Exhibit 99.1                  
                      For Information
                      Brent A. Collins
                      303-861-8140

FOR IMMEDIATE RELEASE


SM ENERGY REPORTS RESULTS FOR FOURTH QUARTER OF 2010
AND 2010 PROVED RESERVES AND COSTS INCURRED;
PROVIDES OPERATIONAL UPDATE


·  
Quarterly record average daily production of 344.4 MMCFE/d; exceeds guidance of 305 – 330 MMCFE/d

·  
Reported GAAP net income of $37.1 million, or $0.57 per diluted share; adjusted net income of $29.7 million, or $0.46 per diluted share

·  
Proved reserves at year-end 2010 up 27% from 2009 to 984.5 BCFE

·  
Eagle Ford shale and Bakken / Three Forks programs remain focus of capital program


DENVER, CO February 24, 2011 – SM Energy Company (NYSE: SM) today reports financial results for the fourth quarter of 2010 and provides an update on the Company’s operating and financial activities.  In addition, a new presentation for the fourth quarter earnings and operational update has been posted on the Company’s website at sm-energy.com.  This presentation will be referenced in the conference call scheduled for 8:00 a.m. Mountain time (10:00 a.m. Eastern time) on February 25, 2011.  Information for the earnings call can be found below.


MANAGEMENT COMMENTARY

Tony Best, CEO and President, remarked, “Last year was a transformational year for SM Energy.  We entered 2010 with a plan to advance our resource plays in inventory and get them ready for full-scale development.  Our focus became centered on oil and liquids rich plays such as the Eagle Ford shale and Bakken/Three Forks and we saw continued success in these programs.   For the year, SM Energy replaced nearly 350% of its production organically, while keeping a strong balance sheet.  We are well positioned as we enter 2011 and we remain focused on building shareholder value with the continued growth in our key resource plays.”



FOURTH QUARTER 2010 RESULTS

SM Energy posted net income for the fourth quarter of 2010 of $37.1 million, or $0.57 per diluted share.  This compares to $990 thousand, or $0.02 per diluted share, for the same period in 2009.  Adjusted net income for the fourth quarter was $29.7 million, or $0.46 per diluted share, versus $20.1 million, or $0.31 per diluted share, for the fourth quarter of 2009.  Adjusted net income excludes certain items that the Company believes affect the comparability of operating results.  Items excluded are generally one-time items or are items whose timing and/or amount cannot be reasonably estimated.  A summary of the adjustments made to arrive at adjusted net income is presented in the table below.


   
For the Three Months Ended December 31,
  
   
2010
    
2009
  
Weighted-average diluted share count (in millions)
           64.9             64.1  
   
$ in millions
    
Per Diluted Share
    
$ in millions
    
Per Diluted Share
  
Reported net income
   $ 37.1     $ 0.57     $ 1.0     $ 0.02  
Adjustments net of tax:
                                
Change in Net Profits Plan liability
   $ (3.0 )   $ (0.05 )   $ 4.3     $ 0.07  
Unrealized derivative loss
   $ 8.2     $ 0.13     $ 2.0     $ 0.03  
Gain on property sales
   $ (14.7 )   $ (0.23 )   $ (13.8 )   $ (0.21 )
Bad debt recovery associated with SemGroup, L.P.
     -       -     $ (3.1 )   $ (0.05 )
                                 
Adjusted net income (loss), before impairments
   $ 27.8     $ 0.43     $ (9.5 )   $ (0.15 )
                                 
Non-cash impairments net of tax:
                                
Impairment of proved properties
   $ 3.9     $ 0.06     $ 13.5     $ 0.21  
Abandonment and impairment of unproved properties
   $ (1.9 )   $ (0.03 )   $ 15.7     $ 0.24  
Impairment of materials inventory
     -       -     $ 0.5     $ 0.01  
                                 
Adjusted net income
   $ 29.7     $ 0.46     $ 20.1     $ 0.31  
                                 
NOTE:  Totals may not sum due to rounding
                                


Operating cash flow was $176.4 million for the fourth quarter of 2010 compared to $144.2 million for the same period in 2009.  Net cash provided by operating activities was $78.7 million for the fourth quarter of 2010 compared with $83.1 million for the same period in 2009.

Adjusted net income and operating cash flow are non-GAAP financial measures – please refer to the respective reconciliation in the accompanying Financial Highlights section at the end of this release.
 
SM Energy reported average daily production of 344.4 MMCFE/d for the fourth quarter, which was above the guidance range of 305 to 330 MMCFE/d.  Production growth was driven by strong results in the Company’s Eagle Ford shale and Haynesville shale programs.  Sequentially, reported production grew 15% in the fourth quarter of 2010 over the preceding quarter.

Total operating revenues and other income for the fourth quarter of 2010 was $294.1 million compared to $242.0 million for the same period in 2009.  In the fourth quarter, the Company’s average equivalent price, net of hedging, was $7.98 per MCFE, which is an increase of 4% from the $7.69 per MCFE realized in the comparable period in 2009.  Average realized prices, inclusive of hedging activities, for the fourth quarter were $6.00 per Mcf, which was essentially flat from the same quarter in 2009, and $70.30 per barrel, which was an increase of 9% from 2009.  SM Energy reports its gas volumes on a “wet gas” basis, meaning that revenue dollars associated with natural gas liquids (“NGLs”) are reported within the Company’s natural gas revenues.

Lease operating expense (“LOE”) in the fourth quarter was $1.06 per MCFE, which is below the Company’s guidance of $1.15 to $1.20 per MCFE.  This represents a 19% decrease from the $1.31 per MCFE in the comparable period last year.  Sequentially, lease operating expense remained flat in the fourth quarter of 2010 from the third quarter.

Transportation expense in the fourth quarter was $0.22 per MCFE, which is within the guidance range of $0.20 to $0.22 per MCFE.  The reported per unit expense increased 10% from the comparable period in 2009.  Transportation expense also increased 22% from $0.18 per MCFE in the third quarter of 2010.  The increase in transportation reflects the growth in production in areas where higher transportation costs exist.

Production taxes for the fourth quarter of 2010 were $0.52 per MCFE, which was essentially flat from the same period a year ago.  Sequentially, production taxes increased 33% from the third quarter of 2010.  This increase was the result of production tax credits realized in the third quarter of 2010 related to severance tax holidays.  The Company’s realized production tax rate for the fourth quarter was 6.5%, which was essentially within the provided guidance of 7% of pre-hedge oil and natural gas revenue.

Total general and administrative (“G&A”) expense for the fourth quarter of 2010 was $1.00 per MCFE, which is above the guidance range of $0.88 to $0.96 per MCFE.  Cash G&A expense was $0.73 per MCFE for the quarter, compared to a guidance range of $0.54 to $0.58 per MCFE.  Non-cash G&A for the quarter was $0.16 per MCFE versus a guidance range of $0.18 to $0.20 per MCFE.  G&A related to cash payments from the Company’s legacy Net Profits Plan (“NPP”) program was $0.11 per MCFE in the quarter compared to a guidance range of $0.16 to $0.18 per MCFE.  The total G&A expense variance from guidance is largely the result of higher compensation costs related to annual performance-based bonus accruals for 2010.  On a sequential basis, G&A expense increased 4% from the third quarter of 2010.

Depletion, depreciation and amortization expense (“DD&A”) was $2.99 per MCFE in the fourth quarter of 2010, which was within the Company’s guidance range of $2.90 to $3.20 per MCFE.  DD&A increased 4%, or $0.11 per MCFE, between the fourth quarters of 2010 and 2009.  Sequentially, DD&A in the fourth quarter of 2010 decreased 2% from $3.05 per MCFE in the third quarter.  The Company’s DD&A rate is impacted by a number of factors, including year-end proved reserves and divestitures.
 
 

PROVED RESERVES AND COSTS INCURRED

Below is a roll-forward of the Company’s proved reserves from year-end 2009 to year-end 2010.

 
   
(BCFE)
  
Beginning of year
     772.2  
         
Revisions of previous estimate (engineering, price, and aged PUD locations)
     24.7  
Discoveries and extensions
     270.2  
Infill reserves in an existing proved field
     114.0  
Purchases of minerals in place
     0.2  
Sales of reserves
     (86.8 )
Production
     (110.0 )
         
End of year
     984.5  


SM Energy’s estimate of proved reserves as of December 31, 2010, was 984.5 BCFE, which is an increase of 27% from 772.2 BCFE at the end of 2009.  These reserves are comprised of 57.4 MMBbl of oil and 640.0 Bcf of natural gas, and are 70% proved developed, compared to 82% proved developed at the end of 2009.  The before income tax PV-10 value of the Company’s estimated proved reserves at December 31, 2010 was $2.3 billion, which was roughly $1.0 billion higher than the prior year. Over 80% of SM Energy’s estimated proved reserves by value were audited by an independent reserve engineering firm.

Prices used at year-end to calculate the Company’s estimate of proved reserves were $4.38 per MMBTU of natural gas and $79.43 per barrel of oil, using the trailing 12-month arithmetic average of the first of month price.  These prices are 13% and 30% higher than the prices used at the end of 2009 for natural gas and oil, respectively.

In 2010, SM Energy realized $2.14 per MCFE in drilling finding costs, excluding revisions, which is an improvement of 38% from $3.44 per MCFE realized in 2009.  Drilling reserve replacement, excluding revisions, increased to 349% in 2010 from 100% in 2009.

Finding costs and reserve replacement ratios are non-GAAP financial measures – please refer to the respective definitions in the accompanying Financial Highlights section at the end of this release.

Below is a table detailing the Company’s costs incurred in oil and gas producing activities for the year ended December 31, 2010.


Costs incurred in oil and gas producing activities:
  
    For the Year Ended
    December 31,
    2010
    (in thousands)
Development costs
   $ 299,308  
Facility costs
     80,328  
Exploration costs
     443,888  
Acquisitions:
        
  Proved properties
     664  
  Unproved properties – other
     53,192  
Total, including asset retirement obligation
   $ 877,380  


FINANCIAL POSITION AND LIQUIDITY

As of December 31, 2010, SM Energy had total long-term debt of $323.7 million.  This was comprised of $275.7 million, net of debt discount, related to the Company’s 3.50% Senior Convertible Notes and $48.0 million drawn on the long-term credit facility.  The Company’s debt-to-book capitalization ratio was 21% as of the end of the quarter.

On February 7, 2011, the Company closed the private offering of $350 million of 6.625% Senior Notes due 2019, which are unsecured and were issued at par value.  The net proceeds will be used to repay outstanding balances under the credit facility, fund a portion of the Company’s 2011 capital program and for general corporate purposes.  As a result of the offering, the borrowing base for the long-term credit facility was automatically reduced from $1.1 billion to $1.0 billion; however, the Company’s commitment amount under the credit facility of $678 million was not changed.  SM Energy’s debt-to-book capitalization ratio, pro forma for this offering, would be 34%.


OPERATIONAL UPDATE

Eagle Ford Shale
SM Energy is currently operating two (2) drilling rigs on its operated acreage in South Texas.  The Company plans to increase its operated rig count to six (6) drilling rigs by the end of 2011.  A third drilling rig is expected to arrive at the beginning of March 2011.

The Company continues to make improvements in its drilling times in the play.  During 2010, drilling time per 1,000 ft. of penetration was reduced to 24 hours from 32 hours, a 25% improvement.  A number of pilots to test downspacing potential and retained energy fracture stimulations are planned this year, both of which will provide important data regarding the ultimate spacing for the Company’s development plans.

SM Energy has previously announced its intention to sell down a portion of its total 250,000 net acre Eagle Ford shale position.  The data room for this planned transaction opened earlier this week and the Company expects to have an agreement completed in the second quarter of 2011.

Bakken / Three Forks
Two (2) drilling rigs are currently operating for SM Energy in the Williston Basin with a focus on horizontal development of the Bakken and Three Forks formations.  A third operated rig is expected to arrive in April of 2011.  The Company has increased its acreage position in the prospective portion of North Dakota to approximately 85,000 net acres, up from the previously reported 81,000 net acres.

Marcellus Shale Divestiture Update
To date, the Company has not received acceptable cash offers for its Marcellus shale position in north central Pennsylvania where it holds the rights to approximately 43,000 net acres.  SM Energy continues to negotiate with interested parties.

 
 
 
 
Performance Guidance

The Company’s guidance for the first quarter and the full year of 2011 is as follows:

      1Q11    
FY 2011
  
Production (BCFE)
     30 – 33       128 – 132  
LOE ($/MCFE)
   $ 1.10 – $1.15     $ 1.07 – $1.12  
Transportation ($/MCFE)
   $ 0.30 – $0.35     $ 0.40 – $0.45  
Production Taxes (% of pre-hedge O&G revenue)
     7 %     7 %
                 
G&A - cash NPP ($/MCFE)
   $ 0.16 – $0.18     $ 0.16 – $0.18  
G&A - other cash ($/MCFE)
   $ 0.54 – $0.57     $ 0.55 – $0.58  
G&A - non-cash ($/MCFE)
   $ 0.12 – $0.14     $ 0.13 – $0.15  
G&A TOTAL ($/MCFE)
   $ 0.82 – $0.89     $ 0.84 – $0.91  
                 
DD&A ($/MCFE)
   $ 2.95 – $3.15     $ 2.95 – $3.15  
Non-cash interest expense ($MM)
   $ 3.6     $ 15.0  
Effective income tax rate range
             37.4% - 37.9 %
% of income tax that is current
          
<10%
  



EARNINGS CALL INFORMATION

The Company has scheduled a teleconference to discuss the fourth quarter results on February 25, 2011 at 8:00 a.m. Mountain time (10:00 a.m. Eastern time).  The call participation number is 800-260-8140 and the participant passcode is 21918282.  An audio replay of the conference call will be available approximately two hours after the call at 888-286-8010, with the passcode 43039171.  International participants can dial 617-614-3672 to take part in the call, using passcode 21918282 and can access a replay of the call at 617-801-6888, using passcode 43039171.  Replays can be accessed through March 11, 2011.

The call will be webcast live and can be accessed at SM Energy Company’s website at sm-energy.com.  An audio recording of the call will be available at that site through March 11, 2011.


INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This release contains forward looking statements within the meaning of the securities laws, including forecasts and projections.  The words “will,” “believe,” “budget,” “anticipate,” “plan,” “intend,” “estimate,” “forecast,” “look,” and “expect” and similar expressions are intended to identify forward looking statements.  These statements involve known and unknown risks, which may cause SM Energy’s actual results to differ materially from results expressed or implied by the forward looking statements.  These risks include such factors as the volatility and level of oil and natural gas prices, uncertainties inherent in projecting future rates of production from drilling activities and acquisitions, the ability of midstream service providers to purchase or market the Company’s production, the availability of debt and equity financing for purchasers of oil and gas properties, the ability of the banks in the Company’s credit facility to fund requested borrowings, the ability of hedge counterparties to settle hedges in favor of the Company, the risks associated with the Company’s hedging strategy, the uncertain nature of the expected benefits from divestitures or joint ventures of oil and gas properties, the ability to close announced divestitures or joint ventures of oil and gas properties, and other such matters discussed in the “Risk Factors” section of SM Energy’s 2010 Annual Report on Form 10-K, which is expected to be filed on or around February 25, 2011.  Although SM Energy may from time to time voluntarily update its prior forward looking statements, it disclaims any commitment to do so except as required by the securities laws.


INFORMATION ABOUT PROVED RESERVES

This press release contains references to certain items pertaining to the process used to estimate the Company’s proved reserves and their PV-10 value, which is equal to the standardized measure of discounted future net cash flows from proved reserves on the applicable date, before deducting future income taxes, discounted at 10 percent.  SM Energy believes that the presentation of pre-tax PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company’s proved reserves prior to taking into account future corporate income taxes and the Company’s current tax structure.  The Company further believes investors and creditors use pre-tax PV-10 value as a basis for comparison of the relative size and value of the Company’s proved reserves to other peer companies.  SM Energy’s pre-tax PV-10 value for estimated proved reserves as of December 31, 2010 may be reconciled to its standardized measure of discounted future net cash flows as of December 31, 2010 by reducing the Company’s pre-tax PV-10 value by the discounted future income taxes associated with such reserves, and a reconciliation is provided below.


Reconciliation of standardized measure (GAAP) to PV-10 value (Non-GAAP):

 
Additionally, the Company believes its use of an independent reserve auditor is a fact of interest to investors and analysts who follow the Company.  More information on these items will be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 to be filed with the Securities and Exchange Commission on February 25, 2011.


   
As of December 31,
  
   
2010
  
    (in thousands)
Standardized measure of discounted future net cash flows (GAAP)
   $ 1,666,367  
Add: 10 percent annual discount, net of income taxes
     1,294,632  
Add: future income taxes
     1,335,576  
         
Undiscounted future net cash flows
   $ 4,296,575  
Less: 10 percent annual discount without tax effect
     (1,952,244 )
         
PV-10 value (Non-GAAP)
   $ 2,344,331  

 
ABOUT THE COMPANY

SM Energy Company, formerly named St. Mary Land & Exploration Company, is an independent energy company engaged in the exploration, exploitation, development, acquisition, and production of natural gas, natural gas liquids and crude oil. SM Energy routinely posts important information about the Company on its website. For more information about SM Energy, please visit its website at sm-energy.com.


 
 
 
 


SM ENERGY COMPANY
FINANCIAL HIGHLIGHTS
December 31, 2010
                                     
                                     
Guidance Comparison
  
For the Three Months
                          
   
Ended December 31, 2010
                        
   
Actual
    
Guidance Range
                          
                                     
Oil and gas production (MMCFE per day)
     344.4       305 - 330                          
                                         
Lease operating expense (per MCFE)
   $ 1.06     $ 1.15 - $1.20                          
Transportation expense (per MCFE)
   $ 0.22     $ 0.20 - $0.22                          
Production taxes, as a percentage of pre-hedge revenue
     7 %     7 %                        
                                         
General and administrative - cash (per MCFE)
   $ 0.73     $ 0.54 - $0.58                          
General and administrative - cash related to Net Profits Plan (per MCFE)
   $ 0.11     $ 0.16 - $0.18                          
General and administrative - non-cash (per MCFE)
   $ 0.16     $ 0.18 - $0.20                          
General and administrative - TOTAL (per MCFE)
   $ 1.00     $ 0.88 - $0.96                          
                                         
Depreciation, depletion, and amortization (per MCFE)
   $ 2.99     $ 2.90 - $3.20                          
                                         
                                         
                                         
Production Data
  
For the Three Months
          
For the Years
        
   
Ended December 31,
          
Ended December 31,
        
      2010       2009    
Percent Change
       2010       2009    
Percent Change
  
                                             
Average realized sales price, before hedging:
                                            
Oil (per Bbl)
   $ 77.46     $ 68.98       12 %   $ 72.65     $ 54.40       34 %
Gas (per Mcf)
     5.23       4.88       7 %     5.21       3.82       36 %
                                                 
Average realized sales price, net of hedging:
                                                
Oil (per Bbl)
   $ 70.30     $ 64.43       9 %   $ 66.85     $ 56.74       18 %
Gas (per Mcf)
     6.00       6.07       -1 %     6.05       5.59       8 %
                                                 
Production:
                                                
Oil (MMBbls)
     1.8       1.5       21 %     6.4       6.3       0 %
Gas (Bcf)
     20.7       17.1       21 %     71.9       71.1       1 %
BCFE (6:1)
     31.7       26.1       21 %     110.0       109.1       1 %
                                                 
Daily production:
                                                
Oil (MBbls per day)
     19.9       16.4       21 %     17.4       17.3       0 %
Gas (MMcf per day)
     224.9       185.3       21 %     196.9       194.8       1 %
MMCFE per day (6:1)
     344.4       284.0       21 %     301.4       298.8       1 %
                                                 
Margin analysis per MCFE:
                                                
Average realized sales price, before hedging
   $ 7.90     $ 7.18       10 %   $ 7.60     $ 5.65       35 %
                                                 
Average realized sales price, net of hedging
     7.98       7.69       4 %     7.82       6.94       13 %
Lease operating expense
     1.06       1.31       -19 %     1.10       1.33       -17 %
Transportation
     0.22       0.20       10 %     0.19       0.19       0 %
Production taxes
     0.52       0.51       2 %     0.48       0.37       30 %
General and administrative
     1.00       0.80       25 %     0.97       0.70       39 %
Operating margin
   $ 5.18     $ 4.87       6 %   $ 5.08     $ 4.35       17 %
Depletion, depreciation, amortization, and
                                                
asset retirement obligation liability accretion
   $ 2.99     $ 2.88       4 %   $ 3.06     $ 2.79       10 %

 
 
 
 
 

Consolidated Statements of Operations
                        
(In thousands, except per share amounts)
  
For the Three Months
    
For the Years
  
 
  
Ended December 31,
    
Ended December 31,
  
   
2010
    
2009
    
2010
    
2009
  
                         
Operating revenues and other income:
                        
Oil and gas production revenue
   $ 250,160     $ 187,606     $ 836,288     $ 615,953  
Realized oil and gas hedge gain
     2,694       13,418       23,465       140,648  
Gain on divestiture activity
     23,094       22,076       155,277       11,444  
Marketed gas system revenue
     16,083       16,977       70,110       58,459  
Other revenue
     2,087       1,919       7,694       5,697  
Total operating revenues and other income
     294,118       241,996       1,092,834       832,201  
                                 
Operating expenses:
                                
Oil and gas production expense
     56,961       52,872       195,075       206,800  
Depletion, depreciation, amortization,
                                
and asset retirement obligation liability accretion
     94,806       75,140       336,141       304,201  
Exploration
     21,027       13,414       63,860       62,235  
Impairment of proved properties
     6,127       21,630       6,127       174,813  
Abandonment and impairment of unproved properties
     (3,012 )     25,153       1,986       45,447  
Impairment of materials inventory
     -       774       -       14,223  
General and administrative
     31,560       20,687       106,663       76,036  
Recovery of bad debt expense
     -       (5,189 )     -       (5,189 )
Change in Net Profits Plan liability
     (4,656 )     6,963       (34,441 )     (7,075 )
Marketed gas system expense
     14,176       16,235       66,726       57,587  
Unrealized derivative loss
     12,994       3,218       8,899       20,469  
Other expense
     956       1,065       3,027       13,489  
Total operating expenses
     230,939       231,962       754,063       963,036  
                                 
Income (loss) from operations
     63,179       10,034       338,771       (130,835 )
 
                                
Nonoperating income (expense):
                                
Interest income
     53       10       321       227  
Interest expense
     (4,727 )     (7,532 )     (24,196 )     (28,856 )
                                 
Income (loss) before income taxes
     58,505       2,512       314,896       (159,464 )
Income tax benefit (expense)
     (21,366 )     (1,522 )     (118,059 )     60,094  
                                 
Net income (loss)
   $ 37,139     $ 990     $ 196,837     $ (99,370 )
                                 
Basic weighted-average common shares outstanding
     63,131       62,565       62,969       62,457  
                                 
Diluted weighted-average common shares outstanding
     64,919       64,113       64,689       62,457  
                                 
Basic net income (loss) per common share
   $ 0.59     $ 0.02     $ 3.13     $ (1.59 )
                                 
Diluted net income (loss) per common share
   $ 0.57     $ 0.02     $ 3.04     $ (1.59 )

 
 
 
 


Consolidated Balance Sheets
            
(In thousands, except share amounts)
  
December 31,
    
December 31,
  
ASSETS
  
2010
    
2009
  
             
Current assets:
            
Cash and cash equivalents
   $ 5,077     $ 10,649  
Accounts receivable
     163,190       116,136  
Refundable income taxes
     8,482       32,773  
Prepaid expenses and other
     45,522       14,259  
Derivative asset
     43,491       30,295  
Deferred income taxes
     8,883       4,934  
Total current assets
     274,645       209,046  
                 
Property and equipment (successful efforts method), at cost:
                
Land
     1,491       1,371  
Proved oil and gas properties
     3,389,158       2,797,341  
Less - accumulated depletion, depreciation, and amortization
     (1,326,932 )     (1,053,518 )
Unproved oil and gas properties
     94,290       132,370  
Wells in progress
     145,327       65,771  
Materials inventory, at lower of cost or market
     22,542       24,467  
Oil and gas properties held for sale
     86,811       145,392  
Other property and equipment, net of accumulated depreciation
                
of $15,480 in 2010 and $14,550 in 2009
     21,365       14,404  
      2,434,052       2,127,598  
                 
Other noncurrent assets:
                
Derivative asset
     18,841       8,251  
Other noncurrent assets
     16,783       16,041  
Total other noncurrent assets
     35,624       24,292  
                 
Total Assets
   $ 2,744,321     $ 2,360,936  
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
          
                 
Current liabilities:
                
Accounts payable and accrued expenses
   $ 417,654     $ 236,242  
Derivative liability
     82,044       53,929  
Deposit associated with oil and gas properties held for sale
     2,355       6,500  
Total current liabilities
     502,053       296,671  
                 
Noncurrent liabilities:
                
Long-term credit facility
     48,000       188,000  
Senior convertible notes, net of unamortized
                
discount of $11,827 in 2010, and $20,598 in 2009
     275,673       266,902  
Asset retirement obligation
     69,052       60,289  
Asset retirement obligation associated with oil and gas properties held for sale
     2,119       18,126  
Net Profits Plan liability
     135,850       170,291  
Deferred income taxes
     443,135       308,189  
Derivative liability
     32,557       65,499  
Other noncurrent liabilities
     17,356       13,399  
Total noncurrent liabilities
     1,023,742       1,090,695  
                 
Commitments and contingencies
                
                 
Stockholders' equity:
                
Common stock, $0.01 par value: authorized  - 200,000,000 shares;
                
issued:  63,412,800 shares in 2010 and 62,899,122 shares in 2009;
                
outstanding, net of treasury shares: 63,310,165 shares in 2010
                
and 62,772,229 shares in 2009
     634       629  
Additional paid-in capital
     191,674       160,516  
Treasury stock, at cost:  102,635 shares in 2010 and 126,893 shares in 2009
     (423 )     (1,204 )
Retained earnings
     1,042,123       851,583  
Accumulated other comprehensive loss
     (15,482 )     (37,954 )
Total stockholders' equity
     1,218,526       973,570  
Total Liabilities and Stockholders' Equity
   $ 2,744,321     $ 2,360,936  


 
 
 
 

Consolidated Statements of Cash Flows
                        
(In thousands)
  
For the Three Months
    
For the Years
  
   
Ended December 31,
    
Ended December 31,
  
   
2010
    
2009
    
2010
    
2009
  
Cash flows from operating activities:
                        
                         
Net income (loss)
   $ 37,139     $ 990     $ 196,837     $ (99,370 )
Adjustments to reconcile net income (loss) to net cash
                                
provided by operating activities:
                                
Gain on divestiture activity
     (23,094 )     (22,076 )     (155,277 )     (11,444 )
Depletion, depreciation, amortization,
                                
and asset retirement obligation liability accretion
     94,806       75,140       336,141       304,201  
Exploratory dry hole expense
     -       2,961       289       7,810  
Impairment of proved properties
     6,127       21,630       6,127       174,813  
Abandonment and impairment of unproved properties
     (3,012 )     25,153       1,986       45,447  
Impairment of materials inventory
     -       774       -       14,223  
Stock-based compensation expense*
     6,890       5,787       26,743       18,765  
Recovery of bad debt expense
     -       (5,189 )     -       (5,189 )
Change in Net Profits Plan liability
     (4,656 )     6,963       (34,441 )     (7,075 )
Unrealized derivative loss
     12,994       3,218       8,899       20,469  
Loss related to hurricanes
     -       28       -       8,301  
Amortization of debt discount and deferred financing costs
     3,442       3,291       13,464       12,213  
Deferred income taxes
     28,822       29,347       114,517       (39,735 )
Plugging and abandonment
     (1,208 )     (14,286 )     (8,314 )     (26,396 )
Other
     (908 )     1,950       (3,993 )     3,382  
Changes in current assets and liabilities:
                                
Accounts receivable
     (42,216 )     (12,101 )     (47,153 )     46,743  
Refundable income taxes
     (7,111 )     (29,952 )     24,291       (19,612 )
Prepaid expenses and other
     (35,875 )     2,034       (35,363 )     (6,626 )
Accounts payable and accrued expenses
     6,075       (12,608 )     53,198       (4,814 )
Excess income tax benefit (expense) from the exercise of stock awards
     522       -       (854 )     -  
Net cash provided by operating activities
     78,737       83,054       497,097       436,106  
                                 
Cash flows from investing activities:
                                
Net proceeds from sale of oil and gas properties
     52,003       38,761       311,504       39,898  
Proceeds from insurance settlement
     -       1,453       -       16,789  
Capital expenditures
     (179,604 )     (86,787 )     (668,288 )     (379,253 )
Acquisition of oil and gas properties
     21       (18 )     (664 )     (76 )
Receipts from restricted cash
     -       -       -       14,398  
Other
     2,367       3,150       (4,125 )     4,152  
Net cash used in investing activities
     (125,213 )     (43,441 )     (361,573 )     (304,092 )
                                 
Cash flows from financing activities:
                                
Proceeds from credit facility
     256,500       174,000       571,559       2,072,500  
Repayment of credit facility
     (210,500 )     (221,000 )     (711,559 )     (2,184,500 )
Debt issuance costs related to credit facility
     -       -       -       (11,074 )
Proceeds from sale of common stock
     3,324       1,931       6,440       3,110  
Dividends paid
     (3,153 )     (3,127 )     (6,297 )     (6,247 )
Excess income tax benefit (expense) from the exercise of stock awards
     (522 )     -       854       -  
Other
     (1,185 )     (1,285 )     (2,093 )     (1,285 )
Net cash provided by (used in) financing activities
     44,464       (49,481 )     (141,096 )     (127,496 )
                                 
Net change in cash and cash equivalents
     (2,012 )     (9,868 )     (5,572 )     4,518  
Cash and cash equivalents at beginning of period
     7,089       20,517       10,649       6,131  
Cash and cash equivalents at end of period
   $ 5,077     $ 10,649     $ 5,077     $ 10,649  
                                 
* Stock-based compensation expense is a component of exploration expense and general and administrative expense on the consolidated statements of
operations. For the three months ended December 31, 2010, and 2009, approximately $2.0 million and $1.9 million, respectively of stock-based compensation
expense was included in exploration expense. For the three months ended December 31, 2010, and 2009, approximately $4.9 million and $3.9 million,
respectively, of stock-based compensation expense was included in general and administrative expense. For the Years ended December 31, 2010, and 2009,
approximately $7.7 million and $6.3 million, respectively of stock-based compensation expense was included in exploration expense. For the Years
ended December 31, 2010 and 2009, approximately $19.0 million and $12.5 million, respectively of stock-based compensation expense was included in
general and administrative expense.


 
 
 
 

Adjusted Net Income
                        
(In thousands, except per share data)
                        
                         
Reconciliation of net income (loss) (GAAP)
  
For the Three Months
    
For the Years
  
to Adjusted net income (Non-GAAP):
  
Ended December 31,
    
Ended December 31,
  
   
2010
    
2009
    
2010
    
2009
  
                         
Reported net income (loss) (GAAP)
   $ 37,139     $ 990     $ 196,837     $ (99,370 )
                                 
Adjustments net of tax: (1)
                                
Change in Net Profits Plan liability
     (2,956 )     4,338       (21,529 )     (4,409 )
Unrealized derivative loss
     8,249       2,005       5,563       12,755  
Gain on divestiture activity
     (14,660 )     (13,753 )     (97,061 )     (7,131 )
Bad debt recovery associated with Sem Group, L.P.
     -       (3,143 )     -       (3,143 )
Loss related to hurricanes (2)
     -       17       -       5,173  
                                 
Adjusted net income (loss), before impairment adjustments
     27,772       (9,546 )     83,810       (96,125 )
                                 
Non-cash impairments net of tax: (1)
                                
Impairment of proved properties
     3,889       13,475       3,830       108,935  
Abandonment and impairment of unproved properties
     (1,912 )     15,670       1,241       28,320  
Impairment of materials inventory
     -       482       -       8,863  
Adjusted net income, non-recurring items
                                
& non-cash impairments (Non-GAAP) (3)
   $ 29,749     $ 20,081     $ 88,881     $ 49,993  
                                 
Adjusted net income per share (Non-GAAP)
                                
Basic
   $ 0.47     $ 0.32     $ 1.41     $ 0.80  
Diluted
   $ 0.46     $ 0.31     $ 1.37     $ 0.80  
                                 
Average number of shares outstanding
                                
Basic
     63,131       62,565       62,969       62,457  
Diluted
     64,919       64,113       64,689       62,457  
                                 
(1) Adjustments are shown net of tax using the effective income tax rate; calculated by dividing the income tax benefit (expense) by income (loss) before income taxes as stated on the consolidated statement of operations.
  
                           
(2) The loss related to hurricanes is included within line item other expense on the consolidated statements of operations.
                          
   
(3) Adjusted net income excludes certain items that the Company believes affect the comparability of operating results. Items excluded generally are one-time items or are items whose timing and/or amount cannot be reasonably estimated. These items include non-cash adjustments and impairments such as the change in the Net Profits Plan liability, unrealized derivative loss, impairment of proved properties, abandonment and impairment of unproved properties, impairment of materials inventory, gain on divestiture activity, bad debt recovery associated with Sem Group, L.P., and loss related to hurricanes. The non-GAAP measure of adjusted net income is presented because management believes it provides useful additional information to investors for analysis of SM Energy's fundamental business on a recurring basis. In addition, management believes that adjusted net income is widely used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions. Adjusted net income should not be considered in isolation or as a substitute for net income, income from operations, cash provided by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since adjusted net income excludes some, but not all, items that affect net income and may vary among companies, the adjusted net income amounts presented may not be comparable to similarly titled measures of other companies.
  

 
 
 
 


Operating Cash Flow
                        
(In thousands)
                        
                         
Reconciliation of net cash provided by operating activities
  
For the Three Months
    
For the Years
  
(GAAP) to Operating cash flow (Non-GAAP):
  
Ended December 31,
    
Ended December 31,
  
   
2010
    
2009
    
2010
    
2009
  
                         
Net cash provided by operating activities (GAAP)
   $ 78,737     $ 83,054     $ 497,097     $ 436,106  
                                 
Changes in current assets and liabilities
   $ 78,605     $ 52,627     $ 5,881     $ (15,691 )
                                 
 
 
   $ 21,027     $ 13,414       63,860       62,235  
      Less:  Exploratory dry hole expense
   $ -     $ (2,961 )     (289 )     (7,810 )
      Less:  Stock-based compensation expense included in exploration
   $ (1,952 )   $ (1,917 )     (7,676 )     (6,314 )
                                 
Operating cash flow (Non-GAAP) (4)
   $ 176,417     $ 144,217     $ 558,873     $ 468,526  
                                 
(4) Beginning in the third quarter of 2009 the Company changed its definition of operating cash flow. Prior periods have been conformed to the current
definition and the change in the definition did not result in a material variance to results under the prior definiton. Operating cash flow is computed as net cash
provided by operating activities adjusted for changes in current assets and liabilities and exploration, less exploratory dry hole expense, and
stock-based compensation expense included in exploration. The non-GAAP measure of operating cash flow is presented because management believes that it
provides useful additional information to investors for analysis of SM Energy's ability to internally generate funds for exploration, development, acquisitions, and to
service debt. In addition, operating cash flow is widely used by professional research analysts and others in the valuation, comparison, and investment
recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts
in making investment decisions. Operating cash flow should not be considered in isolation or as a substitute for net income, income from operations, net cash provided
by operating activities or other income, profitability, cash flow, or liquidity measures prepared under GAAP. Since operating cash flow excludes some, but not all
items that affect net income and net cash provided by operating activities and may vary among companies, the operating cash flow amounts presented may not
be comparable to similarly titled measures of other companies. See the consolidated statements of cash flows herein for more detailed cash flow information.

 


 
 
 
 
 
Information on Proved Reserves and Costs Incurred
                              
                               
Costs incurred in oil and gas producing activities:
                              
   
For the Year Ended
                          
   
December 31,
                          
   
2010
                          
Development costs
   $ 299,308                          
Facility costs (5)
     80,328                          
Exploration costs
     443,888                          
Acquisitions:
                                
Proved properties
     664                          
Unproved properties - other
     53,192                          
Total, including asset retirement obligation (6) (7)
   $ 877,380                          
                                 
(5) Beginning December 31, 2010 facility costs are being disclosed separately, whereas these costs were previously captured in Development costs.
              
(6)    Includes capitalized interest of $4.3 million for the year ended December 31, 2010.
                            
(7) Includes amounts relating to estimated asset retirement obligations of $5.8 million for the year ended December 31, 2010.
                    
                                 
Proved oil and gas reserve quantities:
                                
   
For the Year Ended
  
   
December 31, 2010
  
   
Oil or Condensate
    
Gas
    
Equivalents
    
Proved Developed
    
Proved Undeveloped
  
   
(MMBbl)
    
(Bcf)
    
(BCFE)
    
(BCFE)
    
(BCFE)
  
Total proved reserves
                                
Beginning of year
     53.8       449.5       772.2       630.3       141.9  
Revisions of previous estimate
     3.1       6.1       24.7       45.9       (21.2 )
Discoveries and extensions
     16.2       172.9       270.2       140.0       130.2  
Infill reserves in an existing proved field
     2.8       97.2       114.0       41.1       72.9  
Purchases of minerals in place
     -       0.2       0.2       0.2       -  
Sales of reserves
     (12.1 )     (14.0 )     (86.8 )     (76.9 )     (9.9 )
Production
     (6.4 )     (71.9 )     (110.0 )     (110.0 )     -  
Conversions
                             16.7       (16.7 )
End of year
     57.4       640.0       984.5       687.3       297.2  
                                         
PV-10 value (in millions)
                   $ 2,344.3     $ 2,053.6     $ 290.8  
                                         
Proved developed reserves
                                        
Beginning of year
     48.1       342.0       630.3                  
End of year
     46.0       411.0       687.3                  
                                         
                                         
                                         
Finding Cost and Reserve Replacement Ratios: (8)
                                        
                                         
Finding Costs in $ per MCFE
                                        
Drilling, excluding revisions
   $ 2.14                                  
Drilling, including revisions
   $ 2.01                                  
All-in
   $ 2.14                                  
                                         
Reserve Replacement Ratios
                                        
Drilling, excluding revisions
     349 %                                
Drilling, including  revisions
     372 %                                
All-in
     372 %                                
                                         
(8) Finding costs and reserve replacement ratios are common metrics used by professional research analysts and others in the valuation, comparison, and investment recommendations of companies in the oil and gas exploration and production industry. The metrics are easily calculated from information provided in the sections "Costs incurred in oil and gas producing activities" and "Proved oil and gas reserve quantities" above. Finding cost provides some information as to the cost of adding proved reserves from various activities. Reserve replacement provides information related to how successful a company is at growing its proved reserve base. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in "Costs incurred in oil and gas producing activities." The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
  
                                         
Finding Costs Definitions:
                                        
> Drilling, excluding revisions - numerator defined as the sum of development costs and exploration costs and facility costs divided by a denominator defined as the sum of discoveries and extensions and infill reserves in an existing proved field. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
  
                                         
> Drilling, including revisions - numerator defined as the sum of development costs and exploration costs and facility costs divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and revisions. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
  
                                         
> All-in - numerator defined as total costs incurred, including asset retirement obligation divided by a denominator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and revisions. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
  
                                         
                                         
Reserve Replacement Ratio Definitions:
                                        
> Drilling, excluding revisions - numerator defined as the sum of discoveries and extensions and infill reserves in an existing proved field divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
  
                                         
> Drilling, including revisions - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, and revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.
  
                                         
> All-in - numerator defined as the sum of discoveries and extensions, infill reserves in an existing proved field, purchases of minerals in place, and revisions divided by production. To consider the impact of divestitures on this metric, further include sales of reserves in denominator.