

	Mayer Brown LLP
	700 Louisiana Street
	Suite 3400
	Houston, Texas 77002-2730
July 25, 2011
	Main Tel +1 713 238 3000
	Main Fax +1 713 238 4888
	www.mayerbrown.com

	Dallas Parker
	Direct Tel +1 713 238 2700
	Direct Fax +1 713 238-4700
BY EDGAR	dparker@mayerbrown.com

H. Roger Schwall

Securities and Exchange Commission

100 F Street N.E.

Washington, D.C. 20549

Re:		Bonanza Creek Energy, Inc.
		Registration Statement on Form S-1
		Filed June 7, 2011
		File No. 333-174765

Dear Mr. Schwall:

On behalf of the above-captioned registrant (the “Company”), enclosed for your information and review are responses to the comments from the staff of the Commission (the “Staff”) set forth in your letter dated July 6, 2011with respect to the above referenced Registration Statement on Form S-1 of the Company (the “Registration Statement”). Set forth below are the Company’s responses to the Staff’s comments. Concurrently with the delivery of this letter, the Company is submitting (via EDGAR) Amendment No. 1 to the Registration Statement (“Amendment No. 1”), which reflects changes made to the Registration Statement in response to the Staff’s comments. Courtesy copies of this letter and Amendment No. 1 (specifically marked to show the changes thereto) are being submitted to the Staff.

This letter is submitted to respond on a point-by-point basis to the Staff’s comments. Each of the Staff’s comments is set forth below (with page references unchanged) and is followed by the Company’s response in bold face type (with page references to Amendment No. 1). All terms used but not defined herein have the meanings assigned to such terms in the Registration Statement.

COMMISSION COMMENTS FOLLOWED BY COMPANY RESPONSES

General

1. Please provide complete responses, and where disclosure has changed, indicate precisely where in the marked version of the amendment we will find your responsive changes. To the extent comments on one section apply to similar disclosure elsewhere, please make

corresponding revisions to all affected areas. This will minimize the need for us to repeat similar comments. Further, please provide updated disclosure with each amendment.

Acknowledged

2. In the amended registration statement, fill in all blanks other than those that contain information you are allowed to omit at the time of effectiveness pursuant to Rule 430A.

Acknowledged

3. You do not yet provide a range for the potential offering price per share. Because other, related disclosure likely will be derived from the midpoint of the range, we remind you to provide the range once it becomes available so that you will have time to respond to any resulting staff comments.

Acknowledged

4. Prior to printing and distributing the preliminary prospectus, please provide us with copies of all artwork and any graphics you propose to include in the prospectus, as well as accompanying captions, if any. We may have comments after reviewing these materials.

Acknowledged

5. Prior to submitting a request for accelerated effectiveness of the registration statement, ensure that we have received a letter or call from the Financial Regulatory Authority (FINRA) which confirms that it (a) has finished its review and (b) has no additional concerns with respect to the underwriting arrangements. Please provide us a copy of that letter, or ensure that FINRA calls us for that purpose.

Acknowledged

6. We note your disclosure that you intend to apply to list your common stock on the New York Stock Exchange. With a view toward disclosure, please advise us regarding the anticipated timing of such listing, and the status of your efforts to seek such listing.

Response:

The Company is currently scheduled for clearance review by the New York Stock Exchange (“NYSE”) on July 28. We expect that the NYSE will provide us with a clearance letter by the end of July, at which time we will submit our listing application. The NYSE informs us that listing approval is typically granted very soon after the application is submitted. We have disclosed the status and anticipated timing of our listing on page 7 of Amendment No. 1.

Prospectus Summary, page 1

7. We note your statement that of your proved reserves, 68.1% were classified as oil and natural gas liquids and 35.1% of which were classified as proved developed. Please explain the classification of the remaining 31.9% and 64.9%, respectively.

Response:

Of our 32,860 MBoe of total proved reserves, 10,481 MBoe (31.9%) are classified as gas reserves and 21,334.6 MBoe (64.9%) are PUD reserves.

8. We note your disclosure on page 70 that any future commercial development of the Niobrara oil shale will require significant investment to construct the infrastructure necessary to gather and transport associated natural gas produced from the formation, and that you are not aware of any current plans to construct or fund this construction in the immediate future. We also note your statement on page 3 that there were no proved or probable reserves identified with respect to 57% of your net acres in Weld and Jackson Counties. As such, please expand to explain in better detail why the Niobrara resource potential is considered a competitive strength.

Response:

As requested, we have expanded our disclosure on pages 3-4 and 69-70 of Amendment No. 1 to explain in better detail why the Niobrara resources potential is considered a competitive strength.

Principal Stockholders, page 5

9. State the percentage of your common stock that is under the control of West Face Capital Inc. and the percentage that it will control following this offering. Discuss the practical effect of this ownership on matters requiring shareholder consent.

Response:

As requested, we have disclosed on page 6 of Amendment No. 1 that pursuant to an investment management agreement between West Face Capital and AIMCo, West Face Capital has the ability prior to the offering to vote approximately 72.66% of our issued and outstanding shares and that such ownership allows West Face Capital to control the outcome of any matter submitted to a vote of the stockholders. Once the price range and offering size is determined, we will revise the Registration Statement to state the percentage of our issued and outstanding shares that West Face Capital will control following the offering.

10. We note that you discuss two stockholders in the risk factor at the bottom of page 30. Please confirm that you have named both of them in this section and provided the information requested in the preceding comment for both.

Response:

As requested, on pages 32-33 of Amendment No. 1 we have identified the stockholders as West Face Capital and clients of AIMCo and explain that by voting as a group West Face Capital and AIMCo, on behalf of its clients, would have the ability to control or substantially influence the outcome of stockholder votes. Once the price range and offering size is determined, we will revise the Registration Statement to state the percentage of our issued and outstanding shares that West Face Capital and AIMCo will each respectively control following the offering.

Risk Factors, page 15

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing..., page 25

11. We note that you use hydraulic fracturing to stimulate production from your wells. Please tell us, with a view towards disclosure:

· your acreage subject to fracking;

· the percentage of your reserves subject to fracking;

· the anticipated costs and funding associated with fracking activities; and

· whether there have been any incidents, citations, or suits related to your fracking operations for environmental concerns, and if so, what your response has been.

Response:

On pages 90-91 of Amendment No. 1 we provide the requested information regarding our hydraulic fracturing operations.

We use hydraulic fracturing as a means to maximize production of oil and gas from formations having low permeability such that natural flow is restricted. Fracture stimulation has been used for decades in both the Rocky Mountains and Mid Continent. In the Rocky Mountains, other companies in the oil and gas industry have fracture stimulated tens of thousands of wells since the mid 1980s. We and our predecessor companies have completed over 300 fracture stimulations since acquiring assets in the DJ Basin in 1999. At our Dorcheat property in the Mid-Continent region, fracture stimulation has been performed since the 1970s and has been used more universally since the early 1990s. We and our predecessor

companies have completed over 40 fracture stimulations since acquiring our Dorcheat properties in mid-2008.

We expect that approximately 91% of our total acreage held as of December 31, 2010 will be subject to hydraulic fracturing in one or more reservoirs, which corresponds to approximately 44% of our total proved reserves. It should be noted that a significant portion of our total acreage does not contain proved reserves at this time.

Our use of hydraulic fracturing is limited mainly to our Mid-Continent and Rocky Mountain regions. Although the cost of each well varies, costs incurred in connection with hydraulic fracturing activities as a percentage of the total cost of drilling and completing a new-drill well average approximately 21% (or $350,000) in our Mid-Continent region and 46% (or $385,000) in our Rocky Mountain region. These costs are accounted for in the same way that all other costs of drilling and completing our wells are accounted for and are included in our normal capital expenditure budget, which is funded through operating cash flows or borrowings under our credit facility. Based on the expected capital forecast in our proved reserve report, we estimate that we will spend approximately $93.1 million for future fracturing activities on both new-drill wells and workovers on existing wells.

For as long as we have owned and operated properties subject to hydraulic fracturing, there have not been any incidents, citations or suits related to fracturing operations or related to environmental concerns from fracturing operations.

12. In regard to your use of hydraulic fracturing, please also tell us what steps you, or the third-party contractors you hire, have taken to minimize any potential environmental impact. For example, and without limitation, please explain if you:

· have steps in place to ensure that your drilling, casing, and cementing adhere to known best practices;

· monitor the rate and pressure of the fracturing treatment in real time for any abrupt change in rate or pressure;

· evaluate the environmental impact of additives to the frac fluid; and

· minimize the use of water and/or dispose of it in a way that minimizes the impact to nearby surface water.

Response:

On page 91 of Amendment No. 1 we describe the steps we and our third-party contractors have taken to minimize any potential environmental impact in regard to our hydraulic fracturing.

We periodically review our plans and policies regarding oil and gas operations, including hydraulic fracturing, in order to minimize any potential environmental impact. We adhere to applicable legal requirements and industry practices for groundwater protection. Our operations are subject to close supervision by state and federal regulators (including the Bureau of Land Management with respect to federal acreage), who frequently inspect our fracturing operations.

During well construction, steel casing pipe and concrete are employed for protection. Once the pipe is set in place, cement is pumped into the well where it hardens to create an isolating barrier between the steel casing pipe and the surrounding geological formations. In accordance with best industry practices, casing and cement design conforms to the applicable requirements and standards of state agencies. As an example, for any fresh water aquifers, a separate string of casing is set below the base as part of the casing design to eliminate any “pathway” for the fracturing fluid to contact any fresh water aquifers during the hydraulic fracturing operations. Furthermore, the hydrocarbon bearing formations are generally separated from any usable underground fresh water aquifers by thousands of feet of impermeable rock layers. This distance is approximately 5,200 feet and 6,200 feet, respectively, for our Rockies and Mid-Continent reservoirs that are being fracture stimulated. This wide separation serves as a protective barrier that prevents any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones. In addition, the vendors conducting hydraulic fracturing on our properties monitor pump rates and pressures during the fracturing treatments. This monitoring occurs on a real-time basis to identify abrupt changes in rate or pressure, which permits the operator to modify or cease the fracturing process.

Typical hydraulic fracturing treatments are made up of water, chemical additives and sand. We utilize major hydraulic fracturing service companies who track and report all additive chemicals that are used in fracturing as required by the appropriate government agencies. Each of these companies fracture stimulate a multitude of wells for the industry each year.

We strive to minimize water usage in our fracture stimulation designs. Water recovered from our hydraulic fracturing operations is disposed of in a way that does not impact surface waters. We dispose of our recovered water by means of approved disposal or injection wells.

13. In light of the public concern over the risks relating to hydraulic fracturing, please review your disclosure to ensure that you have disclosed all material information regarding your potential liability. This would include, for example, your potential liability in connection with an environmental contamination related to your drilling and fracturing operations. For example, and without limitation, please address the following with respect to your drilling and fracturing operations:

· disclose the applicable policy limits related to your insurance coverage;

· disclose your related indemnification obligations and those of your customers or business partners, if applicable;

· clarify your insurance coverage with respect to any liability related to any resulting negative environmental effects; and

· provide further detail on the risks for which you are insured for your hydraulic fracturing operations.

Response:

On pages 22-23 of Amendment No. 1 we discuss our potential liability in connection with our hydraulic fracturing operations and our insurance coverage and indemnification obligations.

We carry insurance to reduce our exposure to sudden and accidental environmental contamination but do not have coverage for gradual, long-term contamination. Our policies include operator’s extra expense (“OEE”) coverage with a $1.0 million limit per occurrence; commercial general liability (“CGL”) coverage with a time element pollution limit of $1.0 million per occurrence and in the aggregate; and excess liability coverage with a $10.0 million limit per occurrence and in the aggregate. Our OEE policy provides primary coverage for the cleanup of polluting or contaminating substances caused by a sudden and accidental loss of control of a well at the surface. The CGL and Excess Liability policies also provide sudden and accidental pollution liability coverage, including coverage in excess of the OEE policy limit for pollution caused by a well out of control at the surface. In order to obtain coverage, we must report the event to the insurance company within 90 days after its commencement. The CGL policy also contains a $1.0 million aggregate limit for damage to oil, gas, water or other mineral substances that have not been reduced to physical possession above the surface.

Since our hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean up costs stemming from a sudden and accidental pollution event, provided that we

report the event within 90 days after its commencement. We may not have coverage if the operator is unaware of the pollution event and unable to report the “occurrence” to the insurance company within the required time frame. Nor do we have coverage for gradual, long-term pollution events.

Pursuant to our surface leases, we typically indemnify the surface owner for clean up and remediation of the site. As owner and operator of oil and gas wells and associated gathering systems and pipelines, we typically indemnify the drilling contractor for pollution emanating from the well, while the contractor indemnifies us against pollution emanating from its equipment.

14. In this regard, discuss what remediation plans or procedures you have in place to deal with the environmental impact that would occur in the event of a spill or leak from your hydraulic fracturing operations.

Response:

On page 92 of Amendment No. 1 we discuss our remediation plans and procedures in place to deal with the environmental impact of a spill or leak from our hydraulic fracturing operations.

Surface spills and leaks are controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions, as well as any Spill Prevention, Control and Countermeasures (SPCC) plans we maintain in accordance with EPA requirements. This would include any action up to and including total abandonment of the wellbore.

Two of our stockholders will together beneficially own or control..., page 30

15. Please identify the two stockholders to which you refer. Indicate whether these stockholders currently have any agreement, written or otherwise, with respect to voting or investment decisions relating to their shares of common stock.

Response:

As requested, on pages 32-33 of Amendment No. 1 we have identified the stockholders as West Face Capital and clients of AIMCo and describe the investment management agreement under which West Face Capital has the right prior to the offering to vote the shares of our common stock held by clients of AIMCo.

Use of Proceeds, page 34

16. Once you know the expected size of the offering, and no later than when you provide the price range for the offering, you will need to provide the estimated amounts you intend to allocate to each of the identified uses. In that regard, it is insufficient to indicate that the remaining proceeds will be used for “[your] exploration and development program and for general corporate purposes.” Instead, provide necessary detail for each intended use, and present the information in tabular form to facilitate clarity. If you have no specific plan for a significant portion of the proceeds, state this explicitly, and discuss the principal reasons for the offering at this time. Refer generally to Item 504 of Regulation S-K.

Response:

As requested, we have disclosed on page 36 of Amendment No. 1 that the remaining proceeds will be used to repay all outstanding indebtedness under our credit facility, to fund our drilling and development program and to fund the expansion of our gas processing facilities. Also, as requested, we have disclosed in tabular form on page 36 the amount to be allocated to each of the intended uses of proceeds. Once the offering price is determined, we will revise Amendment No. 1 to state the amounts to be allocated to each such use.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 43

Results of Operations, page 46

17. Please expand your disclosure to identify the underlying reasons for all material variances in your other income and expense line items. In this regard, we note you do not discuss your amortization of debt discount and the unrealized gain (loss) in fair value of the warrant put option for any of the reporting periods presented.

Response:

As requested, on pages 51-52, 55 and 58 of Amendment No. 1 we have expanded our disclosure of the underlying reasons for all material variances in our other income and expense line items and specifically discuss our amortization of debt discount and unrealized loss in fair value of the warrant put option for the reporting periods presented.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009, page 49

Operating expenses, page 51

18. We note in 2010 you recognized $2,378,000 of expenses related to a cancelled private placement. Please disclose in further detail the origin of this expenditure to comply with the guidance of Item 303(a)(3)(i) and (ii), and Instruction 3 to paragraph 303(a) of Regulation S-K.

Response:

As requested, on page 55 of Amendment No. 1 we disclose further detail relating to the cancelled private offering.

Gain on Sale of Oil and Gas Properties, page 52

19. We note your disclosure indicating that you recognized a gain on sale of property interests in the amount of $4.1 million in March 2010. Please explain why you did not discuss this gain in your results of operations discussion for the interim periods.

Response:

On page 51 of Amendment No. 1 we explain in our results of operations discussion for the interim periods that the $4.1 million gain on sale of property interests in March 2010 was attributable to the sale of our non-operated working interest in the Jasmin, California property.

Liquidity and Capital Resources, page 54

Cash Flows Provided by Operating Activities, page 55

20. It appears you have limited your discussion of cash flows from operating activities to only quantifying the changes in working capital for each reporting period. Please consider the guidance found in FRC 501.13b and revise your discussion to disclose the reasons underlying the material changes in your working capital from period to period.

Response:

As requested, on page 59 of Amendment No. 1 we have revised our discussion to disclose the reasons underlying the material changes in our working capital from period to period.

Business, page 63

21. Disclose your reserves in the tabular format provided in Regulation S-K, Item 1202(a)(1)-(4).

Response:

As requested, on page 67 of Amendment No. 1 we have provided a table of our reserves in the format provided for in Regulation S-K.

Proved Undeveloped Reserves, page 70

22. We note your disclosure in which you report an increase of 12,989 MBoe in proved undeveloped reserves from 2009 to 2010. Further, we note you disclose the conversion of 1,108 MBoe proved undeveloped reserves to proved developed reserves contributed to this increase; however, this conversion would actually decrease the quantity of proved undeveloped reserves in 2010. Please revise your disclosure to resolve this inconsistency accordingly.

Response:

We inadvertently included incorrect data in this section. One pages 75-76 of Amendment No. 1 we have included the corrected data.

Executive Compensation and Other Information, page 92

23. We note that for your NEOs, roughly 89-97% of their total compensation in the last three years was paid in base salary and annual incentive (cash) awards. As such, it appears that long-term incentives such as stock awards have historically played a very small role in your compensation program. On the other hand, you state that you intend to use the 50th percentile of your peer group as a guideline in terms of setting long-term incentive compensation. Please discuss in better detail how this will affect the percentage of total future compensation that will be paid in the form of long-term incentives.

Response:

While historically long-term incentives have played a small role in the compensation of our named executive officers, in connection with this offering, consistent with our philosophy of setting compensation levels at or near the 50th percentile of our peer group, we intend to implement a Long-term Incentive Plan under which we expect that a significant portion of our named executive officers’ overall compensation will be made up of long-term incentives. The average portion of total compensation paid as long-term incentives for the named executive officers of our peer group is approximately 40%.

As requested, on pages 99-100 of Amendment No. 1 we discuss in more detail how use of the 50th percentile of our peer group as a guideline will affect the percentage of total future compensation that will be paid in the form of long-term incentives.

24. We note your statement on page 95 that “we expect that in connection with this offering, our compensation committee will propose, subject to approval by our board of directors, an increase in the base salaries of our named executive officers in order set their base salaries closer to the market 50th percentile with appropriate adjustments for level of experience and job responsibility.” Please provide quantitative disclosure of the market 50th percentile base salaries for your NEO positions, such as your CEO, COO and CAO.

Response:

The salary changes referenced were recently approved and implemented. We have also provided the information requested for the comparable named executive officers of our peer group.

As requested, on pages 102-03 of Amendment No. 1 we provide quantitative disclosure of the market 50th percentile base salaries for our NEO positions, such as our CEO, COO and CAO.

25. Please expand your disclosure regarding your annual cash incentive compensation to explain in better detail what is meant by the statement that your board determined “the aggregate amount to be paid as bonuses as a percentage of our EBITDA for the fiscal year.” For example, disclose your actual EBITDA for the fiscal year, and discuss how you calculated the $250,000 aggregate bonus amount from this number, as applicable. In addition, provide further detail as to the “contributions and performance” that led to the bonus amounts awarded to each of the NEOs.

Response:

As requested, on pages 103-04 of Amendment No. 1 we have expanded our disclosure regarding our annual cash incentive compensation. With regard to the “contributions and performance” that led to the bonus amounts, management has historically utilized the aggregate bonus pools paid out by our peers relative to the EBITDAX levels generated each year by those peers as a comparative tool to recommend aggregate bonus pool levels to our board of directors for approval. The bonus pool amount approved by our board of directors and paid to employees was entirely discretionary but typically varied between 0.5% and 5% of EBITDAX generated for that year. In 2010, the aggregate bonus pool paid to employees represented approximately 1% of EBITDAX generated by the Company. For 2010, Mr. Wilson and Mr. Grove received the largest bonuses for their efforts in

refinancing our debt position and achieving strong reserve bookings in 2009, respectively.

26. In the potential payments table on page 104, please explain the “Total” rows, which appear to be blank.

Response:

The total row is intended to show the total potential value to be received upon certain termination scenarios for each of our named executive officers. On page 112 of Amendment No. 1, we have provided the totals for this table.

Certain Relationships and Related Party Transactions, page 107

27. Please explain how the terms of these transactions were determined, such as the terms for the services provided to HEC and the interest rate of the CJ Bennett Family Trust unsecured subordinated note.

Response:

HEC Services. In 2009, HEC entered into a “Contract Field Operating Agreement” with certain of our subsidiaries to operate and develop all HEC properties in Arkansas and Colorado. HEC compensated such subsidiaries for work based on overhead rates that were billed to HEC in a manner similar to overhead rates billed to working interest parties though Joint Operating Agreements (“JOA”). The overhead rates were determined based on a review of JOAs for comparable operations in the vicinity of the HEC properties and were set for producing wells at $350 per well per month and drilling wells at $5,000 per well per month (prorated for periods less than a full month). In addition, HEC entered into a “Management Fee Agreement” with certain of our subsidiaries to manage the operations of HEC. The management rate of $200 per well per month was negotiated between and agreed to by the Managers of HEC and such subsidiaries.

Bennett Note. The C.J. Bennett Family Trust unsecured subordinated note (“Bennett Note”) was issued by BCEC in March 2008 to meet financing needs for the acquisition of properties in Arkansas. The terms of the Bennett Note were negotiated by the parties. The Bennett Note accrued cash interest at an annual rate of 12% (13% if paid-in-kind at our election) and had an initial term of 11 months (which was subsequently extended). Additionally, the Bennett Note was subordinated to both our credit facility and our senior subordinated unsecured notes, and could not be retired without the approval of the senior lenders (such approval not being granted until the December 2010 financing transaction with West Face Capital). In contrast to our senior subordinated unsecured notes, the

Bennett Note did not contain an equity component or board representation rights. Accordingly, our board of directors determined that the interest rate paid on the Bennett Note was appropriate compensation given its subordinated priority and the difference in terms with our senior subordinated unsecured notes.

In contemplation of this offering, we have adopted policies that require future related-party transactions between us and our directors, officers and their family to be authorized by our audit committee.

Principal and Selling Stockholders, page 112

28. Footnote 2 of your beneficial ownership table indicates that West Face Capital has voting and investment power over the shares held by Project Black Bear LP. Please include West Face Capital and its ownership interest in your table, or advise.

Response:

As requested, on pages 120-121 of Amendment No. 1 we have included West Face Capital and its ownership interest on the beneficial ownership table.

29. Several of your footnotes indicate that the named beneficial owner in the table “disclaims beneficial ownership... except to the extent of his pecuniary interest therein.” Please explain in better detail what is meant by this statement. As an example only, please explain why the shares held by Mr. Carty consist of those shares held by Black Bear, and disclose the extent of Mr. Carty’s pecuniary interest in these shares.

Response:

As requested, on pages 120-121 of Amendment No. 1 we have revised several of the footnotes. For Mr. Overbergen (footnote (8)), we have included a disclaimer of beneficial ownership to make clear the fact that, while we has a relationship with one of our stockholders, he does not have voting or investment control over the shares held by that stockholder. For footnotes (2), (3) and (4), we have included disclaimers of beneficial ownership for those persons who exercise voting and investment control over our shares on behalf of an employer and not for their own benefit.

30. Please disclose whether any selling shareholder is a registered broker-dealer or affiliate of a registered broker-dealer. If you determine that a selling shareholder is a registered broker-dealer, please revise your disclosure to indicate that such selling shareholder is an underwriter, unless such selling shareholder received its securities as compensation for investment banking services. If a selling shareholder is an affiliate of a registered broker- dealer, please disclose, if true, that such selling shareholder acquired its shares in the

ordinary course of business and at the time of the acquisition did not have any arrangements or understandings with any person to distribute the securities. If not, you must indicate that such selling shareholder is an underwriter.

Response:

As requested, on page 120 of Amendment No. 1 we disclose that none of the selling shareholders is a registered broker-dealer or an affiliate of a registered broker-dealer.

31. Please disclose the natural person or persons who have voting or investment control over the shares to be offered by the legal entities listed as selling stockholders. This includes West Face Capital, which has delegated voting and investment power over the shares held by Project Black Bear LP.

Response:

As requested, on page 121 of Amendment No. 1 we have disclosed the natural persons who have voting or investment control over the shares to be offered by the selling stockholders.

Financial Statements, page F-1

32. We note that your financial statements reflect the Corporate Restructuring as if it occurred on December 31, 2010 rather than as of the effective date, December 23, 2010. Please revise your presentation to clearly differentiate between the predecessor and successor financial information by presenting separate audited statements of income, stockholders equity and cash flows of the successor for the period December 24, 2010 through December 31, 2010 and of the predecessor for the period January 1, 2010 through December 23, 2010.

Please note that the financial statements for the registrant and its predecessor should collectively be ‘as of’ all dates and ‘for’ all periods required by Article 3 of Regulation S-X. Therefore, your predecessor financial statements must include an audited balance sheet as of December 31, 2009 and unaudited comparative interim period statements of income and cash flows through March 31, 2010.

Please confirm that you understand you will be required to continue presenting predecessor financial statements and the applicable management’s discussion and analysis in your periodic reports subsequent to the effective date of your registration statement, to the extent necessary to cover all periods prescribed by the form. Please contact us by telephone if you require further clarification or guidance.

Response:

As requested, we have provided our separate audited statements of income, stockholders equity and cash flows for the period December 24, 2010 through December 31, 2010 and for BCEC as our predecessor for the period January 1, 2010 through December 23, 2010. We have also provided in the BCEC financial statements an audited balance sheet as of December 31, 2009 and unaudited comparative interim period statements of income and cash flows through March 31, 2010. We understand we will be required to continue presenting predecessor financial statements and the applicable management’s discussion and analysis in our periodic reports subsequent to the effective date of our registration statement, to the extent necessary to cover all periods prescribed by the form.

Bonanza Creek Energy, Inc.

Audited Financial Statements

Note 14 — Disclosures About Oil and Gas Producing Activities (Unaudited), page F-16

33. Please separately disclose the net quantities of your interests in proved undeveloped reserves as of the beginning and the end of the year as required by FASB ASC 932-235- 50-4. Refer to Example 1 at FASB ASC 932-235-55-2 for an illustration of this required disclosure. This comment is also applicable to your disclosures of reserve quantity information presented in the financial statements of BCEC and Holmes Eastern Company, LLC.

Response:

As requested, on pages F-22, F-55 and F-67 of Amendment No. 1 we have disclosed the net quantities of our interests in PUDs as of the beginning and the end of the year for the Company, BCEC and HEC respectively.

Bonanza Creek Energy, Inc.

Unaudited Interim Financial Statements

Note 5 — Fair Value Measurement and Asset Retirement Obligation, page F-25

34. Please provide a reconciliation of the beginning and ending balances for fair value measurements using significant unobservable inputs (Level 3) for the interim period ended March 31, 2011 to comply with FASB ASC paragraph 820-10-50-2. Note this disclosure requirement for interim periods became effective for fiscal years beginning after December 15, 2010 and for interim periods within those interim periods. Refer to the transition guidance found at FASB ASC 820-10-65-7.

Response:

As requested, we have expanded our disclosure on page F-32 of Amendment No. 1.

Bonanza Creek Energy Company, LLC

Audited Financial Statements

Note 2 — Summary of Significant Accounting Policies, page F-33

Income Taxes, page F-34

35. We note your presentation of pro forma income taxes and pro forma net income (loss) on the face of your consolidated statements of operations. Further, we note you believe BCEC would not be subject to any income tax had they been a tax reporting entity for any of the periods presented due to “the permanent differences between financial reporting and tax reporting on this change to fair value of the warrant put option.” Please clarify in further detail your assumptions for estimating income taxes of nil for all reporting periods.

Response:

On pages F-41-42 of Amendment No. 1 we disclose our assumptions for estimating income taxes of nil for BCEC.

The Pro Forma income statements for the years ended December 31, 2008, 2009, and 2010 do not report an income tax expense or benefit. Included in the income statements is a “Change in fair value of warrant put option” in the amount of $70,972,241, $(80,639,866), and $34,344,894, respectively, for the years ended December 31, 2008, 2009, and 2010. The change in the fair value of warrant put option is a permanent book/tax difference that will never be recognized for income tax purposes upon conversion to equity. In all three years reported, there is a net book loss after removing the change in the fair value of warrant put option. Further, in all three years reported, there is a taxable loss that exceeds the book loss primarily due to deductions for intangible drilling costs, depletion, and depreciation for income tax purposes in excess of those for book purposes. Therefore, there is no current income tax expense to recognize in all three years reported. As there is a net book loss for all three years reported, after removing the change in fair value of warrant put option, a deferred income tax benefit and a related deferred tax asset would be calculated under FAS 109 / ASC 740. However, based on all evidence, Management believes that a full valuation allowance should be placed on the deferred tax asset as it is more likely than not that the deferred tax asset would not be realized in the future. Based on the above, there should not be anything recorded for income taxes on the Pro Forma financial statements for all three years reported.

Concentration of Credit Risk, page F-35

36. We note your disclosure in which you state you had two major customers that “...provided approximately 82% of total revenue for the period ended December 23, 2010...” and “... had six other customers that provided approximately 82% and 80%, respectively, of total revenue for the years ended December 31, 2009 and 2008....” Please disclose the revenues from each customer which contributed 10% or more of your revenues in each reporting period to comply with the guidance of FASB ASC 280-10-50- 42.

Response:

As requested, we have disclosed on pages F-9 and F-42 of Amendment No. 1 the revenues from each customer which contributed 10% or more of our revenues in each reporting period.

Note 11 — Disclosures About Oil and Gas Producing Activities (Unaudited), page F-45

37. We note that you report positive oil and gas revisions which appear to be material. Please disclose your explanations for these significant changes to comply with FASB ASC 932-235-50-5.

Response:

As requested, we have disclosed on page F-55 of Amendment No. 1 our explanation for the positive oil and gas revisions.

In 2008, net revisions to previous estimates of 1,303 MBoe resulted primarily from well results and extensive engineering and geological reviews of the Mid-Continent properties that led to a change in planned development well spacing from 20 acres to 10 acres.

In 2010, net revisions to previous estimates of 1,969 MBoe were due primarily to positive price changes and changes to the rate forecasts for wells in the Mid-Continent region based on results from improved stimulation techniques in smaller, tighter, higher gas oil ratio sands that led to increased gas reserves and slightly higher NGL reserves.

Holmes Eastern Company, LLC

Financial Statements

Note 7 — Disclosures About Oil and Gas Producing Activities (Unaudited), page F-57

38. We note that you report both negative oil revisions and positive gas revisions in 2010 which appear to be material. Please disclose your explanations for these significant changes to comply with FASB ASC 932-235-50-5.

Response:

As requested, we have disclosed on page F-67 of Amendment No. 1 our explanation for our negative oil revisions and our positive gas revisions in 2010.

In 2010 there were revisions to the reserve estimates attributed to HEC of -441 Mbbls and +5,174 MMcf. Net revisions to previous estimates were due primarily to changes to the rate forecasts for wells in the Mid-Continent region based on results from improved stimulation techniques in smaller, tighter, higher gas oil ratio sands that led to slightly lower oil but increased gas reserves.

Exhibits

39. You have omitted a number of exhibits that Item 601 of Regulation S-K requires you to file. The staff reserves the right to review and comment upon all exhibits. To expedite the processing of your filing and to ensure that you have adequate time to respond to any future staff comments, please file with the next amended registration statement all such exhibits, including the opinion of counsel and all material contracts.

Response:

As requested, we have filed with Amendment No. 1 the following exhibits:

· Registration Rights Agreement, dated as of December 23, 2010;

· Form of Indemnity Agreement with each of the directors and executive officers;

· Stock Purchase Agreement, dated as of December 23, 2010, between the Company, BCEOC, Project Black Bear LP and Her Majesty Queen in Right of Alberta;

· Contribution Agreement, dated as of December 23, 2010, among the company and BCEC; and

· Contribution Agreement, dated as of December 23, 2010, among the Company, BCEC, BCEOC, Bonanza Creek Energy Resources, LLC and members of HEC

Certain other documents we expect to file as exhibits are still being finalized. These documents include the Form of Second Amended and Restated Certificate of Incorporation, the Form of Second Amended and Restated Bylaws of the Company and certain compensation agreements. We expect to complete these documents soon and will file them at the earliest possible time. We have not yet provided an opinion of counsel since we feel it is premature to do so prior to the pricing of the offering.

40. In this regard, please be sure to file material contracts with your principal customers, including Lion Oil and Plains Marketing, or tell us why these do not need to be filed.

Response:

Although Lion Oil and Plains Marketing are our primary customers for oil sales, we do not consider our contracts with them to be material to our business since the goods we sell pursuant to the contracts are commodities, the pricing terms are typical for our industry and the agreements may be terminated by either party upon 30 days notice. If our contracts with either of these customers were to be terminated, we are confident that we could find substitute purchasers for our goods at comparable prices by entering into similar agreements or by selling our goods on the open market.

Exhibits 99.1 and 99.2

41. We note that your reserves have been estimated by Cawley, Gillespie & Associates, Inc. Please obtain and file new reports that discuss the possible effects of regulation on the ability of the registrant to recover the estimated reserves as required by Item 1202(8)(vi).

Response:

Our reserve reports prepared by Cawley, Gillespie & Associates, Inc. take into consideration the impact of current regulations on our recovery of reserves, as expressed by the following language included in each of our reserve reports prepared by them:

The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the effective date except as noted herein. The possible

effects of changes in legislation or other Federal or State restrictive actions have not been considered. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Cawley, Gillespie & Associates, Inc. advises us that it is not otherwise aware of other possible effects of regulation on our ability to recover our estimated reserves.

Exhibits 99.1, 99.2 and 99.3

42. Text in each of the reports states that the particular report was prepared for the exclusive use of Bonanza Creek and may not be put to other use without the prior written consent of the report provider. Item 1202(a)(8) of Regulation S-K requires the reports and it is inappropriate to limit investor reliance on reports included with your filing. Please obtain and file revised versions of each report which retain no language that could suggest either a limited audience or a limit on potential investor reliance.

Response:

We have made the requested revisions to the reports, which are filed as Exhibits 99.1, 99.2 and 99.3.

Engineering Comments

General Information

43. Please expand your disclosure to present a section on Present Activities, including the number of wells you were currently drilling as of December 31, 2010. Please see paragraphs (a)(b)(c)(d) of Item 1206 of Regulation S-K.

Response:

As requested, we have expanded our disclosure on page 79 of Amendment No. 1 to include a section on Present Activities including the number of wells we are currently drilling. As of April 30, 2011, we were in the process of drilling 5.0 gross (4.2 net) wells. Of these wells, 2.0 gross (2.0 net) were exploratory wells in progress in the Rocky Mountain region, and 2.0 gross (1.7 net) and 1.0 gross (0.5 net) were development wells in progress in the Mid-Continent and California regions, respectively. Additionally, to accommodate future increased gas volumes, we are in the process of building a 12.5 MMcf/d processing facility in our Dorcheat Macedonia Field in the Mid-Continent region.

44. Please expand your disclosure to present a section on Delivery Commitments. Please see paragraph (a)(b)(c)(d) of Item 1207 of Regulation S-K.

Response:

We have revised our disclosure on page 78 of Amendment No. 1 to state that we are not party to any agreements pursuant to which we must deliver a specified quantity of our oil or gas production.

45. Please provide a copy of your 2010 reserve report by Cawley Gillespie & Associates which includes annual estimated cash flows for each well.

Response:

As requested, we have delivered a copy of our 2010 reserve report.

Development Project by Region, page 2

46. In the Rocky Mountain area please tell us how many PUDs you have booked as proved in the Niobrara Shale, the basis for calling those locations proved and if the PUD wells will be drilled as horizontal or vertical wells. Please also tell us the average EUR for the wells currently producing from the Niobrara Shale and if they are horizontal or vertical wells.

Response:

We currently do not have any PUD locations for horizontal wells in the Niobrara Shale. However, we do have 93 PUD locations for vertical production, which include the Niobrara Shale along with the Codell Sandstone. The average EUR for the vertical wells is 61.1 MBoe. We categorize these vertical wells as proved by analogy to the multiple similarly completed wells in the area. Thousands of wells with similar completions have been drilled by operators in the DJ Basin. We and our predecessor companies have drilled in excess of 150 wells of similar completion through June 30, 2011. Accordingly, the average EUR for wells currently producing from the Niobrara/Codell is 70.8 MBoe.

North Park Basin, page 69

47. Please tell us where the EOG Niobrara wells are in relation to your properties.

Response:

Our acreage position in the North Park Basin is approximately 15 to 20 miles northeast of the Niobrara horizontal wells drilled by EOG Resources. The Niobrara

formation in our acreage is comparable in depth to EOG Resources’ area. Measurements of resistivity and porosity from well logs are of similar characteristics between the two areas. Correspondingly, the thermal maturity of the Niobrara derived from well log and analytical evaluation provide values within the same range. The Niobrara has proven to be productive in both areas as well.

Proved Undeveloped Reserves, page 70

48. At your current rate of conversion of PUD to proved developed it does not appear you can convert your current PUDs within five years. Please tell us how you plan to do this. Also, please disclose the capital you spent in 2010 to convert your PUDs to proved developed. Please see paragraph (c) of Item 1203 of Regulation S-K.

Response:

As requested, we have disclosed on pages 75-76 of Amendment No. 1 the capital we spent in 2010 to convert our PUDs to proved developed.

During the 2010 calendar year, 41 proved undeveloped locations were drilled and converted to proved developed producing with a total capital expenditure of $21.6 million.

Our proved reserves estimates prepared by Cawley Gillespie & Associates, Inc. for the year ended December 31, 2010 identified 297 proved undeveloped well locations. During the 2011 calendar year, we have implemented an accelerated drilling schedule with an approved capital budget that calls for drilling 114 producing wells. Through July 7, 2011, a total of 74 wells have been spud, including 26 in the Mid-Continent region, 45 in the Rocky Mountain region and 3 in the California region. The table below presents the number of wells identified in the current reserve report, wells approved for drilling in 2011 and the number of years required to fully develop at a rate consistent with the 114 wells planned for drilling in the 2011 calendar year.

Region	PUDs in Reserve Report	2011 Plan	Years to Develop
Mid-Continent Region	188	42	4.5
Rocky Mountain Region	91	66	1.4
California Region	18	6	3.0
Total	297	114	2.6

Technology Used to Establish Proved Reserves, page 71

49. Please tell us what technology or method was used by Cawley Gillespie & Associates to establish the EUR for vertical wells and for horizontal wells in the Niobrara Shale.

Response:

Our reserve report does not currently contain any horizontal wells in the Niobrara Shale. The vertical wells that will produce from the Niobrara Shale are comingled with the Codell Sandstone. We and other operators have drilled thousands of vertical wells with similar completions in the DJ Basin. EURs for the PUD vertical wells are mainly based on analogy to those of surrounding producers. We and our predecessor companies have drilled in excess of 150 vertical wells in the DJ Basin. The estimated average EUR from our current producing wells in the Codell/Niobrara is 70.8 MBoe versus an estimated average EUR of 61.1 MBoe for the Codell/Niobrara vertical PUD locations.

Operating Data, page 72

50. Please tell us the reason for the significant decline in per barrel equivalent operating costs from 2008 to 2009.

Response:

Our production expense decreased $7.0 million, or 34%, to $13.4 million in 2009 from $20.4 million in 2008 and decreased on an equivalent basis from $34.02 per Boe to $18.35 per Boe. The decrease in production expense on a Boe equivalent basis is due primarily to significantly lower steaming costs related to heavy oil production in our Western region (the Midway Sunset, California field and the Red Springs, Wyoming field), increased production from our Arkansas properties, and lower service costs in 2009 compared to 2008 related to a downturn in the economy and pressure on contractors to lower costs. The Western region’s steam cost (purchase natural gas and water) decreased $5.4 million, or 96%, to $0.2 million in 2009 from $5.6 million in 2008 and decreased on an equivalent basis from $37.97 per Boe to $1.70 per Boe. Production from our Arkansas properties increased 151,030 Boe, or 65%, to 381,831 Boe in 2009 as compared to 230,801 in 2008, which primarily contributed to lower operating expense on an equivalent basis of $11.55 per Boe from $33.12 per Boe in 2008 to $21.57 per Boe in 2009.

Acquisitions, page F-10

51. Please tell us why you did not disclose a pro forma presentation of the reserve and Standardized Measure information.

Response:

We have disclosed on pages F-13-16 of Amendment No. 1 a pro forma presentation of the reserve and Standardized Measure information.

* * * *

Any questions regarding the above responses or Amendment No. 1 should be directed to either Dallas Parker at (713) 238-2700 or Andrew J. Stanger at (713) 238-2702.

Thank you for your attention to this filing.

	Very truly yours,


	/s/ Dallas Parker

	Dallas Parker

cc: Michael R. Starzer

Andrew J. Stanger