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[SM LETTERHEAD]

November 27, 2012

Ethan Horowitz

Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

100 F. Street, N.E.

Washington, D.C. 20549

Re:                             SM Energy Company
 Form 10-K for Fiscal Year Ended December 31, 2011
 Filed February 23, 2012
 Form 10-Q for Fiscal Quarter Ended September 30, 2012
 Filed November 1, 2012
 File No. 001-31539

Dear Mr. Horowitz:

Set forth below are the responses of SM Energy Company, a Delaware corporation (the “Company,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated November 9, 2012, with respect to the Staff’s review of the Company’s Form 10-K for the fiscal year ended December 31, 2011, filed with the Commission on February 23, 2012 (the “Form 10-K”), and Form 10-Q for the fiscal quarter ended September 30, 2012, filed with the Commission on November 1, 2012 (the “Form 10-Q”).  For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.

Form 10-K for Fiscal Year Ended December 31, 2011

Proved Undeveloped Reserves, page 11

1.                                      We note you converted 8% of your proved undeveloped reserves (“PUDs”) to proved developed reserves in 2011.  Please tell us about your development plans in sufficient detail to explain how you intend to convert your PUDs within five years from initial booking.

RESPONSE:  Our 2011 conversion rate of proved undeveloped (“PUD”) reserves to proved developed (“PD”) reserves is not indicative of our intended future pace of PUD reserve

development, because our 2011 drilling and completion schedule for our key plays focused on delineating our acreage position and drilling lease-holding obligation wells.  In 2012, we have largely completed our delineation and lease holding activities, and have begun turning our focus to converting previously booked PUD reserves to PD reserves.  We intend to develop more than 97.7% of our PUD reserves as of year-end 2011 within a five-year time frame from their initial booking date.  Plans for the remaining 2.3% are addressed in our response to comment 2 below.

Our two biggest plays accounted for 73.9% of our PUD reserves at the end of 2011.  Our Eagle Ford assets accounted for 222 bcfe, or 53.4% of our year-end 2011 PUD reserves.  Due to our large Eagle Ford acreage position, we focused a large majority of our 2011 drilling and completion activities in this play on delineating our acreage rather than on developing our PUD locations.  While only three gross operated and three gross non-operated PUD reserve locations were converted in 2011, we developed a total of 47 gross wells on our operated acreage in 2011 and the operator of our non-operated acreage developed a total of 153 gross wells in the same period.(1)  The 222 bcfe booked on our Eagle Ford assets at year-end 2011 represents 45 gross operated locations and 66 gross non-operated locations, and, as we continue to develop this play, we intend to allocate the capital necessary and focus our efforts on developing a larger percentage of our PUD inventory annually.  As evidence of our commitment to timely develop this play, our 2012 capital budget (as of December 31, 2011) included 85 gross operated Eagle Ford wells and 161 gross non-operated Eagle Ford wells, of which 60 and 201 (more than we budgeted), respectively, had been completed as of October 31, 2012.  We anticipate that 2012 operated and non-operated drilling and completion activities will convert in excess of 19% of our 2011 PUD reserves in this play.

Our second biggest play, the Bakken/Three Forks in North Dakota, accounted for 85 bcfe, or 20.5% of our year-end 2011 PUD reserves.  We focused our 2011 activities on drilling and completing lease-holding obligation wells, and therefore, we did not drill and complete a large number of our PUD locations in 2011.  PUD conversions accounted for 7 bcfe of developed Bakken/Three Forks reserves in 12 gross wells; however, an additional 81 wells accounting for 37 bcfe were drilled in the play in 2011 from unproved categories.  The 85 bcfe booked on our Bakken/Three Forks assets at year-end 2011 represents 104 gross locations.  As we continue to develop this play, we intend to allocate the capital necessary and focus our efforts on developing a larger percentage of our PUD inventory annually.  As evidence of our commitment to timely develop this play, our 2012 capital budget (as of December 31, 2011) included 34 gross operated Bakken/Three Forks wells and 52 gross non-operated Bakken/Three Forks wells, of which, 29 and 104 (more than we budgeted), respectively, had been completed as of October 31, 2012.  We anticipate that 2012 operated and non-operated drilling and completion activities will convert in excess of 20% of our 2011 PUD reserves in this play.

The remaining 26.1% of our PUD reserve inventory at year-end 2011 is located primarily in our Woodford and Haynesville shale assets.  As part of our annual reserve process at the end

(1)  We operated 82% and 77% of our 2011 PUD reserves in the Eagle Ford shale and Bakken/Three Forks, respectively.

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of 2011, we evaluated these PUD reserves (and all of our other PUD reserves) against our internal investment hurdle.  We maintained the PUD reserves that passed this test, and removed those that did not.  We intend to develop these PUD reserves within five years of their initial booking date.

It is also important to note that we book PUD reserves based in part upon a drilling and completion schedule that takes into account our allocation of capital to projects and rig schedule assumptions for key plays based upon historical operated and non-operated drilling and completion activities, long-term lease obligations, rig availability, marketing agreements, and transportation and infrastructure constraints, none of which we reasonably expect to limit our PUD reserve development within five years.  In addition, we reasonably expect to have sufficient capital available to implement our plans to develop our PUD reserves within five years. In fact, the Company’s projected capital expenditures for drilling and completing PUD reserve locations in each of the next five years is expected be significantly less than our total 2012 drilling and completion capital expenditure budget of $1.55 billion, as shown in the table below:

Year

Capital required to develop
   2011 year-end PUD reserves
   ($MM)

PUD reserve development
   capital as a percentage of
   budgeted 2012 drilling and
   completion capital

2012

$

285

18.4

%

2013

$

289

18.6

%

2014

$

266

17.2

%

2015

$

74

4.8

%

2016

$

14

0.9

%

Total

$

928

2.                                      We note your statement that “As of December 31, 2011, we had no material proved undeveloped reserves that have been on our books in excess of five years.”  Please note that Rule 4-10(a)(31)(ii) of Regulation S-X specifies a five year limit after booking for the development of PUD reserves.  Please be more specific in your disclosure and affirm to us, if true, that none of your PUD reserves are scheduled to be developed beyond five years after first booking, or otherwise advise.

RESPONSE:  At year-end 2011, we had an immaterial amount of PUD reserves booked that will not be converted within five years of their initial booking date.  In that year, 0.9% of the Company’s total PUD reserves (3.9 bcfe) were associated with the addition of pay related to seven additional injection wells in our Parkway Delaware Waterflood Unit, which had been booked in 2002; however, this project was included in our 2012 capital budget and as of November 15, 2012, we have completed the work on four of the seven injection wells and have plans to initiate the remainder of the work prior to the end of 2012.  Additionally, the Company had 5.9 bcfe (1.4% of the total PUD reserves) booked to the PUD category for behind pipe

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reserves that have been on the Company’s books for more than five years.  Based on our correspondence and discussions with the Staff in June and July 2006, starting with our 2006 year-end reserve process, we began classifying behind pipe reserves as PUD reserves if the costs to complete such reserves are in excess of 15% of the costs to drill and complete a new well.  Accordingly, due to their behind pipe status, we maintained these reserves as PUD reserves.

Notes to Consolidated Financial Statements

Note 12 — Acquisition and Development Agreement and Carry and Earning Agreement, page 126

3.                                      We note you entered into an Acquisition and Development Agreement with Mitsui E&P Texas LP wherein you agreed to transfer a 12.5% working interest in certain non-operated oil and gas assets for Mitsui’s agreement to carry 90% of certain drilling and completion costs attributable to your remaining interest in these assets, until Mitsui has paid a total of $680 million on your behalf.  The agreement also included the conveyance of 50% of your ownership in gathering assets in exchange for reimbursement by Mitsui of 50% of the costs you have incurred.  Please clarify for us how you accounted for this transaction on day one.  Additionally, please clarify the nature of the terms once payout has been reached.

RESPONSE:  Carried interest transactions of this nature are common in our industry, and our accounting and treatment for the Mitsui transaction is consistent with authoritative guidance.  We evaluated this transaction in two parts: (i) the conveyance of 50% of our interest in the related gathering assets, and (ii) the $680 million carry of certain drilling and completion costs attributable to our approximate 14.5% retained interest in exchange for the conveyance of a 12.5% working interest in certain non-operated properties owned by us.

Our accounting treatment of the sale of the gathering assets relied on ASC 360-20-40-46. The transaction satisfied the definition of a partial sale, and therefore, we accounted for it as a recovery of cost.  Mitsui purchased 50% of our interest in the gathering assets for consideration equal to 50% of our proportionate investment in the gathering assets.  Therefore, we recognized no gain or loss on this portion of the transaction.

We evaluated the $680 million carry of certain drilling and completion costs attributable to our approximate 14.5% retained interest in exchange for the conveyance of a 12.5% working interest in certain non-operated properties separately for unproved and proved properties. With respect to unproved properties, we followed the guidance in ASC 932-360-40-7, noting that the conveyance to Mitsui of unproved properties represented a pooling of assets.  Consequently, we recognized no gain or loss at the time we conveyed the 12.5% (of 8/8ths) working interest to

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Mitsui. With respect to proved properties, we followed the guidance in ASC 932-360-55-5 and ASC 932-360-55-6 and concluded that the terms of the Acquisition and Development Agreement (“ADA”) constitute a carried interest.  Consequently, the transaction contemplated by the ADA is not a sale, and we recognized no gain or loss. After Mitsui has reimbursed us for $680 million of drilling and completion costs from the escrow account (as discussed below in our response to comment 5), as billed by the operator, we will be responsible for paying our proportionate share of future drilling and completion costs.

Supplemental Oil and Gas Information (unaudited), page 128

Costs Incurred in Oil and Gas Producing Activities, page 128

4.                                      We note your disclosure under this heading includes separate line items for “Facility costs” and “Leasing activity.”  Please revise your presentation to reflect the disclosure specifically required by FASB ASC 932-235-50-18 and reflected in Example 3 in ASC 932-235-55-4.

RESPONSE:  The “Leasing activity” line item under the heading “Acquisitions” consists entirely of costs related to the leasing of undeveloped acreage.  We have historically distinguished between the “Leasing activity” and “Unproved properties” line items to differentiate between lease acquisition costs for properties acquired through leasing efforts (“Leasing activity”) and those that are part of an acquisition transaction that includes proved and/or unproved reserves (allocated between “Proved properties” and “Unproved properties”).  Please note that the Form 10-K did not include the “Unproved properties” line item because the dollar amount for such line item for the years ended December 31, 2011, 2010, and 2009 was $0.  We believe this disclosure provides financial statement users with greater transparency regarding how we acquire assets and how much we invest to acquire them.

The “Facility costs” line item consists of costs that are associated with facilities related to development activities.  These types of costs are disproportionately weighted to the beginning of large scale, long lead time development projects. We distinguish between “Development costs” and “Facility costs” because we believe it provides financial statement users with more detail regarding the costs we incur to find and develop oil, natural gas and natural gas liquids.

We have reviewed Example 3 in ASC 932-235-55-4 and note that our tabular disclosure does not strictly follow that example.  We propose that in future filings, beginning with our Annual Report on Form 10-K for the year ending December 31, 2012 (“2012 Form 10-K”), we modify our disclosure to the following:

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Supplemental Oil and Gas Information (unaudited)

Costs Incurred in Oil and Gas Producing Activities

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows:

For the Period Ended XXX,

20XX

20XX

20XX

(in thousands)

Development costs (1)

$

XXX

$

XXX

$

XXX

Exploration costs

XXX

XXX

XXX

Acquisitions

Proved properties

XXX

XXX

XXX

Unproved properties (2)

XXX

XXX

XXX

Total, including asset   retirement obligation

$

XXX

$

XXX

$

XXX

(1)         Includes facility costs of $XXX, $XXX, and $XXX for the periods ended XXX, 20XX, 20XX, and 20XX, respectively.

(2)         Includes $XXX related to the XXX acquisition.  The balance relates to leasing activity.

Form 10-Q for Fiscal Quarter Ended September 30, 2012

Notes to Condensed Consolidated Financial Statements

Note 12 — Acquisition and Development Agreement, page 21

5.                                      We note you hold $93.8 million in cash payments from Mitsui and that $201.3 million of the $680.0 million carry amount has been spent as of September 30, 2012.  Please expand your disclosure here to address the factors that impact the amount and timing of receipt of these carry amounts, such as whether the drilling carry amounts are to be funded on a predetermined schedule or will be reimbursed to you as they are billed by the operator.  In addition, please expand your disclosure to discuss how these drilling carries impact your results of operations, if applicable.

RESPONSE:  Under the ADA, we pay drilling and completion costs as they are billed by the operator, and Mitsui reimburses us for those costs.  The reimbursement funds are drawn from a Company maintained escrow account, which Mitsui funds on a monthly basis.  Pursuant to the ADA, Mitsui committed to maintain the balance of the escrow account in an amount equal to an estimate of 90% of our share of two month’s drilling and completion costs.  We prepare the estimate of each month’s drilling and completion costs using an average of the costs billed by the operator during the prior six months.  Additionally, as discussed in our Note 12 — Acquisition and Development Agreement, the ADA required