaning, as well as a variety of fluids and additives used in the drilling and production process.

ESPPI currently offers production chemicals, drilling chemicals, waste remediation chemicals, cleaners and waste treatment chemicals:

• Surfactants that are highly effective in treating production and injection problems at the customer well-head.
• Well completion and work-over chemicals that maximize productivity from new and existing wells. Bactericides that kill water borne bacterial growth, thus preventing corrosion and plugging of the customer well-head and flowline.
• Scale compounds that prevent or treat scale deposits.
• Corrosion inhibitors, which are organic compounds that form a protective film on metal surfaces to insulate the metal from its corrosive environment.
• Antifoams that provide safe economic means of controlling foaming problems.
• ESPPI emulsion breakers, which are chemicals specially formulated for crude oils containing produced waters. Paraffin chemicals that inhibit and/or dissolve paraffin to prevent buildup. Their effectiveness is not diminished when used in conjunction with other chemicals.
• Water Clarifiers that solve any and all of the problems associated with purifying effluent water, improve appearance, efficiency and productivity.

Oil and Gas Exploration: We are also engaged in the business of exploring and, if warranted, developing commercial reserves of oil and gas. Since we are currently an exploration stage company, there is no assurance that commercially viable resources or reserves exist on any of our properties, and a great deal of further exploration will be required before a final evaluation as to the economic and legal feasibility for our future operation is determined. As of the date of this quarterly report, we have not discovered any economically viable resource or reserve on the properties owned by Aurora or Boreal, and there is no assurance that we will discover any. On August 16, 2008, the Sibley 84 #1 well of Block 83 84 Project JV entered production and began to sell natural gas. However, due to the current condition of the well and the uncertainty regarding its production levels, its classification will remain as an unproven property.

Distribution Methods

ESP Petrochemicals, Inc. : ESPPI's goal is first, to solve the customer’s problem at the well and optimize drilling or production, and secondly, the sale of product. Typically, the ESPPI team may gather information at a well site and enter this data into the analytical system at the company’s labs in Lafayette, Louisiana. The system provides testing parameters and reproduces conditions at the wellhead. This allows the ESPPI chemist to design and test a new chemical blend in a very short time. In many cases, a new blend may be in service at the well in as little as 24 hours.

Once the chemical blend has been formulated and decided, the chemical is placed in service at the wellhead of the customer by delivering a storage tank, called a “day tank”, at the customer’s well-site location and filling the tank with the custom blended chemical. The tank is tied to a pressure pump that provides the pumping capacity to deliver the chemical into the wellhead for the customer.

This unique process shortens the chemical development time frame from what might have been as long as two months or more to a few days or hours. The exceptional service, response times and chemical products that the ESPPI team is able to provide its customers is a differentiating factor within the industry.

West Gomez Projects : The West Gomez field has all of the necessary infrastructure to gather and deliver oil and natural gas when and if any of the projects enter into production.

Chaco Basin Concessions : A new gas field discovery in Paraguay will require new infrastructure, such as gas processing plants, gas gathering pipelines, and construction of a connection into the existing pipeline system in Brazil and Argentina for international export. A new oil discovery will also require new infrastructure, such as oil tanks and pumps. Crude oil must be moved from the production site to refineries. These movements can be made using a number of different modes of transportation, including trucks and trains, and also via an oil pipeline, which would need to be constructed in Paraguay. We would not, on our own, be able to distribute any oil and gas we discover, from our operations in Paraguay. We would need to rely on third party contractors to distribute any such oil and gas or sell any such oil and gas to third parties at the point of production.

RESULTS OF OPERATIONS

     You should read the following discussion of our financial condition and results of operations together with the unaudited interim consolidated financial statements and the notes to the unaudited interim consolidated financial statements included in this quarterly report. This discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results may differ materially from those anticipated in these forward-looking statements.

For the three month periods ended March 31, 2009 and March 31, 2008

The following table summarizes the results of our operations during the three months ended March 31, 2009 and 2008, and provides information regarding the dollar and percentage increase or (decrease) from 2008 to 2009.

Sales

Sales revenue increased to $569,093 for the three months ended March 31, 2009 compared to $426,366 for the same period of 2008, an increase of $142,727. The customer base expanded between the first quarter of 2008 and the first quarter of 2009 due to increased sales coverage in Southern Louisiana and East Texas regions. ESPPI increased sales volume to several of our existing customers through supply of additional petrochemical products at customer wellsites.

Cost of goods sold and gross profit

Cost of goods sold for the three months ended March 31, 2009 was $396,769, an increase of $81,836 or 26% compared to $314,933 over the same period in 2008. The increase is comparable to the increase in sales for the same period.

Our gross profit increased to $172,324 for the three months ended March 31, 2009, an increase of $60,891 or 55% compared to $111,433 for the same period of 2008. The increase was related to the increase in sales partially offset by the increase in cost of sales.

General and administrative expenses

General and administrative expenses increased to $466,840 for the three months ended March 31, 2009 compared to $172,543 for the same period of 2008. The expenses in 2009 include stock based compensation of $137,566. Excluding this expense the increase in general and administrative expenses would have been $156,731. This increase was primarily related to temporarily higher costs associated with combining the companies acquired late in 2008.

Net loss

Our net loss increased to a loss of $328,810 for the three months ended March 31, 2009 compared to a loss of $82,648 for the same period of 2008. The primary reason for the increase in the net loss was the increase in general and administrative expenses.

Cash Flow Used in Operating Activities

Operating activities used cash of $89,944 for the three months ended March 31, 2009, compared to using $136,945 for the three months ended March 31, 2008. The decrease in cash used during the three months ended March 31, 2009 was primarily attributable to changes in our non-cash working capital balances related to operations, including prepaid expenses and other current assets, accounts payable, and accrued liabilities.

Cash Flow Used in Investing Activities

Investing activities used cash of $20,558 for the three month period ended March 31, 2009 compared to using $5,430 for the three month period ended March 31, 2008. The cash used in investing activities was a result of purchases of fixed assets.

Cash Flow Provided by Financing Activities

Financing activities generated cash of $145,886 for the three month period ended March 31, 2009 compared to generating $124,520 for the three month period ended March 31, 2008. The cash generated from financing activities was a result of proceeds from loans from related parties partially offset by repayments of those loans.

Liquidity And Capital Resources

As of March 31, 2009, our total assets were $2,647,011 and our total liabilities were $1,779,936. We had cash of $62,751, current assets of $882,875 and current liabilities of $1,323,745 as of March 31, 2009. We had negative working capital of $440,870 on that date.

We will require additional funds to implement our growth strategy. To date, we have had negative cash flows from operations and we have been dependent on sales of our equity securities and debt financing to meet our cash requirements. We expect this situation to continue for the foreseeable future. We anticipate that we will have negative cash flows during the next twelve months. Funds may be raised through equity financing, debt financing, or other sources, which may result in further dilution in the equity ownership of our shares. There is still no assurance that we will be able to maintain operations at a level sufficient for an investor to obtain a return on his investment in our common stock. Further, we may continue to be unprofitable.

Cash Requirements

Our plan of operations for the next 12 months involves the exploration of our oil and gas investments, the growth of our petrochemical business through the expansion of regional sales, and the research and development of new chemical and analytical services in areas of waste remediation, water treatment and specialty biodegradable cleaning compounds. As of March 31, 2009, our company had cash of $62,751 and a working capital deficit of $440,870.

We estimate that our general operating expenses for the next twelve month period to include at least $3,000,000 for exploration expenses and $420,000 for professional fees and general and administrative expenses for a total estimated funding of at least $3,420,000. Estimated operating expenses include provisions for consulting fees, salaries, travel, telephone, office rent, and ongoing legal, accounting, and audit expenses to comply with our reporting responsibilities as a public company under the United States Exchange Act of 1934, as amended.

We will require additional funds to continue our operations and implement our growth strategy in exploration operations. To date, we have had negative cash flows from operations and we have been dependent on sales of our equity securities and debt financing to meet our cash requirements. We expect this situation to continue for the foreseeable future. We anticipate that we will have negative cash flows during the next twelve month period. These funds may be raised through equity financing, debt financing, or other sources, which may result in further dilution in the equity ownership of our shares. There is still no assurance that we will be able to maintain operations at a level sufficient for an investor to obtain a return on his investment in our common stock. Further, we may continue to be unprofitable.

We incurred a net loss of $328,810 for the three months ended March 31, 2009. As indicated above, we anticipate that our projected operating expenses for the next twelve months will be $3,420,000. We will be required to raise additional funds through the issuance of equity securities or through debt financing in order to carry-out our plan of operations for the next twelve month period. There can be no assurance that we will be successful in raising the required capital or that actual cash requirements will not exceed our estimates.

Given that we have had limited revenues to date, our cash requirements are subject to numerous contingencies and risk factors beyond our control, including operation and acquisition risks, competition from well-funded competitors, and our ability to manage growth. We can offer no assurance that our company will generate cash flow sufficient to achieve profitable operations or that our expenses will not exceed our projections. If our expenses exceed estimates, we will require additional monies during the next twelve months to execute our business plan.

There are no assurances that we will be able to obtain funds required for our continued operation. There can be no assurance that additional financing will be available to us when needed or, if available, that it can be obtained on commercially reasonable terms. If we are not able to obtain additional financing on a timely basis, we will not be able to meet our other obligations as they become due and we will be forced to scale down or perhaps even cease the operation of our business.

Going Concern

We have historically incurred losses. Because of these historical losses, we will require additional working capital to develop our business operations. We intend to raise additional working capital through private placements, public offerings, bank financing and/or advances from related parties or shareholder loans.

Our investments in Aurora Petroleos SA, Boreal Petroleos SA, our joint venture with Trius Energy, LLC are dependent on the efforts of others for the development of well sites and the generation of cash flow. There is not guaranty that those investments will not suffer material setbacks or will ever become productive. For example, the Block 83 84 Project JV that is under the joint venture with Trius Energy, LLC experienced a well-head blowout on November 12, 2008, which has delayed the development of that well. If the parties responsible for the development of such projects are unsuccessful in the development of those properties, the Company will lose its investments in those projects

The continuation of our business is dependent upon obtaining further financing and achieving a break even or profitable level of operations. The issuance of additional equity securities by us could result in a significant dilution in the equity interests of our current or future stockholders. Obtaining commercial loans, assuming those loans would be available, will increase our liabilities and future cash commitments.

There are no assurances that we will be able to achieve a level of revenues adequate to generate sufficient cash flow from operations. To the extent that funds generated from operations and any private placements, public offerings and/or bank financing are insufficient, we will have to raise additional working capital. No assurance can be given that additional financing will be available, or if available, will be on terms acceptable to us. If adequate working capital is not available we may not increase our operations.

These conditions raise substantial doubt about our ability to continue as a going concern. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might be necessary should we be unable to continue as a going concern.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operation are based upon the condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to our critical accounting policies from those described in our annual report on Form 10-KSB for the year ended December 31, 2008.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Not Applicable.

Item 4T. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15 under the Securities Exchange Act of 1934, as of the end of the period covered by this quarterly report, being March 31, 2009, we have carried out an evaluation of the effectiveness of the design and operation of our company’s disclosure controls and procedures. This evaluation was carried out under the supervision and with the participation of our company’s management, including our company’s President and Chief Executive Officer. Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be reported in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. In connection with the completion of the review and issuance of the Form 10-Q report on our financial statements for the quarter ended March 31, 2009, we identified deficiencies that existed in the design or operation of our internal control over financial reporting that it considers to be “material weaknesses.” The PCAOB has defined a material weakness as a “significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.” The material weaknesses persisted during the period covered by this report.

These material weaknesses are a result of the lack of a formal communication procedure for reportable activities occurring in the Company’s subsidiary, ESP Petrochemicals, Inc., to the chief executive officer of the Company, who is also the officer in charge of the Company’s reporting obligations.

Prior to the reverse acquisition, which occurred on December 30, 2008, there was one employee of ESP Resources, Inc., one physical location in Texas where employees maintained offices and the Company did not have any subsidiaries. Every Company transaction was approved by the Company’s chief executive and financial officer. Following the reverse merger transaction, the Company’s chief executive and financial officer continued to handle the transactions involving the Company’s investments prior to December 30, 2009. At that time, the chief executive officer of ESP Petrochemicals, Inc. was appointed the president of the Company and oversaw the operations of ESP Petrochemicals, Inc. The principal offices of the Company were also moved from Texas to Louisiana. The Company continues to operate in this manner, with the Company’s chief executive and financial officer residing and working in Texas and the Company’s president residing and working at the Company’s principal office in Louisiana.

While the Company (i) is not aware of any reportable events that have not been disclosed in a timely manner and (ii) together with its subsidiary, continues to employee less than ten people, the chief executive and financial officer believes that the expansion of the Company’s operations and geographic distance between the principal officers of the Company merit the implementation of a more formal procedure for periodically communicating the Company’s activities to the chief executive and financial officer. The Company proposes to conduct at least weekly conference calls to review the transactions in which the Company and its subsidiary have participated in the previous week and to immediately communicate significant events. The chief executive and financial officer feels that these additional procedures will provide reasonable assurance that the Company’s controls and procedures will meet their objectives.

Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Due to the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.

To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this quarterly report have been prepared in accordance with generally accepted accounting principles. In addition, our Form 10-Q was extensively reviewed by our chief executive and president to ensure that all transactions are properly disclosed. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Not applicable.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information

None.

Item 6. Exhibits.

* Filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

ESP RESOURCES, INC.

By: /s/ Chris Metcalf
Chris Metcalf
Chief Executive Officer and Director
(Principal Executive Officer and
Principal Financial Officer)
Date: March 23, 2010