EX-99.1 2 dex991.htm PRESS RELEASE Press release

Exhibit 99.1

LOGO

SandRidge Energy, Inc. Reports Financial and Operational Results for Fourth Quarter and Full Year 2009

Oklahoma City, Oklahoma, February 25, 2010 – SandRidge Energy, Inc. (NYSE: SD) today announced financial and operational results for the quarter and year ended December 31, 2009.

Financial Highlights

Fourth Quarter

 

  •  

Adjusted net income available to common stockholders (which excludes non-cash asset impairments, unrealized gains or losses on derivative contracts and gains or losses on the sale of assets) of $26.3 million, or $0.14 per share, in fourth quarter 2009 compared to adjusted net income available to common stockholders of $10.2 million, or $0.06 per share, in fourth quarter 2008

 

  •  

Adjusted EBITDA of $150.2 million compared to $157.9 million in fourth quarter 2008

 

  •  

Operating cash flow of $112.8 million compared to $114.7 million in fourth quarter 2008

 

  •  

Net loss applicable to common stockholders of $434.2 million (including $388.9 million non-cash full cost ceiling impairment), or $2.36 per share fully diluted, attributable to lower natural gas and oil pricing levels during 2009 compared to net loss applicable to common stockholders of $1.59 billion (including $1.86 billion non-cash full cost ceiling impairment), or $9.78 per share fully diluted, in fourth quarter 2008

 

  •  

No borrowings outstanding under credit facility at December 31, 2009

Full Year

 

  •  

Adjusted net income available to common stockholders (which excludes non-cash asset impairments, unrealized gains or losses on derivative contracts and gains or losses on the sale of assets) of $139.8 million, or $0.80 per share, in 2009 compared to adjusted net income available to common stockholders of $142.5 million, or $0.92 per share, in 2008

 

  •  

Adjusted EBITDA of $584.0 million compared to $678.2 million in 2008

 

  •  

Operating cash flow of $417.6 million compared to $540.3 million in 2008

 

  •  

Net loss applicable to common stockholders of $1.78 billion (including $1.69 billion non-cash full cost ceiling impairment), or $10.20 per share fully diluted, attributable to lower natural gas and oil pricing levels during 2009 compared to net loss applicable to common stockholders of $1.46 billion (including $1.86 billion non-cash full cost ceiling impairment), or $9.36 per share fully diluted, in 2008

Adjusted net income available to common stockholders, adjusted EBITDA and operating cash flow are non-GAAP financial measures. Each measure is defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” beginning on page 10.

Operational Highlights and Year End Reserves

 

  •  

Average of six rigs running in the Piñon Field area during fourth quarter 2009. Currently 12 rigs running in the Piñon Field.

 

  •  

Closed $800 million acquisition of Permian Basin oil assets from Forest Oil Corporation in December 2009. Currently six rigs running in the Permian Basin.

 

  •  

2009 natural gas and oil production increased to 104.8 Bcfe (287 MMcfe per day) compared to 101.4 Bcfe (277 MMcfe per day) in 2008.

 

  •  

Net acreage position in Permian Basin at December 31, 2009 increased by approximately 100,000 net acres from December 31, 2008 to a current total of approximately 150,000 net acres.

  •  

Oil reserves increased 144% year over year using new SEC 12-month average pricing. Oil reserves increased 180% and 182% using alternate pricing scenarios based upon spot prices at December 31, 2009 and the average 10-year NYMEX strip price at December 31, 2009, respectively.

 

  •  

Oil reserves represent 69% of total PV-10 value using new SEC 12-month average pricing. Oil reserves represent 54% and 49% of total PV-10 value using alternate pricing scenarios based upon spot prices at December 31, 2009 and the average 10-year NYMEX strip price at December 31, 2009, respectively.

 

  •  

Proved reserves total 1.312 Tcfe at December 31, 2009 based upon new SEC 12-month average pricing. Proved reserves total 2.566 Tcfe and 2.678 Tcfe using alternate pricing scenarios based upon spot prices at December 31, 2009 and the average 10-year NYMEX strip price at December 31, 2009, respectively.

Presentation slides to be viewed in conjunction with certain of the above Operational Highlights are available on the company’s website, www.sandridgeenergy.com, under Investor Relations/Events.

Tom L. Ward, Chief Executive Officer of SandRidge, commented, “We have transformed our company to one whose oil reserves comprise approximately 50% to 70% of its total PV-10 value based on the pricing scenarios included in our sensitivity analysis. We are now poised to grow through the development of both oil and gas properties and expect our percentage of revenues from oil sales to continue to increase in the future. Our earnings potential is strong with over 80% of our estimated 2010 production hedged at $9.15 per Mcfe. We have hedged over $1.1 billion of oil revenues through 2012. We are also excited about the exploration opportunities that lie ahead in the WTO and have spud two wells to test two distinct structures that have been identified by 3-D seismic. Lastly, the Century Plant is scheduled to start up this summer, enabling us to expand our drilling of the Warwick Caballos reservoir in the Piñon Field.

“While gas PUDs were reduced on a PV-10 basis using a price of $3.87 per Mcf as determined under the new SEC price rule, we estimate our total proved reserves would have increased by about 20% had we used year end 2009 prices under the old SEC price rule. Under all pricing scenarios, the PV-10 value per Mcfe of our reserves ranks highly among our peers. As we approach start up of the Century Plant, we have ramped up drilling in the Piñon Field from a low of four rigs in the fourth quarter of 2009 to 12 rigs currently. In addition, we are currently running six rigs in the Permian Basin, where we are achieving exceptional rates of return at current oil prices. We are fortunate to be able to maximize earnings by running an appropriate mix of rigs in our oil and gas plays and having the option to adjust further from gas to oil drilling as dictated by project economics and return on investment.”

 

2

Proved Reserves and PV-10 Sensitivity Analysis

The table below presents a comparison of the company’s reserve volumes, PV-10, reserve replacement metrics and value of proved reserves per unit calculated using the 12-month average price as required under new SEC pricing rules that became effective December 31, 2009 and two alternate pricing scenarios. The company believes the estimation of reserves based upon the December 31, 2009 spot price is a useful comparison to the company’s reserve calculation as of December 31, 2008, which also was based on year end spot prices under SEC rules then in effect. The estimation of reserves using a constant price based upon the average 10-year NYMEX strip price as of December 31, 2009 provides another view of the company’s reserves. Cost assumptions were held constant among all three pricing scenarios. Prices below are before field differentials, although field differentials are applied in the calculations.

 

     Prices Held Constant At:  
     $3.87
per
Mcf
$57.65
per Bbl
(1)		     $5.79
per
Mcf
$79.34
per Bbl
(2)		     $6.94
per
Mcf
$92.24
per Bbl
(3)		  
     (Bcfe)     (Bcfe)     (Bcfe)  

Beginning balance, 01/01/09

      2,159        2,159        2,159   

Revision - price

      (1,123 )      51        157   

Revision - changes to previous estimates

      (69 )      (88 )      (86 ) 

Acquisitions

      442        521        524   

Divestitures

      (1 )      (1 )      (1 ) 

Extensions and discoveries

      9        29        30   

Production

      (105 )      (105 )      (105 ) 
                        

Ending balance, 12/31/09

      1,312        2,566        2,678   
                        

PV-10 (in millions)(4)

       

Oil properties

    $ 1,076      $ 1,955      $ 2,588   

Gas properties

      485        1,635        2,652   
                        

Total

    $ 1,561      $ 3,590      $ 5,240   

% Oil properties to total

      69 %      54 %      49 % 

Reserve replacement(5)

      —          513        625   

Reserve replacement ratio(5)

      —          489 %      596 % 

Drilling and acquisition finding costs ($/Mcfe)(6)

    $ 3.14      $ 2.59      $ 2.56   

PV-10 of proved reserves ($/Mcfe)(4)

    $ 1.19      $ 1.40      $ 1.96   

 

(1)

12-month average prices under current SEC rules. Oil is West Texas Intermediate posted price, NYMEX equivalent price of $61.14.

(2)

Spot prices at December 31, 2009.

(3)

Price based on the average 10-year NYMEX strip.

(4)

Represents estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes. PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to Standardized Measure see “Non-GAAP Financial Measures" beginning on page 10.

(5)

The company’s management uses proved reserve replacement as an indicator of its ability to replenish annual production volumes and grow its reserves. Management believes that reserve replacement is relevant and useful information that is commonly used by analysts, investors and other interested parties in the natural gas and oil industry as a means of evaluating the operational performance and prospects of entities engaged in the production and sale of depleting natural resources. It should be noted that proved reserve replacement is a statistical indicator that has limitations. As an annual measure, proved reserve replacement 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 proved reserve replacement does not consider the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. This financial measure does not distinguish between changes in reserve quantities that are developed and those that will require additional time and funding to develop.

(6)

Calculated exclusive of price-related revisions and costs incurred for pipe inventory, seismic data and the acquisition of unproved properties.

 

3

Operational and Financial Statistics

Information regarding the company’s production, pricing, costs and earnings is presented below:

 

     Three Months Ended December 31,     Year Ended December 31,  
     2009     2008     2009     2008  

Production:

         

Natural gas (MMcf)

      19,877        24,305        87,461        87,402   

Oil (MBbl)(1)

      731        583        2,894        2,334   

Natural gas equivalent (MMcfe)

      24,263        27,801        104,823        101,405   

Daily production (MMcfed)

      264        302        287        277   

Average price per unit:

         

Realized natural gas price per Mcf - as reported

    $ 3.80      $ 5.01      $ 3.36      $ 7.95   

Realized impact of derivatives per Mcf

      3.50        2.35        3.84        (0.05 ) 
                                

Net realized price per Mcf

    $ 7.30      $ 7.36      $ 7.20      $ 7.90   
                                

Realized oil price per barrel - as reported (1)

    $ 69.22      $ 51.92      $ 55.62      $ 91.54   

Realized impact of derivatives per barrel (1)

      3.16        13.42        4.07        (3.45 ) 
                                

Net realized price per barrel (1)

    $ 72.38      $ 65.34      $ 59.69      $ 88.09   
                                

Realized price per Mcfe - as reported

    $ 5.20      $ 5.46      $ 4.34      $ 8.96   
                                

Net realized price per Mcfe - including impact of derivatives per Mcfe

    $ 8.16      $ 7.80      $ 7.66      $ 8.83   
                                

Average cost per Mcfe:

         

Lease operating

    $ 1.69      $ 1.56      $ 1.61      $ 1.57   

Production taxes

      0.04        0.04        0.04        0.30   

General and administrative:

         

General and administrative, excluding stock-based compensation

      0.70        1.02        0.74        0.89   

Stock-based compensation

      0.26        0.16        0.22        0.19   

Depletion

      2.00        2.94        1.68        2.87   

Lease operating cost per Mcfe:

         

Excluding offshore and tertiary recovery

    $ 1.31      $ 1.30      $ 1.40      $ 1.35   

Offshore operations

      4.23        12.86        3.34        4.53   

Tertiary recovery operations

      16.49        10.95        10.85        11.16   

Earnings per share:

         

(Loss) income per share (applicable) available to common stockholders(2)

         

Basic

    $ (2.36 )    $ (9.78 )    $ (10.20 )    $ (9.36 ) 

Diluted

      (2.36 )      (9.78 )      (10.20 )      (9.36 ) 

Adjusted net income per share available to common stockholders

      0.14        0.06        0.80        0.92   

Weighted average number of common shares outstanding (in thousands):

         

Basic

      184,211        163,044        175,005        155,619   

Diluted

      184,211        163,044        175,005        155,619   

 

(1)

Includes NGLs.

(2)

Includes effects of non-cash full cost ceiling impairments of $0.39 billion and $1.86 billion for the three month periods ended December 31, 2009 and 2008, respectively, and $1.69 billion and $1.86 billion for the years ended December 31, 2009 and 2008, respectively.

 

4

2009 Financial Results

The company reported a net loss applicable to common stockholders for 2009 of $1.78 billion due to non-cash full cost ceiling impairments on its natural gas and oil properties totaling $1.7 billion during 2009 ($1.3 billion at March 31, 2009 and $0.4 billion at December 31, 2009) and price-related declines in natural gas and oil revenues.

Ceiling Test Impairment

The company utilizes the full cost method of accounting for its natural gas and oil properties. As required by SEC rules effective December 31, 2009, proved reserve volumes at December 31, 2009 were calculated using the average price for the 12-month period, using the first-day-of-the-month price for each month, compared to a one-day period end pricing method used in previous years. The use of these calculated averages resulted in a non-cash impairment charge of approximately $388.9 million against the carrying value of the company’s natural gas and oil properties for the fourth quarter of 2009.

The calculated 12-month average per unit prices used in the estimation of proved reserves and future net revenues at December 31, 2009 were $3.87 per Mcf for natural gas and $57.65 per barrel for oil compared to the one-day period end prices of $5.71 per Mcf for natural gas and $41.00 per barrel of oil at December 31, 2008. This decline in natural gas prices caused some of the company’s proved undeveloped reserves to be removed from its total proved reserves as those quantities could not be economically developed at the calculated price used to estimate proved reserves at December 31, 2009. Additionally, the decline in natural gas prices caused a shortening of the productive lives of certain proved properties as these properties became uneconomic earlier in their lives with the use of lower natural gas prices compared to prices used in the estimation of reserves in the previous periods. The PV-10, based upon 12-month average prices as required under the new SEC pricing rules, was $1.56 billion at December 31, 2009 compared to PV-10 of $2.26 billion at December 31, 2008 that was calculated using period end pricing.

Natural Gas and Oil Pricing

The average price received, excluding the impact of derivative contract settlements, for natural gas decreased 57.7% in the full year 2009 to $3.36 per Mcf compared to $7.95 per Mcf in 2008. The average price received, excluding the impact of derivative contract settlements, for natural gas in the fourth quarter of 2009 decreased 24.2% to $3.80 per Mcf compared to $5.01 per Mcf in the fourth quarter of 2008. Similarly, average prices received, excluding the impact of derivative contract settlements, for oil production in the full year 2009 decreased 39.2% to $55.62 per barrel. However, average prices received, excluding the impact of derivative contract settlements, for oil production in the fourth quarter of 2009 increased 33.3% to $69.22 per barrel from fourth quarter 2008.

Natural gas and oil production increased by 3.4% to 104.8 Bcfe for 2009 from 101.4 Bcfe for 2008. This increase in total production for 2009 was offset by the lower average commodity prices received during the period, resulting in decreased natural gas and oil revenues of $454.7 million for 2009 compared to $908.7 million in 2008. Increased fourth quarter 2009 oil production and the higher associated prices received for that production were offset by lower natural gas production and average natural gas prices received resulting in decreased natural gas and oil revenues of $126.1 million compared to $151.9 million for the same period in 2008.

Gain (Loss) on Derivative Contracts

The company enters into natural gas and oil swaps and basis swaps for a portion of its production in order to stabilize future cash inflows for planning purposes. In that regard, 2009 results benefited by a net gain of $147.5 million ($200.5 million unrealized loss and $348.0 million realized gain) on derivative commodity contracts. This compares to a $211.4 million net gain ($224.4 million unrealized gain and $13.0 million realized loss) for 2008. The net gain on derivative commodity contracts for fourth quarter 2009 was $7.8 million ($64.0 million unrealized loss and $71.8 million realized gain) compared to a net gain of $215.5 million ($150.5 million unrealized gain and $65.0 million realized gain) for the same period in 2008.

 

5

Drilling Activities

At December 31, 2009, the company had 15 rigs operating compared to 8 at September 30, 2009 and 17 at December 31, 2008. The company averaged 11 rigs operating during the fourth quarter of 2009 and drilled 46 wells. The company drilled a total of 140 wells during 2009. A total of 44 gross (41.5 net) operated wells were completed and brought on production throughout the fourth quarter of 2009 bringing the total number of operated wells completed and brought on production during 2009 to 160 gross (148.0 net). Currently, SandRidge has 24 rigs operating, of which 12 are drilling in the Piñon Field area of the West Texas Overthrust (“WTO”) and 6 are drilling in the Permian Basin.

CO2 Treating Capacity and Century Plant

Construction of the Century Plant, located in Pecos County, Texas, remains on schedule with anticipated start up of Phase 1 in summer 2010. Century Plant Phase 1 will add approximately 400 MMcf per day of CO2 treating capacity, giving the company access to total CO2 treating capacity in the WTO of approximately 775 MMcf per day. Century Plant Phase 2 is expected to come on line in 2011, increasing access to total CO2 treating capacity to over 1 Bcf per day.

Exploration Update

Exploration efforts during the fourth quarter continued to focus on the integration of 3-D seismic data and evolving sub-surface geologic models. The first two wells of the company’s exploratory program began drilling during the first quarter of 2010 and will each test structures of greater than 10,000 acres in size.

Capital Expenditures

The table below summarizes the company’s capital expenditures for the three-month periods and years ended December 31, 2009 and 2008:

 

     Three Months Ended December 31,    Year Ended December 31,
     2009     2008    2009    2008
     (in thousands)

Drilling and production

           

WTO

    $ 52,731      $ 234,552    $ 249,187    $ 985,435

Non-WTO (excluding tertiary)

      40,641        117,354      186,035      390,684

Tertiary

      1,852        12,800      14,057      31,564
                            
     95,224        364,706      449,279      1,407,683

Leasehold and seismic

           

WTO

      772        70,349      10,461      303,289

Non-WTO (excluding tertiary)

      7,902        44,231      17,836      148,703

Tertiary

      —          —        —        87
                            
     8,674        114,580      28,297      452,079

Pipe inventory(1)

      (18,613 )      14,324      77,652      47,245

Total exploration and development

      85,285        493,610      555,228      1,907,007
                            

Drilling and oil field services

      1,320        2,030      4,090      52,869

Midstream

      8,637        50,335      52,425      160,460

Other - general

      7,699        22,517      33,399      57,511
                            

Total capital expenditures, excluding acquisitions

      102,941        568,492      645,142      2,177,847
                            

Acquisition

      795,074        —        795,074      —  
                            

Total capital expenditures

    $ 898,015      $ 568,492    $ 1,440,216    $ 2,177,847
                            

 

(1)

Pipe expenditure amount for the three months ended December 31, 2009 represents transfers of pipe to the full cost pool for use in drilling and production activities.

 

6

The company’s fourth quarter 2009 capital expenditures, excluding the Forest acquisition, totaled $102.9 million and were 81.9% lower than capital expenditures incurred for the same period in 2008 due to the company’s decreased drilling activities. Excluding the Forest acquisition, capital expenditures for 2009 were 70.4% lower than in 2008.

Costs incurred during 2009 in natural gas and oil property acquisition, exploration and development activities were $816.8 million, $126.3 million and $407.4 million, respectively, for a total of $1,350.5 million. Approximately $67.7 million of acquisition costs incurred during 2009 were for unproved properties. Approximately $6.8 million in seismic costs and $77.7 million in pipe inventory costs have been included in 2009 exploration costs incurred.

Derivative Contracts

The table below sets forth the company’s natural gas price and basis swaps and oil swaps through 2013 as of February 23, 2010. Current natural gas and oil derivative contracts excluding basis swaps account for 106 Bcfe, or approximately 82% of anticipated production for 2010, at $9.15 per Mcfe. Since November 29, 2009, the company has entered into additional oil swaps for 2010 and 2011, which are included below. The company currently does not have natural gas swaps for 2011, 2012 or 2013 or oil swaps for 2013.

 

     Year Ending
     12/31/2010    12/31/2011    12/31/2012    12/31/2013

Natural Gas Swaps:

            

Volume (Bcf)

      80.29      0.00      0.00      0.00

Swap

    $ 7.70      NM      NM      NM

Natural Gas Basis Swaps:

            

Volume (Bcf)

      82.13      104.03      113.46      14.60

Swap

    $ 0.74    $ 0.47    $ 0.55    $ 0.46

Oil Swaps:

            

Volume (MMBbls)

      4.29      4.75      4.39      0.00

Swap

    $ 82.03    $ 86.52    $ 88.26      NM

 

7

Balance Sheet

The company’s capital structure at December 31, 2009 and 2008 is presented below:

 

     December 31,  
     2009     2008  
     (in thousands)  

Cash and cash equivalents

    $ 7,861      $ 636   
                

Current maturities of long-term debt

    $ 12,003      $ 16,532   

Long-term debt (net of current maturities):

     

Senior credit facility

      —          573,457   

Notes payable—Drilling rig fleet and oil field services equipment

      6,304        17,375   

Mortgage

      17,020        17,952   

Senior Notes:

     

Senior Floating Rate Notes due 2014

      350,000        350,000   

8.625% Senior Notes due 2015

      650,000        650,000   

9.875% Senior Notes due 2016, net

      351,021        —     

8.0% Senior Notes due 2018

      750,000        750,000   

8.75% Senior Notes due 2020, net

      442,590        —     
                

Total debt

      2,578,938        2,375,316   

Stockholders’ equity:

     

Preferred stock

      5        —     

Common stock

      203        163   

Additional paid-in capital

      2,961,613        2,170,986   

Treasury stock, at cost

      (25,079 )      (19,332 ) 

Accumulated deficit

      (3,142,699 )      (1,358,296 ) 
                

Total SandRidge Energy, Inc. stockholders’ (deficit) equity

      (205,957 )      793,521   
                

Noncontrolling interest

      10,052        30   

Total capitalization

    $ 2,383,033      $ 3,168,867   
                

The company’s total debt (short-term and long-term) increased $203.6 million during 2009 through a combination of issuances of senior notes and net repayments of amounts outstanding under its senior credit facility with proceeds from issuances of preferred and common equity and asset sale transactions. Additionally, during 2009, the company made principal payments on its rig loans and real estate loan related to the purchase of the company’s headquarters building totaling $15.6 million and $0.9 million, respectively. At December 31, 2009, the company had classified $12.0 million of its long-term debt as current. This total included $11.1 million related to its rig loan and $0.9 million related to the real estate loan. Total debt as of December 31, 2009 was $2.579 billion compared to $2.375 billion at year-end 2008. The company was in compliance with all of the financial and other covenants contained in its debt agreements at December 31, 2009. During October 2009, the company’s $985.4 million borrowing base and $1.75 billion commitment were reaffirmed by the group of lenders under its senior credit facility. The company’s December 2009 issuance of its Senior Notes due 2020 reduced the borrowing base to $850.4 million at December 31, 2009.

During 2009, the company raised a total of approximately $1.8 billion through the private placements of 8.5% and 6.0% convertible perpetual preferred stock, the issuance of 9.875% Senior Notes due 2016 and 8.75% Senior Notes due 2020, registered underwritten offerings of common stock and the sale of its Piñon Field gathering and compression assets and deep drilling rights in East Texas. The company used proceeds from these transactions and cash flow from operations to fund the $800.0 million acquisition of properties from Forest and reduce amounts outstanding under its senior credit facility to $0 at December 31, 2009.

 

8

Operational Guidance

 

     Year Ending
December 31, 2010
     Previous
Projection as of
November 30, 2009		    Updated
Projection as of
February 25, 2010

Production

      

Natural Gas (Bcf)

    99 - 100    99

Oil (MMBbls)

    5.1 - 5.8    5
         

Total (Bcfe)

    130 - 135    130

Differentials

      

Natural Gas

    $0.90 - $0.95    $0.75

Oil

    7.00    7.00

Costs per Mcfe

      

Lifting

    $1.58 - $1.74    $1.58 - $1.74

Production Taxes

    0.20 - 0.25    0.20 - 0.25

DD&A - oil & gas

    1.29 - 1.42    1.79 - 1.99

DD&A - other

    0.37 - 0.41    0.37 - 0.41
         

Total DD&A

    $1.66 - $1.83    $2.16 - $2.40

G&A - cash

    0.62 - 0.68    0.62 - 0.68

G&A - stock

    0.22 - 0.25    0.22 - 0.25
         

Total G&A

    $0.84 - $0.93    $0.84 - $0.93

Interest Expense

    $1.63 - $1.80    $1.66 - $1.83

Corporate Tax Rate

    0%    0%

Deferral Rate

    0%    0%

Shares Outstanding at End of Period (in millions)

      

Common Stock

    212.9    213.3

Preferred Stock (converted)

    51.5    51.5
         

Fully Diluted

    264.4    264.8

Capital Expenditures ($ in millions)

      

Exploration and Production

    $715    $715

Land and Seismic

    35    35
         

Total Exploration and Production

    $750    $750

Oil Field Services

    5    5

Midstream and Other(1)

    105    105
         

Total Capital Expenditures

    $860    $860

 

(1)

Includes approximately $60MM - $70MM related to Midstream assets the company may offer for sale in 2010.

The company is updating certain guidance for 2010 from information previously provided on November 30, 2009. The company has updated its projected production and projected natural gas differentials have been reduced to reflect lower differentials experienced to date in 2010. Depreciation, depletion and amortization of oil and gas assets has increased due to the inclusion of assets acquired from Forest in the company’s amortization base. Interest expense per unit has increased due to the company’s issuance of 8.75% Senior Notes due 2020 during December 2009. Common stock outstanding has been updated to reflect recent and projected employee stock compensation activity. The remainder of the previously provided guidance remains unchanged.

 

9

Non-GAAP Financial Measures

Operating cash flow, adjusted EBITDA, adjusted net income available to common stockholders and PV-10 are non-GAAP financial measures.

The company defines operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities. It defines EBITDA as net (loss) income before income tax (benefit) expense, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA excluding interest income, gain or loss on the sale of assets and other various non-cash items (including asset impairments, income from equity investments, noncontrolling interest, stock-based compensation, unrealized (gain) loss on derivative contracts and provision for doubtful accounts). This definition of adjusted EBITDA generally conforms to the EBITDA definition in the company’s credit agreement.

Operating cash flow and adjusted EBITDA are supplemental financial measures used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses these measures because operating cash flow and adjusted EBITDA relate to the timing of cash receipts and disbursements that the company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow and adjusted EBITDA allow the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. These measures should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles (“GAAP”). Adjusted EBITDA should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

Management also uses the supplemental financial measure of adjusted net income available (loss applicable) to common stockholders, which excludes asset impairments, unrealized (loss) gain on derivative contracts and gain or loss on the sale of assets from net income available (loss applicable) to common stockholders. Management uses this financial measure as an indicator of the company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net income available (loss applicable) to common stockholders is not a measure of financial performance under GAAP and should not be considered a substitute for net income available (loss applicable) to common stockholders.

PV-10 represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using pricing assumptions in effect at the end of the period for periods prior to December 31, 2009 and 12-month average prices for the year ended December 31, 2009. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Management uses PV-10 as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the tax-paying status of the entity.

 

10

The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA, adjusted EBITDA, adjusted net income available (loss applicable) to common stockholders and PV-10.

Reconciliation of Net Cash Provided by Operating Activities to Operating Cash Flow

 

     Three Months Ended December 31,    Year Ended December 31,  
     2009    2008    2009    2008  
     (in thousands)  

Net cash provided by operating activities

    $ 38,339    $ 44,821    $ 311,559    $ 579,189   

Add (deduct):

            

Changes in operating assets and liabilities

      74,425      69,860      106,022      (38,875 ) 
                             

Operating cash flow

    $ 112,764    $ 114,681    $ 417,581    $ 540,314   
                             

Reconciliation of Net (Loss) Income to EBITDA and Adjusted EBITDA

 

     Three Months Ended December 31,     Year Ended December 31,  
     2009     2008     2009     2008  
     (in thousands)  

Net (loss) income

    $ (428,243 )    $ (1,594,658 )    $ (1,775,590 )    $ (1,441,280 ) 

Adjusted for:

         

Income tax (benefit) expense

      (4,602 )      (127,636 )      (8,716 )      (38,328 ) 

Interest expense(1)

      50,630        42,112        186,137        138,282   

Depreciation, depletion and amortization - other

      12,014        19,106        50,865        70,448   

Depreciation and depletion - natural gas and oil

      48,524        81,621        176,027        290,917   
                                

EBITDA

      (321,677 )      (1,579,455 )      (1,371,277 )      (979,961 ) 

Asset impairment

      402,732        1,867,497        1,707,150        1,867,497   

Provision for doubtful accounts

      152        125        214        1,748   

(Income) loss from equity investments

      7        (43 )      (1,020 )      (1,398 ) 

Interest income

      (88 )      (501 )      (375 )      (3,569 ) 

Stock-based compensation

      6,267        4,501        22,793        18,784   

Unrealized loss (gain) on derivative contracts

      62,736        (134,072 )      200,049        (215,675 ) 

Loss (gain) on sale of assets

      60        (142 )      26,419        (9,273 ) 
                                

Adjusted EBITDA

    $ 150,189      $ 157,910      $ 583,953      $ 678,153   
                                

 

(1)

Excludes unrealized (gain) loss on interest rate swap of ($1.3) million and $16.5 million for the three-month periods ended December 31, 2009 and 2008, respectively, and ($0.4) million and $8.7 million for the years ended December 31, 2009 and 2008, respectively.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA

 

     Three Months Ended December 31,    Year Ended December 31,  
     2009     2008    2009     2008  
     (in thousands)  

Net cash provided by operating activities

    $ 38,339      $ 44,821    $ 311,559      $ 579,189   

Changes in operating assets and liabilities

      74,425        69,860      106,022        (38,875 ) 

Interest expense(1)

      50,630        42,112      186,137        138,282   

Other non-cash items

      (13,205 )      1,117      (19,765 )      (443 ) 
                               

Adjusted EBITDA

    $ 150,189      $ 157,910    $ 583,953      $ 678,153   
                               

 

(1)

Excludes unrealized (gain) loss on interest rate swap of ($1.3) million and $16.5 million for the three-month periods ended December 31, 2009 and 2008, respectively, and ($0.4) million and $8.7 million for the years ended December 31, 2009 and 2008, respectively.

 

11

Reconciliation of Net (Loss) Income (Applicable) Available to Common Stockholders to Adjusted

Net Income Available to Common Stockholders

 

     Three Months Ended December 31,     Year Ended December 31,  
     2009     2008     2009     2008  
     (in thousands, except per share amounts)  

Net (loss) income (applicable) available to common stockholders

    $ (434,240 )    $ (1,594,658 )    $ (1,784,403 )    $ (1,457,512 ) 

Asset impairment

      402,732        1,867,497        1,707,150        1,867,497   

Unrealized loss (gain) on derivative contracts

      62,736        (134,072 )      200,049        (215,675 ) 

Loss (gain) on sale of assets

      60        (142 )      26,419        (9,273 ) 

Effect of income taxes

      (4,949 )      (128,450 )      (9,445 )      (42,549 ) 
                                

Adjusted net income available to common stockholders

      26,339        10,175        139,770        142,488   

Preferred stock dividends

      5,997        —          8,813        16,232   
                                

Total adjusted net income

    $ 32,336      $ 10,175      $ 148,583      $ 158,720   
                                

Weighted average number of common shares outstanding:

         

Basic

      184,211        163,044        175,005        155,619   

Fully diluted(1)

      238,912        164,837        229,337        157,090   

Per share - basic

    $ 0.14      $ 0.06      $ 0.80      $ 0.92   
                                

Per share - fully diluted

    $ 0.14      $ 0.06      $ 0.65      $ 1.01   
                                

 

(1)

Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating earnings per share in accordance with GAAP.

Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10

 

     December 31,
     2009    2008

Standardized measure of discounted net cash flows

    $ 1,561.0    $ 2,220.6

Present value of future net income tax expense discounted at 10%(1)

      —        37.9
             

PV-10

    $ 1,561.0    $ 2,258.5
             

 

(1)

Due to a full valuation allowance on the company's deferred tax asset at December 31, 2009 that serves to reduce to $0 a tax benefit that otherwise would result from the tax effects of PV-10, there was no effect of income taxes in the Standardized Measure at December 31, 2009.

 

12

Conference Call Information

The company will host a conference call to discuss these results on Friday, February 26, 2010 at 8:00 am CST. The telephone number to access the conference call from within the U.S. is 866-277-1182 and from outside the U.S. is 617-597-5359. The passcode for the call is 22952241. An audio replay of the call will be available at 11:00 am CST on February 26, 2010 until 11:59 pm CDT on March 26, 2010. The number to access the conference call replay from within the U.S. is 888-286-8010 and from outside the U.S. is 617-801-6888. The passcode for the replay is 52480129.

A live audio webcast of the conference call also will be available via SandRidge’s website, www.sandridgeenergy.com, under Investor Relations/Events. The webcast will be archived for replay on the company’s website for 30 days.

3rd Annual Investor/Analyst Meeting

March 2, 2010 (Tuesday) – New York, NY at the Grand Hyatt New York, 109 East 42nd Street at 8:00 am EST to 12:00 pm EST

Conference Participation

SandRidge Energy, Inc. will participate in the following upcoming events:

 

•  

March 3, 2010 – Simmons & Company International, 10th Annual Energy Conference

 

•  

March 23, 2010 – Howard Weil, 2010 Energy Conference

 

•  

March 26, 2010 – Barclays Capital, 2010 High Yield Bond and Syndicated Loan Conference

 

•  

April 8, 2010 – UBS, Energy Mini-Conference

At 8:00 am Central Time on the day of each presentation, the corresponding slides and webcast information will be accessible on the Investor Relations portion of the company’s website at www.sandridgeenergy.com. Please check the website for updates regularly as this schedule is subject to change. Also, please note that SandRidge Energy, Inc. intends for its website to be used as a reliable source of information for all future events in which it may participate. Slides and webcasts (where applicable) will be archived and available for at least 30 days after each presentation.

First Quarter 2010 Earnings Release and Conference Call

May 6, 2010 (Thursday) – Earnings press release and filing of 10-Q after market close

May 7, 2010 (Friday) – Earnings conference call at 9:00 am EST

 

13

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(in thousands, except per share amounts)

 

     Three Months Ended December 31,     Years ended December 31,  
     2009     2008     2009     2008  
     (Unaudited)              

Revenues:

         

Natural gas and oil

    $ 126,077      $ 151,927      $ 454,705      $ 908,689   

Drilling and services

      6,453        10,854        23,902        47,199   

Midstream and marketing

      23,977        33,362        86,028        207,602   

Other

      6,570        4,512        26,409        18,324   
                                

Total revenues

      163,077        200,655        591,044        1,181,814   

Expenses:

         

Production

      40,906        43,492        169,285        159,004   

Production taxes

      857        1,138        4,010        30,594   

Drilling and services

      9,202        5,760        30,899        26,186   

Midstream and marketing

      21,982        29,596        78,684        186,655   

Depreciation and depletion - natural gas and oil

      48,524        81,621        176,027        290,917   

Depreciation, depletion and amortization - other

      12,014        19,106        50,865        70,448   

Impairment

      402,732        1,867,497        1,707,150        1,867,497   

General and administrative

      23,133        32,940        100,256        109,372   

Gain on derivative contracts

      (7,805 )      (215,525 )      (147,527 )      (211,439 ) 

Loss (gain) on sale of assets

      60        (142 )      26,419        (9,273 ) 
                                

Total expenses

      551,605        1,865,483        2,196,068        2,519,961   
                                

(Loss) income from operations

      (388,528 )      (1,664,828 )      (1,605,024 )      (1,338,147 ) 
                                

Other income (expense):

         

Interest income

      88        501        375        3,569   

Interest expense

      (49,323 )      (58,606 )      (185,691 )      (147,027 ) 

(Loss) income from equity investments

      (7 )      43        1,020        1,398   

Other income, net

      7,172        598        7,272        1,454   
                                

Total other (expense) income

      (42,070 )      (57,464 )      (177,024 )      (140,606 ) 
                                

(Loss) income before income tax (benefit) expense

      (430,598 )      (1,722,292 )      (1,782,048 )      (1,478,753 ) 

Income tax (benefit) expense

      (4,602 )      (127,636 )      (8,716 )      (38,328 ) 
                                

Net (loss) income

      (425,996 )      (1,594,656 )      (1,773,332 )      (1,440,425 ) 

Less: net income attributable to noncontrolling interest

      2,247        2        2,258        855   
                                

Net (loss) income attributable to SandRidge Energy, Inc.

      (428,243 )      (1,594,658 )      (1,775,590 )      (1,441,280 ) 

Preferred stock dividends and accretion

      5,997        —          8,813        16,232   
                                

(Loss applicable) income available to SandRidge Energy, Inc. common stockholders

    $ (434,240 )    $ (1,594,658 )    $ (1,784,403 )    $ (1,457,512 ) 
                                

Basic and Diluted Earnings Per Share:

         

Net (loss) income attributable to SandRidge Energy, Inc.

    $ (2.33 )    $ (9.78 )    $ (10.15 )    $ (9.26 ) 

Preferred stock dividends

      (0.03 )      —          (0.05 )      (0.10 ) 
                                

Basic and diluted (loss) income per share (applicable) available to SandRidge Energy, Inc. common stockholders

    $ (2.36 )    $ (9.78 )    $ (10.20 )    $ (9.36 ) 
                                

Weighted average number of common shares outstanding:

         

Basic

      184,211        163,044        175,005        155,619   
                                

Diluted

      184,211        163,044        175,005        155,619   
                                

 

14

SandRidge Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(in thousands, except per share data)

 

     December 31,  
     2009     2008  
ASSETS     

Current assets:

     

Cash and cash equivalents

    $ 7,861      $ 636   

Accounts receivable, net:

     

Trade

      105,412        102,746   

Related parties

      64        6,327   

Derivative contracts

      105,994        201,111   

Inventories

      3,707        3,686   

Costs in excess of billings

      12,346        —     

Other current assets

      20,580        41,407   
                

Total current assets

      255,964        355,913   

Natural gas and crude oil properties, using full cost method of accounting

     

Proved

      5,913,408        4,676,072   

Unproved

      281,811        215,698   

Less: accumulated depreciation, depletion and impairment

      (4,223,437 )      (2,369,840 ) 
                
     1,971,782        2,521,930   
                

Other property, plant and equipment, net

      461,861        653,629   

Derivative contracts

      —          45,537   

Investments

      —          6,088   

Restricted deposits

      32,894        32,843   

Other assets

      57,816        39,118   
                

Total assets

    $ 2,780,317      $ 3,655,058   
                
LIABILITIES AND EQUITY     

Current liabilities:

     

Current maturities of long-term debt

    $ 12,003      $ 16,532   

Accounts payable and accrued expenses:

     

Trade

      203,048        366,337   

Related parties

      860        230   

Derivative contracts

      7,080        5,106   

Asset retirement obligation

      2,553        275   

Billings in excess of costs incurred

      —          14,144   
                

Total current liabilities

      225,544        402,624   

Long-term debt

      2,566,935        2,358,784   

Other long-term obligations

      14,099        11,963   

Derivative contracts

      61,060        3,639   

Asset retirement obligation

      108,584        84,497   
                

Total liabilities

      2,976,222        2,861,507   
                

Commitments and contingencies

     

Equity:

     

SandRidge Energy, Inc. stockholders' equity:

     

Preferred stock, $0.001 par value, 50,000 shares authorized:

     

8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2009 and no shares issued and outstanding at December 31, 2008; aggregate liquidation preference of $265,000 at December 31, 2009

      3        —     

6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at December 31, 2009 and no shares issued and outstanding at December 31, 2008; aggregate liquidation preference of $200,000 at December 31, 2009

      2        —     

Common stock, $0.001 par value, 400,000 shares authorized; 210,581 issued and 208,715 outstanding at December 31, 2009 and 167,372 issued and 166,046 outstanding at December 31, 2008

      203        163   

Additional paid-in capital

      2,961,613        2,170,986   

Treasury stock, at cost

      (25,079 )      (19,332 ) 

Accumulated deficit

      (3,142,699 )      (1,358,296 ) 
                

Total SandRidge Energy, Inc. stockholders' (deficit) equity

      (205,957 )      793,521   

Noncontrolling interest

      10,052        30   
                

Total (deficit) equity

      (195,905 )      793,551   
                

Total liabilities and equity

    $ 2,780,317      $ 3,655,058   
                

 

15

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(in thousands)

 

     Years Ended December 31,  
     2009     2008  

CASH FLOWS FROM OPERATING ACTIVITIES:

     

Net loss

    $ (1,773,332 )    $ (1,440,425 ) 

Adjustments to reconcile net loss to net cash provided by operating activities:

     

Provision for doubtful accounts

      214        1,748   

Depreciation, depletion and amortization

      226,892        361,365   

Impairment

      1,707,150        1,867,497   

Debt issuance costs amortization

      7,477        5,623   

Discount amortization on long-term debt

      990        —     

Deferred income taxes

      —          (47,530 ) 

Unrealized loss (gain) on derivative contracts

      200,049        (215,675 ) 

Loss (gain) on sale of assets

      26,419        (9,273 ) 

Interest income - restricted deposits

      (51 )      (402 ) 

Income from equity investments

      (1,020 )      (1,398 ) 

Stock-based compensation

      22,793        18,784   

Changes in operating assets and liabilities increasing (decreasing) cash:

     

Receivables

      8,760        3,735   

Inventories

      61        307   

Other current assets

      20,827        (20,603 ) 

Other assets and liabilities, net

      (26,937 )      14,271   

Accounts payable and accrued expenses

      (108,733 )      41,165   
                

Net cash provided by operating activities

      311,559        579,189   
                

CASH FLOWS FROM INVESTING ACTIVITIES:

     

Capital expenditures for property, plant and equipment(1)

      (715,205 )      (2,058,415 ) 

Acquisitions of assets

      (795,074 )      —     

Proceeds from sale of assets

      263,220        158,781   

Contributions on equity investments

      —          (1,528 ) 

Loans to equity investees

      —          (7,500 ) 

Fundings of restricted deposits

      —          (781 ) 
                

Net cash used in investing activities

      (1,247,059 )      (1,909,443 ) 
                

CASH FLOWS FROM FINANCING ACTIVITIES:

     

Proceeds from borrowings

      2,619,607        3,252,209   

Repayments of borrowings

      (2,416,975 )      (1,944,542 ) 

Dividends paid - redeemable convertible preferred

      —          (17,552 ) 

Noncontrolling interest distributions

      (26 )      (5,497 ) 

Proceeds from issuance of common stock

      324,830        —     

Proceeds from issuance of convertible perpetual preferred stock

      443,210        —     

Stock-based compensation excess tax benefit

      (3,864 )      4,594   

Purchase of treasury stock

      (5,747 )      (3,553 ) 

Debt issuance costs

      (18,310 )      (17,904 ) 
                

Net cash provided by financing activities

      942,725        1,267,755   
                

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

      7,225        (62,499 ) 

CASH AND CASH EQUIVALENTS, beginning of year

      636        63,135   
                

CASH AND CASH EQUIVALENTS, end of year

    $ 7,861      $ 636   
                

Supplemental Disclosure of Cash Flow Information:

     

Cash paid for interest, net of amounts capitalized

    $ 171,994      $ 131,183   

Cash paid for income taxes

      2,908        2,191   

Supplemental Disclosure of Noncash Investing and Financing Activities:

     

Change in accrued capital expenditures(1)

    $ (70,063 )    $ 119,432   

Convertible perpetual preferred stock dividends payable

      8,813        —     

Accretion on redeemable convertible preferred stock

      —          7,636   

 

(1)

Capital expenditures on an accrual basis were $645,142 for the year ended December 31, 2009.

 

16

For further information, please contact:

Kevin R. White

Senior Vice President

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, OK 73102-6406

(405) 429-5515

Cautionary Note to Investors - This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, but not limited to, the information appearing under the heading “Operational Guidance.” These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of future natural gas and oil production, pricing differentials, operating costs and capital spending, and descriptions of our development plans. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of natural gas and oil prices, our success in discovering, estimating, developing and replacing natural gas and oil reserves, actual decline curves and the actual effect of adding compression to gas wells, the availability and terms of capital, the ability of counterparties to transactions with us to meet their obligations, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, construction risks related to the Century Plant, including the reliance we place on third parties, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A - “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2009 and in comparable “risk factors” sections of our Quarterly Reports on Form 10-Q filed after the date of this press release. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.

In this press release, the company includes a table demonstrating the sensitivity of the company’s proved oil and gas reserves to price fluctuations by comparing the reserves calculated under the price assumptions required by current U.S. Securities and Exchange Commission (“SEC”) rules to (1) spot prices at December 31, 2009, and (2) the 10-year average NYMEX strip prices as of December 31, 2009. The reserves presented under these alternative price assumptions are not calculated in accordance with current SEC rules, and they have not been reviewed by independent petroleum engineers. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and, accordingly, are subject to substantially greater risk of being actually realized by the company. For a discussion of the company’s proved reserves, as calculated under current SEC rules, we refer you to the company’s Annual Report on Form 10-K referenced above.

SandRidge Energy, Inc. is a natural gas and oil company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge and its subsidiaries also own and operate gas gathering and processing facilities and CO2 treating and transportation facilities and conduct marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and operates a drilling rig and related oil field services business. SandRidge focuses its exploration and production activities in West Texas, the Permian Basin, the Mid-Continent, the Cotton Valley Trend in East Texas, the Gulf Coast, and the Gulf of Mexico. SandRidge’s internet address is www.sandridgeenergy.com.

 

17