LAREDO PETROLEUM HOLDINGS, INC.

15 W. SIXTH STREET, SUITE 1800

TULSA, OKLAHOMA 74119

November 14, 2011

Mr. H. Roger Schwall
Assistant Director
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E. Mail Stop 4628
Washington, D.C. 20549-3561

Re:                               Laredo Petroleum Holdings, Inc.

Amendment No. 1 to Registration Statement on Form S-1

File No. 333-176439

Filed October 11, 2011

Dear Mr. Schwall:

Set forth below are the responses of Laredo Petroleum Holdings, Inc., a Delaware corporation (“we” or the “Company”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the U.S. Securities and Exchange Commission (the “Commission”) by letter dated November 1, 2011 with respect to Amendment No. 1 (“Amendment No. 1”) to the Company’s Form S-1 initially filed with the Commission on August 24, 2011, File No. 333-176439 (the “Registration Statement”).  Concurrently with the submission of this letter, we are filing through EDGAR Amendment No. 2 to the Registration Statement (“Amendment No. 2”).  For your convenience, we have also hand delivered three copies of this letter, Amendment No. 2, and Amendment No. 2 marked to show all changes made since the filing of Amendment No. 1.

Each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.  All references to pages numbers and captions correspond to Amendment No. 2, unless otherwise indicated.

Amendment No. 1 to Registration Statement on Form S-1

General

1.                                       References in this letter to our prior comments correspond to the numbered comments which appeared in our letter to you dated September 27, 2011.  We refer you generally to prior comments 1, 2, 3, and 5, and remind you to comply with those comments going forward. Also, please provide the price range of the offering in your next amendment.

Response:  We have made every attempt to comply with or undertake to comply with each such prior comment.  Additionally, with respect to prior comment 2, we have filed Exhibits 2.1, 3.3, 3.4, 4.1, 10.4, 10.5, 10.6, 10.7, 10.8 and 21.1 with Amendment No. 2.  We will file Exhibits 1.1 and 5.1 as soon as possible to allow the Staff sufficient time to review prior to the effectiveness of the Registration Statement.

We acknowledge the Staff’s comment in the last sentence above and will revise the Registration Statement to include a price range when such a range becomes available. We intend to include this information sufficiently in advance of effectiveness of the Registration Statement to provide the Staff time to review the information and to enable us to respond to any additional comments the Staff may have as a result of the inclusion of this information.

Prospectus Summary, page 1

Identified potential drilling locations(4), page 3

2.                                       For the Permian basin and the Anadarko Granite Wash, please expand your table here and on page 84 to disclose the number of “identified potential drilling locations” to which you attributed proved undeveloped reserves.

Response:  We have revised the Registration Statement accordingly. Please see pages 3 and 86.

Use of Proceeds, page 41

3.                                       Please revise to provide the amounts for each of the uses you reference in the second paragraph. See generally Instruction 4 to Item 504 of Regulation S-K.

Response:  We have revised the Registration Statement accordingly. Please see page 43.

Business, page 83

Proved Undeveloped Reserves, page 94

4.                                       Information provided in response to prior comment number 21 from our letter dated September 27, 2011 indicates that your scheduled development expenditures through 2013 as of June 30, 2011 are substantially lower than corresponding amounts as of December 31, 2010, after taking into consideration actual expenditures for the six months ended June 30, 2011. Explain to us, in reasonable detail, the reasons for this decrease.

Response:  Our development plan for proved undeveloped reserves (“PUD”) in the December 31, 2010 reserve report prepared by Ryder Scott Company, L.P. (“Ryder

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Scott”) assumed that approximately 1/5th of our total proved undeveloped reserves would be developed in each of the next five years.

The PUD development plan in the June 30, 2011 reserve report prepared by Ryder Scott assumed that the amount of PUD capital scheduled for all of 2011 would be approximately $200 million. During the first half of 2011, we actually spent approximately $124 million on PUD drilling, and the PUD drilling schedule in effect on June 30, 2011 anticipated approximately $69 million being spent on PUDs during the second half of 2011, for a full year PUD capital of $193 million. It was also assumed that the level of PUD capital for 2012 would be about the same or slightly less than the 2011 full year capital.  Our actual PUD development plan for 2012 is now budgeted at approximately $167 million. We have adjusted our PUD development budget for years 2013, 2014, and 2015 to increase each year, to capture the balance of the PUD drilling within a five-year timeframe.

The principal reasons for our adjustment to our PUD drilling budget are as follows:  All of the PUD locations from the acquired Broad Oak properties are attributed to vertical locations in the Sprayberry, Dean and Upper Wolfcamp formations that directly offset vertical producing wells from these intervals. We believe these locations also have additional non-proved upside from the lower Wolfcamp through Atoka intervals which would be “orphaned” if the vertical PUD locations were just drilled to the Sprayberry, Dean and Upper Wolfcamp intervals.  Additionally, we believe that horizontal wells in the Wolfcamp and Cline Shale intervals offer an alternative development plan that might provide better economics.  From a relative perspective in comparing the PUDs at December 31, 2010 to June 30, 2011, the PUD capital amounts were lowered in calendar years 2012 and 2013 to allow us to utilize some of the PUD capital to drill and test the deeper portions of the Wolfcamp through Atoka intervals and also to test the horizontal ideas, which caused us to alter the relative stages of planned PUD development over the five-year period.

5.                                       We note your disclosure of changes to your proved undeveloped reserves.  The changes from FYE 2009 to FYE 2010, in MMBOE, appear to be:  27 (beginning) + 71 (added) -3 (converted) = 95 (year-end). However, you have disclosed 92 MMBOE in PUD reserves.  Please amend your document to disclose the changes to PUD reserves due to revisions, acquisition/divestiture, drilling as well as conversion to developed status.  With reasonable detail, explain the sources of “new proved undeveloped reserve additions totaling 70,830 MBOE”. Refer to Item 1203(b) of Regulation S-K.

Response:   We have revised the Registration Statement accordingly. Please see page 96.

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Executive compensation, page 119

Summary Compensation Table, page 131

6.                                       We note your response to our prior comment 24.  Footnote 3 to the Summary Compensation Table, which appears to relate to the calculation of a value of $0 per unit for the Series D Units granted February 1, 2010, mentions “certain subjective assumptions” and refers the reader to Note F to your audited combined financial statements.  Note F states that “The Company’s determination of the fair value of each Series B-1, B-2, C, D and E Units is affected by the Company’s proved reserves, current commodity prices, current values of the Company’s non-oil and gas assets and liabilities, as well as assumptions regarding a number of complex and subjective variables.”  Revise the disclosure to provide additional clarity concerning how you calculated a value of $0 per unit for the Series D Units, including but not limited to more information concerning the assumptions and subjective variables involved.

Response:  We have revised the Registration Statement accordingly. Please see footnote 3 to the “Summary compensation” table on page 134, footnote 3 to the “Outstanding equity awards” table on page 142, footnote 2 to the “Stock vested for the year ended December 31, 2010” table on page 144, footnote 6 to the table describing potential payments upon termination or change in control on page 146, footnote 1 to the “Director compensation” table on page 148 and pages F-27 and F-68.

Laredo Petroleum Financial Statements

General

Notes to the combined financial statements, June 30, 2011 and 2010, page F-13

Note A — Organization, page F-13

7.                                       We note your response to prior comment number 31 from our letter dated September 27, 2011. Given the nature and significance of the Broad Oak transaction, and the fact that your filing already includes pro forma financial information, we believe investors would be better informed of the impact of this transaction if it were reflected in the pro forma financial statements.  Revise your pro forma financial statements accordingly.

Response:  We acknowledge the Staff’s comment with respect to pro forma financial information, and, as discussed with the Staff, we note that the Broad Oak transaction is now reflected in the balance sheet of Laredo Petroleum, LLC and its subsidiaries (collectively, “Laredo”) as of September 30, 2011, which is included in Amendment No. 2.  The historical results of the operations of Broad Oak are included in the combined and consolidated financial statements for all periods presented in the Registration Statement.

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We have determined the only additional information that would be reflected in the pro forma financial statements that is not currently reflected in the historical financial statements is the additional interest expense, which would have been incurred on the debt used to finance the Broad Oak acquisition had the acquisition been completed at January 1, 2010.  We have determined that the additional interest expense that would have been incurred is immaterial, and therefore, would not be meaningful to investors.  Accordingly, we believe the presentation of pro forma financial statements, including adjustments to reflect the Broad Oak acquisition, would not contain any additional useful information for investors over what is included in the financial statements as of and for the nine months ended September 30, 2011.

Notes to the combined financial statements, December 31, 2010, 2009 and 2008, page F-50

Note G — Income taxes, page F-72

8.             As indicated in prior comment number 33 from our letter dated September 27, 2011, a cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome when evaluating whether a valuation allowance for deferred tax assets is needed. Your response to our comment identifies various items of positive evidence that you believe support a conclusion that a valuation allowance is not needed for your net deferred tax asset.

You cite as one element of positive evidence the fact that, excluding the impairment charges, you have cumulative three year pre-tax income.  However, FASB ASC paragraph 740-10-30-22(c) describes a strong earnings history coupled with evidence that the loss (for example, an unusual, infrequent or extraordinary item) is an aberration rather than a continuing event. A full cost ceiling test impairment is not unusual, infrequent or extraordinary.  Similarly, the nature of ceiling test impairments is such that there does not appear to be an objective basis for concluding that they are an aberration.  In this regard, we note the disclosure regarding the volatility of commodity prices and possible future impairments appearing under certain of your risk factors.

You cite as an additional piece of positive evidence the existence of significant proved reserves as of December 31, 2010.  However, estimates of proved reserves include assumptions about prices and costs, which may or may not prove to be accurate in future periods and are fundamentally projections.  Additionally, estimates of cash flows from reserves generally exclude material cost elements for items including exploration and general and administrative that will impact the determination of taxable income in future periods.

Based on the considerations outlined above, it is not clear that the positive evidence you have described in your response is sufficient to overcome the negative evidence, i.e. your cumulative losses.  Further explain to us why you believe the evidence you

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have considered is sufficient to overcome the cumulative losses, or describe any additional positive evidence you have considered.

Response:  We acknowledge the Staff’s comment and respectfully submit that based on our analysis, a valuation allowance for deferred tax assets is not needed.  We do not believe the negative evidence of our cumulative losses incurred in 2008 and 2009 is so significant that this negative evidence cannot be overcome when evaluating the realizability of our deferred tax asset based on the following positive evidence: (i) the factors that caused the non-cash impairment expenses, which led to these cumulative losses, (ii) the existence of significant proved oil and gas reserves, (iii) the ability to recover our net operating loss carryforward deferred tax assets in future years, (iv) our ability to use tax planning strategies, and (v) our current price protection utilizing oil and natural gas hedges in place through December 31, 2013.  The impairment expense recognized in 2008 was due to the historic economic downturn that began in the third quarter of 2008 and continued into 2009, during which time the price of oil and natural gas declined to $39.00 per Bbl and $3.00 per MMBtu, respectively.  In addition, the impairment expense we recognized in 2009 was due to the change in the Commission’s rules regarding the price to use in the full cost ceiling test. If we had used the spot price at December 31, 2009 which was consistent with the old rules, a full cost ceiling impairment would not have been necessary. In this respect, we believe this impairment was more like an aberration.

As our net operating loss carryforward deferred tax asset is recoverable over future years and we have no material net operating losses expiring prior to 2027, we believe it is proper and meaningful when analyzing the negative evidence of our historic three-year results to adjust for items that cannot be expected to occur on a similar basis during the future period allowed to recover the deferred tax asset. We believe the adjusted three-year results provide less negative evidence than that presented by the unadjusted cumulative losses.  Based on our forecasted results, future taxable income will be sufficient to utilize the entire net operating loss carryforward prior to expiration.

ASC 740-10-30-22(c) provides the following example of positive evidence that we believe supports a conclusion that a valuation allowance is not needed when there is negative evidence: “A strong earnings history exclusive of the loss that created the future deductible amount (tax loss carryforward or deductible temporary difference) coupled with evidence indicating that the loss (for example, an unusual, infrequent, or extraordinary item) is an aberration rather than a continuing condition.”  We have a strong earnings history exclusive of the loss that created the future temporary difference (full cost impairments). While we acknowledge that a full cost ceiling impairment is possible in the future, we do not believe the impairments recorded in 2008 and 2009 are indicative of future full cost impairments based on the following: (i) the book basis of our oil and gas assets at December 31, 2010, (ii) the net basis differences in our oil and gas properties represented by a net deferred tax liability of $59.9 million at December 31,

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2010, and (iii) our full cost ceiling cushion (after tax) of $191.9 million and $400.9 million at December 31, 2010 and September 30, 2011, respectively.

In reaching this conclusion, we utilized our third-party independent reserve reports and considered the future net income of $2,824.2 million (pre-tax) and our standardized measure, noting $2,221.7 million of future net cash flows (after taxes). A tax depletion deduction and utilization of our net operating loss carryforward is reflected in the standardized measure calculation, and we believe that the tax bases of the properties and our net operating loss will offset future oil and gas production income (net of production costs and future development costs which are not reflected in bases of the properties at this time). Based on this computation, our future taxable income from verifiable sources is in an amount sufficient to support full realization of the net operating loss deferred tax asset.

Our analysis focused on the application of ASC 740-10-30-18(a) and (b). Paragraph (a) provides that “future reversals of existing taxable temporary differences” is a source of future taxable income “. . . of the appropriate character . . . within the carryback [or] carryforward period available under the current tax law . . .” that may be considered in tax asset realization. The principal attributes are, in our case, net operating loss carryforwards of Laredo.  Thus, we considered the future net taxable amount of the book and tax differences of our oil and gas properties (as represented by the recorded deferred tax liability of $59.9 million at December 31, 2010).  This income would be subject to offset by the net operating loss carryover from both a character (ordinary) and a timing (within the net operating loss carryforward period) perspective.

Paragraph (b) of ASC 740-10-30-18 provides one possible source of taxable income which may be available under the tax law to realize a tax benefit for deductible temporary differences and carryforwards. ASC 740-10-30-22(b) amplifies this provision by citing the presence of “ [A]n excess of appreciated asset value over the tax basis of the entity’s net assets in an amount sufficient to realize the deferred tax asset . . .” as an example of facts supporting a positive assertion that future taxable income will exist exclusive of the reversal of existing temporary differences.  We believe that our producing properties represent such an occurrence.  We note ASC 740-10-30-23 provides reliance on future taxable income exclusive of existing temporary differences requires that objectively verifiable evidence receives a greater weight than evidence that is less verifiable.  We believe Laredo’s reserve reports prepared by independent petroleum engineers meet this “objectively verifiable” requirement. Accordingly, we have applied the appropriate weight to this evidence, which we believe is sufficient to overcome the “cumulative loss” negative factor of the analysis.

We note and acknowledge that any analysis that is based on a forecast is inherently subjective. With this in mind, we based our forecasts on inputs from third party sources and we believe the forecasts we used should be given more positive weight than if we had prepared forecasts solely on an internal basis when considering the recoverability of our

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net deferred tax asset. Our forecast and associated sensitivity testing provides additional positive evidence in forming our conclusion.

As part of our analysis discussed in our letter to the Staff dated October 7, 2011 in response to prior comment 33, we included an estimate of exploration expenses. We recognize that general and administrative expenses (and interest expense) would further reduce this expected future taxable income, but submit that, based upon historical results and significant industry experience, these expenses would not be sufficient in amount to adversely impact this judgment.

As discussed in our 2010 audited combined financial statements, at December 31, 2010 we had price protection over a significant portion of our future forecasted production utilizing oil and natural gas hedges in place through December 31, 2013.  As of December 31, 2010, for the years of 2011, 2012 and 2013, we had hedged 12,377,088 MMBtu, 13,800,000 MMBtu and 13,200,000 MMBtu of natural gas at weighted average prices of $4.89, $4.76 and $4.00, respectively, and we had hedged 1,396,416 Bbls, 1,422,000 Bbls and 1,440,000 Bbls of oil at weighted average prices of $73.40, $72.95 and $69.17, respectively.  Additionally, as of October 31, 2011, for the remainder of 2011, 2012, 2013 and 2014, we have hedged 63%, 53%, 66% and 41% of our forecasted natural gas PDP production at weighted average prices of $5.53, $5.42, $4.59 and $4.59, respectively, and 93%, 105%, 146% and 43% of our forecasted oil PDP production at weighted average prices of $79.25, $78.29, $75.80 and $77.50, respectively.

In summary, we believe we have given the negative evidence, i.e. our cumulative losses, the appropriate weight when considering the need for a valuation allowance at December 31, 2010.  We also believe we applied the correct weight to the factors that gave rise to the cumulative book losses, our projections of future taxable income and the realizability of our deferred tax asset.  The fact that our cumulative book losses were generated from impairment charges that do not result in future tax deductions should reduce the weight given to such negative evidence. The results of our operations for the nine months ended September 30, 2011 have validated our judgment at December 31, 2010 and we expect the trend to continue during the last quarter of 2011, so that our three-year cumulative loss will be eliminated by the end of 2011 and such negative evidence will no longer be a factor.  We considered both the positive and negative evidence at December 31, 2010, and believe the aforementioned positive evidence outweighs the negative evidence and supports that we will more likely than not fully realize our net deferred tax asset prior to expiration.

9.             Provide us, as supplemental information, a schedule that reconciles the future net income of $2,824 million referred to in your response to prior comment number 33 with your standardized measure as of December 31, 2010, as disclosed on page F-96 of your filing.

Response:  As requested, we are supplementally providing the Staff with the requested reconciliation.  Please note that this information is being furnished to the Staff

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under separate cover pursuant to Rule 418(b) under the Securities Act of 1933, as amended, and is not being filed electronically as part of this letter.

Net proved oil and gas reserves (unaudited), page F-95

10.           We note your statement, “Extensions, discoveries and other additions of 91,363 MBOE during the year ended December 31, 2010, consist of 20,533 MBOE primarily from the drilling of new wells during the year and 70,830 MBOE from new proved undeveloped locations added during the year”. As we noted in our comment above pertaining to proved undeveloped reserve disclosure on page 94, please explain the sources of the 71 MMBOE in PUD reserve additions.

Response:  We have revised the Registration Statement accordingly. Please see page F-93.

We hereby acknowledge the Staff’s comments with respect to requesting the acceleration of the effectiveness of the Registration Statement and undertake to comply with the Staff’s request.

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If you have any questions or comments concerning these responses, please call Kenneth E. Dornblaser, our General Counsel, at (918) 513-4570 or Christine B. LaFollette at Akin Gump Strauss Hauer & Feld LLP at (713) 220-5896.

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