corresp.htm

February 10, 2011

[Via EDGAR]

H. Roger Schwall

Division of Corporation Finance

Securities and Exchange Commission

100 F Street NE 100

Washington, DC 20549

Re:	Noble Energy, Inc.

Form 10-K for the Fiscal Year Ended December 31, 2009

Filed February 18, 2010

File No. 001-07964

Dear Mr. Schwall:

Set forth below are our responses to the comments received from the Staff of the Securities and Exchange Commission (the Staff) by letter dated February 9, 2011, regarding our Form 10-K for the fiscal year ended December 31, 2009.

As background to assist in review of these matters, Noble Energy follows the following process in regard to Board of Directors review and approval of projects, and what constitutes a Final Investment Decision (FID) for various projects. Each year, a ten year business plan is reviewed and supported by the Board in the July timeframe. This plan includes specific detailed hydrocarbon projects and forms the basis for the following year’s budget and the forward business plan, as well as, the overall capital and financing plan for the Company. Later in the year, a detailed budget is approved by the Board in the October timeframe; again, this budget includes individual project details.

Further, we classify certain large projects as Major Projects and follow a more detailed process with our Board. Current Major Projects include projects such as Tamar, Aseng and Alen. Major Projects are reviewed on an individual basis with our Board, typically, a number of times and also have a formal sanction by the Board representing our FID. For projects that are not classified as Major Projects, the inclusion of the project in the budget and business plan, and the review and approval of those budgets and plans by executive management and the Board, is deemed to be sufficient for an FID.

The Staff’s comments and our responses thereto are as follows.

Please tell us what new information you received from the end of 2009 to the end of 2010 that apparently now allows you to book proved reserves more confidently in the Tamar field, other than the approval of the Israel government which, in 2009 it was more than reasonably certain that they would approve this large natural gas project due to: their demand for natural gas; their previous track record of approving energy projects; their previous track record of approving energy projects operated by Noble and their publicly reported desire to not have to depend on other Middle East states for their energy needs.

Response:

In January 2009, we announced the Tamar discovery offshore Israel in 5,500 feet of water. The development of the Tamar discovery is a Major Project. We believe the project is the second largest deepwater natural gas discovery made in the world in the last ten years, with gross resources of over 8 Tcf. It will require gross capital commitments of approximately $3 billion to develop. Production start up is scheduled for 2012. A discovery to production cycle time of three years for a major offshore natural gas discovery represents a very fast project based on industry standards.

In July 2010, we reached agreement with the Israeli government on the location of the onshore facilities. Prior to that approval being received, several development options were being considered, both for onshore and offshore facilities, which could have impacted the timing of the project, the capital investment required, the ongoing operating cost assumptions, and the peak production rates.

In 2010, we also completed analysis of core from the Tamar #2 appraisal well and finalized our initial reserve estimates. Our partners made substantial progress on their financing of the project, giving our management and Board increased confidence that the project would move forward.

In December 2010, we received final approval from the Government of Israel for the field development plan.

Given the number of outstanding issues at the end of 2009, we do not believe we had met the “reasonable certainty” threshold for booking proved reserves at Tamar as of December 31, 2009. Considering the scope of this major project, we felt it prudent to finalize development plans, gain increased confidence on partner financing, and receive project approval from our Board of Directors, all of which occurred in 2010, prior to booking proved reserves.

We were also guided by our interpretation of The Compliance & Disclosure Interpretations (provided by the SEC on October 26, 2009), which states:

The mere intent to develop, without more, does not constitute 'adoption' of a development plan and therefore would not, in and of itself, justify recognition of reserves. Rather, adoption requires a final investment decision

This interpretation raised substantial doubt that, without formal approval by our Board of Directors, we had not met our requirement of a “final investment decision” for a major project by the end of 2009.

Prior comment 2 asked whether you have taken a final investment decision on the installation of compression in this field and the basis for your increased reserve estimate due to compression. You do not specifically answer that question in your response. In regards to your response, the fact that significant development planning has occurred does not necessarily justify the classification of proved reserves. You indicate that the reserves have been booked based on a high degree of certainty that the project will be completed and because the operator has sanctioned the project. Again, none of this necessarily justifies the classification of proved reserves and the fact that your management has not sanctioned the reserves but has booked the reserves as proved seems to indicate a lack of confidence in the project. It also does not appear to indicate a sound reserve booking practice. It is not clear to us that if management has not approved the project (i.e. not sanctioned), what is the basis for them approving the reserves to be classified as proved. It would appear that a classification of probable reserves would be more appropriate at such time that management is confident enough to sanction the project.

Furthermore, the intent of our request that you provide us with the evidence that these are new, incremental reserves was that you provide us with the evidence that these are new, proved, incremental reserves. You only provided us with a statement, with no evidence, declaring these to be incremental reserves rather than accelerated reserves. Although reservoir simulation is a good tool for evaluating project development and refinement, it is not necessarily a good tool for distinguishing between classifications of reserves. For example, through simulation you are able to calculate oil in place very accurately but are unable, as far as we know, through that simulation to distinguish the different categories of reserves in that volume of oil in place. Please provide us the evidence that you were able to do this through reservoir simulation in a reliable manner in this case and why it is reliable enough to be considered reasonably certain.

Response:

The Alba field, offshore Equatorial Guinea was discovered in 1984 and has been producing since 1991. Gas is sold from the field to three plants, an LPG plant, a methanol plant, and an LNG plant.

The proved undeveloped (PUD) reserves at Alba are related to the planned installation of compression in the field. The compression project, which is not considered a Major Project, is included in our ongoing budgets and plans for the field, including our business and financial plans, all of which have been reviewed and approved by executive management and our Board of Directors. We believe this meets the requirement of a final investment decision. The formal signing of the Authorization for Expenditure (AFE) will occur once the AFE has been presented by the project operator. The operator has already sanctioned the project.

The installation of compression in the field will lower operating pressures by approximately 1,000 psi, thereby allowing the recovery of the incremental reserves which we have booked as PUD. The significant investment required for the project is planned when the additional flow rates are needed to maintain gas rate capacity for the large plants, while optimizing our economics for the project. Smaller capital projects have been implemented already to maintain capacity, which have allowed delaying the large investment for the compression. The technical understanding of the field (drive mechanism, performance prediction) have remained relatively constant over time.

The volume of PUD reserves that will be produced at those lower operating pressures has been determined via multiple reservoir simulations. All simulations honor geologic data as measured at the wells, and are history-matched to historic bottom hole and wellhead pressures, as well as condensate yields. Our proved reserve simulation is a conservative view, limited by measurable data from actual wells, providing a proved reserve estimate which we believe is reasonably certain. Probable and possible simulations, which indicate an additional 1.5 Tcf of gross natural gas in place beyond our proved reserves, are based on seismic interpretations and other changes to assumptions (e.g. smaller aquifer). The history matches for all simulations are updated each year to ensure that we incorporate all field performance data.

The installation of compression is reliable technology for recovering incremental reserves, as proven on reservoirs around the world. The PUD reserves will be recovered from existing wellbores and flow assurance modeling has been conducted. A market for the reserves exists, and we are committed to the project. Therefore, we believe the reserves meet the definition of proved reserves.

We would be happy to provide you a summary of the simulation work or any additional information that will assist with your review.

Should you have any questions or wish to discuss our responses further, please feel free to contact me, at (281) 872-3100.

Sincerely,

/s/ Kenneth M. Fisher

Kenneth M. Fisher

Senior Vice President and Chief Financial Officer