FORM 8-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): April 2, 2012

 

 

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1-33784   20-8084793

(State or other jurisdiction

of incorporation)

 

(Commission

File Number)

 

(I.R.S. Employer

Identification No.)

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma

  73102
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (405) 429-5500

Not Applicable

Former name or former address, if changed since last report

 

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 


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Item 7.01 Regulation FD Disclosure.

As previously reported, on February 1, 2012, SandRidge Energy, Inc. (the “Company”) and Dynamic Offshore Holding, LP (the “Seller”) entered into an Equity Purchase Agreement (the “Equity Purchase Agreement”), pursuant to which the Company will acquire 100% of the outstanding equity interests of Dynamic Offshore Resources, LLC, a Delaware limited liability company and wholly owned subsidiary of Seller (“Dynamic”). The Equity Purchase Agreement provides that, at the closing, the Company will pay to the Seller 73,961,554 shares of Company common stock and $681,828,337 in cash. Consummation of the transaction is subject to customary conditions, including the absence of any material adverse effect relating to Dynamic. The Company anticipates that the closing will occur during the quarter ended June 30, 2012.

This Current Report on Form 8-K is being furnished to provide additional information about the Company and Dynamic. It includes Dynamic’s audited historical financial statements for the three years ended December 31, 2011, as well as audited historical financial statements for the two years ended December 31, 2010 of certain oil and natural gas interests in the Gulf of Mexico (the “XTO Properties”) that Dynamic acquired in 2011 from Exxon Mobil Corporation, and Dynamic’s unaudited pro forma condensed statement of operations for the year ended December 31, 2011 showing the effects of Dynamic’s acquisition of the XTO Properties. See Index to Financial Statements. Unless otherwise specifically stated, the information included in this Current Report on Form 8-K does not include information related to our pending acquisition of Dynamic.

Dynamic is an oil and natural gas exploration, development and production company with operations in the Gulf of Mexico. As of December 31, 2011, Dynamic’s estimated net proved reserves were 62.5 MMBoe, of which 51% was oil and 81% were proved developed, with an associated PV-10 of approximately $1.895 billion, based on SEC pricing of $96.19 per Bbl for oil and $4.118 per MMBtu for natural gas. During February 2012, Dynamic’s properties had aggregate average net daily production of approximately 25,500 Boe per day. The oil and gas reserve estimates for Dynamic are based on a December 31, 2011 reserve report prepared by Netherland, Sewell & Associates, Inc., an independent petroleum engineer.

As of December 31, 2011, Dynamic had interests in approximately 295 net productive wells and over 217 offshore oil and gas leases in federal and state waters of the Gulf of Mexico, representing approximately 731,600 gross (423,500 net) acres. Dynamic’s properties are predominantly located in water depths of less than 300 feet. In addition, Dynamic owns a 49% interest in and operates the deepwater Bullwinkle field and associated platform, located in approximately 1,350 feet of water. Similar to Dynamic’s shallow water properties, the Bullwinkle field produces from a fixed-leg platform utilizing surface wellheads and blowout preventers and, consequently, is not subject to recent regulations instituted for deepwater drilling.

Pro forma financial information showing our results of operations and financial condition as of and for the year ended December 31, 2011 on a pro forma basis giving effect to the Dynamic acquisition is not yet available. We plan to file such unaudited pro forma financial information by mid-April. We expect that, on a pro forma basis, the Dynamic acquisition will be accretive to our cash flows from operations and that pro forma EBITDA for the year ended December 31, 2011 will approximate the combined amounts of our pro forma EBITDA and Dynamic’s pro forma EBITDAX for that period. In

 

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preparing such unaudited pro forma financial information, we will make a number of adjustments to Dynamic’s historical financial results to reflect the acquisition and its effects. These adjustments are expected to include, but not be limited to, the following:

 

   

The unaudited pro forma balance sheet will reflect adjustments to the historical book values of Dynamic’s assets and liabilities as of December 31, 2011 to their estimated fair values, in accordance with acquisition accounting. The fair value of Dynamic’s oil and natural gas properties will be estimated using a discounted cash flow model, with future cash flows estimated based upon oil and gas reserve quantities and forward strip oil and natural gas prices. Any difference between the value of consideration given and the fair market value of net assets acquired and liabilities assumed will be reflected as either goodwill (excess consideration given over fair value of net assets acquired and liabilities assumed) or a bargain purchase gain (excess fair value of net assets acquired and liabilities assumed over consideration given).

 

   

Liabilities assumed upon our acquisition of Dynamic will include asset retirement obligations associated with Dynamic’s oil and natural gas properties. Asset retirement obligations represent estimates of costs to plug, abandon and remediate oil and natural gas properties at the end of their productive lives, in accordance with applicable state laws. Retirement obligations associated with Dynamic’s properties are higher than those associated with our properties due to the offshore location of Dynamic’s operations.

 

   

Because we use the full cost method of accounting for costs related to oil and natural gas properties and Dynamic uses the successful efforts method of accounting, we will need to adjust various line items in Dynamic’s historical statement of operations to present such statements as if the full cost method of accounting had been used throughout the periods presented. As a result, we expect that certain operating costs of Dynamic that were charged to expense, such as unsuccessful exploration drilling costs, geological and geophysical costs, delay rental on leases, and abandonment costs, will not be deducted in the calculation of pro forma combined net income or loss.

 

   

The pro forma financial statements will reflect the issuance of additional long-term debt and the associated pro forma additional interest expense related to the application of proceeds to fund the cash portion of the Dynamic purchase price.

Pro forma financial information, including Dynamic’s pro forma EBITDAX for the year ended December 31, 2011, is necessarily illustrative only and does not purport to present what our results of operations and financial condition would have been had the Dynamic acquisition actually occurred on or before December 31, 2011.

 

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SUMMARY HISTORICAL CONSOLIDATED AND PRO FORMA FINANCIAL DATA

Summary Historical Consolidated and Pro Forma Condensed Financial Data — SandRidge

The following table presents our summary historical consolidated financial data and summary unaudited pro forma condensed statement of operations data for the periods shown. The summary historical consolidated financial data as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 has been derived from our audited consolidated financial statements for those dates and periods. The following summary historical financial data should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included in our 2011 Annual Report on Form 10-K, as amended. The summary unaudited pro forma condensed statement of operations data for the year ended December 31, 2011 have been derived from our unaudited pro forma condensed financial statements included in a Current Report on Form 8-K, which is being filed on the date hereof. The summary unaudited pro forma condensed statement of operations data does not give effect to the Dynamic acquisition. You should read the following summary unaudited pro forma statement of operations data in conjunction with the complete unaudited pro forma condensed financial statements and the related notes thereto.

The summary unaudited pro forma condensed statement of operations data reflects our historical results for the year ended December 31, 2011 adjusted on a pro forma basis to give effect to (i) our proposed conveyance of royalty interests in certain oil and natural gas properties located in northern Oklahoma and southern Kansas to the SandRidge Mississippian Trust II (the “Trust”) in connection with the Trust’s initial public offering, (ii) the sale of certain producing properties located in eastern Texas in November 2011 and (iii) our conveyance of royalty interests in certain oil and natural gas properties located in Andrews County, Texas to SandRidge Permian Trust in August 2011. The summary unaudited pro forma condensed financial information also adjusts our historical results to give effect to final adjustments recorded in 2011 with respect to our July 2010 acquisition of Arena Resources, Inc., as if they had occurred prior to 2011. We refer to the transactions giving rise to the pro forma adjustments collectively as the “SandRidge Transactions.” The summary unaudited pro forma condensed financial information does not include our receipt of the proceeds of the Trust’s public offering, which we will receive as consideration for the conveyance of royalty interests to the Trust.

The summary unaudited pro forma condensed statement of operations data have been presented for illustrative purposes only and do not purport to present what our results of operations and financial condition would have been had these transactions actually occurred on the relevant dates, nor do they project our results of operations for any future period or our financial condition at any future date. We therefore caution you not to place undue reliance on the following summary unaudited pro forma statement of operations data.

 

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     Pro Forma     Historical  
     Years Ended December 31,  
     2011     2011     2010     2009  
     (in thousands)  

Statement of Operations Data:(1)

        

Revenues

   $ 1,375,678      $ 1,415,213      $ 931,736      $ 591,044   

Expenses:

        

Production

     309,367        322,877        237,863        169,880   

Production taxes

     44,850        46,069        29,170        4,010   

Drilling and services

     65,654        65,654        22,368        28,380   

Midstream and marketing

     66,007        66,007        90,149        80,608   

Depreciation and depletion — oil and natural gas

     320,674        326,614        275,335        176,027   

Depreciation and amortization — other

     53,630        53,630        50,776        50,865   

Impairment

     2,825        2,825        —          1,707,150   

General and administrative

     150,143        148,643        179,565        100,256   

(Gain) loss on derivative contracts

     (44,075     (44,075     50,872        (147,527

(Gain) loss on sale of assets

     (2,044     (2,044     2,424        26,419   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     967,031        986,200        938,522        2,196,068   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     408,647        429,013        (6,786     (1,605,024
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

        

Interest income

     240        240        296        375   

Interest expense

     (234,440     (237,572     (247,738     (185,691

Loss on extinguishment of debt

     (38,232     (38,232     —          —     

Income from equity investments

     —          —          —          1,020   

Other income, net

     970        3,122        2,558        7,272   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

     (271,462     (272,442     (244,884     (177,024
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     137,185        156,571        (251,670     (1,782,048

Income tax expense (benefit)

     377        (5,817     (446,680     (8,716
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 136,808      $ 162,388      $ 195,010      $ (1,773,332

Less: net income attributable to noncontrolling interest

     95,336        54,323        4,445        2,258   
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 41,472      $ 108,065      $ 190,565      $ (1,775,590
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) SandRidge historical and pro forma information was prepared using the full cost method of accounting.

 

     As of December 31,  
     2011      2010  
     (in thousands)  

Balance Sheet Data (as of the end of the period):

     

Cash and cash equivalents

   $ 207,681       $ 5,863   

Property, plant and equipment, net

   $ 5,389,424       $ 4,733,865   

Total assets

   $ 6,219,609       $ 5,231,448   

Total debt

   $ 2,814,176       $ 2,909,086   

Total equity

   $ 2,548,950       $ 1,547,483   

Total liabilities and equity

   $ 6,219,609       $ 5,231,448   

 

     Years Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Cash Flow Data:

      

Net cash provided by operating activities

   $ 475,485      $ 390,128      $ 311,559   

Net cash used in investing activities

   $ (918,860   $ (962,753   $ (1,247,059

Net cash provided by financing activities

   $ 645,193      $ 570,627      $ 942,725   

Other Financial Data:

      

EBITDA(a)

   $ 726,310      $ 309,339      $ (1,371,277

Pro forma EBITDA(b)

   $ 656,839        n/a        n/a   

 

(a) EBITDA is a non-GAAP financial measure. We define EBITDA as net income (loss) before income tax expense (benefit), interest expense and depreciation, depletion and amortization.

 

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EBITDA is a supplemental financial measure used by our management and securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of our ability to internally fund exploration and development activities and to service or incur additional debt. EBITDA allows us to compare our operating performance and return on capital with those of other companies without regard to financing methods and capital structure. EBITDA should not be considered in isolation or as a substitute for net income, operating income or any other measure of financial performance prepared in accordance with generally accepted accounting principles. EBITDA excludes some, but not all, items that affect net income and operating income and we may define EBITDA differently than other companies. Therefore, our EBITDA may not be comparable to similarly titled measures used by other companies.

 

(b) Pro forma EBITDA adjusts 2011 historical EBITDA to give effect to the SandRidge Transactions. Pro forma EBITDA is calculated in the same manner as EBITDA, as described in note (a) to this table. Pro forma EBITDA is presented to reflect the SandRidge Transactions’ effect on our 2011 operating performance.

Reconciliation of Net Income (Loss) to EBITDA

 

     Pro  Forma(1)      Historical  
            Years Ended December 31,  
     2011      2011     2010     2009  
     (in thousands)  

Net income (loss)

   $ 41,472       $ 108,065      $ 190,565      $ (1,775,590

Adjusted for:

         

Income tax expense (benefit)

     377         (5,817     (446,680     (8,716

Interest expense(2)

     240,686         243,818        239,343        186,137   

Depreciation and amortization—other

     53,630         53,630        50,776        50,865   

Depreciation and depletion—oil and natural gas

     320,674         326,614        275,335        176,027   
  

 

 

    

 

 

   

 

 

   

 

 

 

EBITDA

   $ 656,839       $ 726,310      $ 309,339      $ (1,371,277
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) This column consists of a reconciliation of net income to EBITDA, with all amounts calculated on a pro forma basis to give effect to the SandRidge Transactions.

 

(2) Excludes unrealized (gain) loss on interest rate swaps of ($6.2) million, $8.4 million and ($0.4) million for the years ended December 31, 2011, 2010 and 2009, respectively.

 

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Summary Historical Consolidated and Pro Forma Condensed Financial Information — Dynamic

The following table presents Dynamic’s summary audited historical consolidated financial data for the periods shown, as well as summary unaudited pro forma condensed statement of operations data for the year ended December 31, 2011 showing the effects of Dynamic’s acquisition of the XTO Properties. The summary consolidated financial data as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 has been derived from Dynamic’s audited consolidated financial statements, which are attached hereto, for those dates and periods. The summary unaudited pro forma condensed statement of operations data for the year ended December 31, 2011 have been derived from Dynamic’s unaudited pro forma condensed statements of operations for such period, which are also attached hereto. You should read the following summary financial data in conjunction with Dynamic’s audited historical consolidated financial statements and related notes thereto and Dynamic’s unaudited pro forma condensed statements of operations and related notes thereto.

The summary unaudited pro forma condensed statement of operations data have been presented for illustrative purposes only and do not purport to present what Dynamic’s results of operations and financial condition would have been had these transactions actually occurred on the relevant dates, nor do they project our results of operations for any future period or our financial condition at any future date. We therefore caution you not to place undue reliance on the following summary unaudited pro forma condensed statement of operations data.

 

     Pro Forma     Historical  
           Years Ended December 31,  
     2011     2011     2010     2009  
     (in thousands)  

Statement of Operations Data:(1)

        

Revenues

   $ 616,420      $ 520,782      $ 358,627      $ 181,009   

Expenses:

        

Lease operating expense

     133,094        113,487        89,399        60,618   

Exploration expense

     15,085        15,085        2,100        8,999   

Depreciation, depletion and

amortization

     203,457        173,585        195,122        88,573   

General and administrative expense

     24,400        24,400        22,547        24,481   

Other operating expense

     84,124        77,505        73,047        51,142   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     460,160        404,062        382,215        233,813   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     156,260        116,720        (23,588     (52,804
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

        

Interest expense, net

     (13,007     (9,503     (13,541     (7,138

Commodity derivative income (expense)

     43,734        43,734        6,990        (21,887

Bargain purchase gain

     282        282        4,024        161,351   

Other

     (145     (145     (1,080     —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     187,124        151,088        (27,195     79,522   

Income tax benefit

     5,359        5,359        14,814        20,387   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 192,483      $ 156,447      $ (12,381   $ 99,909   

Less: net income (loss) attributable to noncontrolling interest

     460        460        (4,070     57,663   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to Dynamic Offshore Resources, LLC

   $ 192,023      $ 155,987      $ (8,311   $ 42,246   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Dynamic historical and pro forma information was prepared using the successful efforts method of accounting.

 

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     As of December 31,  
     2011      2010  
     (in thousands)  

Balance Sheet Data (as of the end of the period):

     

Cash and cash equivalents

   $ 58,696       $ 75,162   

Property and equipment, net

   $ 1,199,411       $ 864,645   

Total assets

   $ 1,463,769       $ 1,067,131   

Total debt

   $ 365,000       $ 203,205   

Total equity

   $ 519,087       $ 477,031   

Total liabilities and equity

   $ 1,463,769       $ 1,067,131   

 

     Years Ended December 31,  
     2011     2010     2009  
     (in thousands)  

Cash Flow Data:

      

Net cash provided by operating activities

   $ 277,142      $ 159,156      $ 38,912   

Net cash provided by (used in) investing activities

   $ (337,454   $ (94,605   $ 62,075   

Net cash provided by (used in) financing activities

   $ 43,846      $ (77,846   $ (64,705

Other Financial Data:

      

EBITDAX(a)

   $ 361,335        200,821        133,780   

Pro forma EBITDAX(b)

   $ 433,241        n/a        n/a   

 

(a) EBITDAX is a non-GAAP financial measure used by Dynamic that most closely corresponds to our definition of EBITDA. Dynamic’s EBITDAX is calculated as net income (loss) before income tax (benefit), interest expense, exploration expense, depreciation, depletion and amortization and accretion of asset retirement obligation.

 

(b) Pro forma EBITDAX gives effect to Dynamic’s acquisition of the XTO Properties as though such acquisition occurred on December 31, 2010.

Reconciliation of Net Income (Loss) to EBITDAX

 

     Pro  Forma(1)     Historical  
           Years Ended December 31,  
     2011     2011     2010     2009  
     (in thousands)  

Net income (loss)

   $ 192,023      $ 155,987      $ (8,311   $ 42,246   

Adjusted for:

        

Income tax benefit

     (5,359     (5,359     (14,814     (20,387

Interest expense, net

     13,007        9,503        13,541        7,138   

Exploration expense

     15,085        15,085        2,100        8,999   

Depreciation, depletion and amortization

     203,457        173,585        195,122        88,573   

Accretion of asset retirement obligation

     15,028        12,534        13,183        7,211   
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDAX

   $ 433,241      $ 361,335      $ 200,281      $ 133,780   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) This column consists of a reconciliation of net income to EBITDAX, with all amounts calculated on a pro forma basis to give effect to Dynamic’s 2011 purchase of the XTO Properties.

 

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Summary SandRidge and Dynamic Oil and Natural Gas Reserve and Production Data

The following table sets forth summary unaudited information with respect to our and Dynamic’s estimated oil and natural gas reserves as of December 31, 2011. The SandRidge historical oil and natural gas reserve data presented below have been derived from our 2011 Annual Report on Form 10-K, as amended, and the Dynamic historical oil and natural gas reserve data are based on a reserve report prepared by Netherland, Sewell & Associates, Inc., which is dated as of December 31, 2011.

For convenience, we also present the mathematical combination of our and Dynamic’s estimated oil and natural gas reserves. This combined number does not purport to represent what our estimated oil and natural gas reserves would have been if the Dynamic acquisition had occurred on or before December 31, 2011, in part because our reserve estimation processes and assumptions may differ from those used by Dynamic. Future exploration, exploitation and development expenditures, as well as future commodity prices and service costs, will affect the reserve volumes attributable to the Dynamic acquired properties. The reserves estimates shown below were determined using a 12-month average price for oil and natural gas for the year ended December 31, 2011.

 

     Estimated Proved Reserves
as of December 31, 2011
        
     SandRidge
Historical
     Dynamic
Historical
     Combined  

Estimated Proved Reserves:

        

Oil (MMBbls)

     244.8         32.1         276.9   

Natural gas (Bcf)

     1,355.1         182.3         1,537.4   

Total (MMBoe)

     470.6         62.5         533.1   

Estimated Proved Developed Reserves:

        

Oil (MMBbls)

     118.7         26.1         144.8   

Natural Gas (Bcf)

     670.4         146.9         817.3   

Total (MMBoe)

     230.4         50.6         281.0   

Estimated Proved Undeveloped Reserves:

        

Oil (MMBbls)

     126.1         6.0         132.1   

Natural Gas (Bcf)

     684.7         35.4         720.1   

Total (MMBoe)

     240.2         11.9         252.1   

 

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For illustrative purposes only, the following table sets forth summary unaudited pro forma information with respect to our and Dynamic’s oil and natural gas production for the year ended December 31, 2011. This pro forma information differs from our and Dynamic’s actual production and does not purport to represent what such production would have been if the transactions described in the notes to the table had occurred on or before December 31, 2010. For convenience, we also present the mathematical combination of our and Dynamic’s pro forma oil and natural gas production. This combined number does not purport to represent what our oil and natural gas production would have been if the Dynamic acquisition had occurred on or before January 1, 2011.

 

     Production for the Year Ended
December 31, 2011
       
     SandRidge
Pro  Forma(1)
    Dynamic
Pro  Forma(2)
    Combined(3)  

Oil (MBbls)

     11,670 (4)      4,340        16,010   

Natural Gas (MMcf)

     61,820        28,109 (4)      89,929   

Total (MBoe)

     21,973        9,025        30,998   

Average daily total volumes (MBoe/d)

     60.2        24.7        84.9   

 

(1) The pro forma SandRidge production data provided in this column gives effect to our November 2011 sale of certain natural gas assets in four counties in east Texas as if such disposition had occurred on December 31, 2010.

 

(2) The pro forma Dynamic production data provided in this column includes production from the XTO Properties as if Dynamic had acquired the XTO Properties on December 31, 2010.

 

(3) The combined production data provided in this column gives effect to the pro forma adjustments to our and Dynamic’s 2011 production data that are referenced in footnotes 1 and 2 to this table.

 

(4) Includes natural gas liquids.

Caution Concerning Forward-Looking Statements

This Current Report on Form 8-K 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. 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 statements relating to when the Company expects to close the proposed transaction. These forward-looking statements are based on the Company’s current expectations and assumptions and analyses made in light of the Company’s experience and its perception of historical trends, current conditions and expected future developments, as well as other factors the Company believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Company’s expectations and predictions is subject to a number of risks and uncertainties, including the availability and terms of capital, and other factors, many of which are beyond the Company’s control. Please see the discussion of risk factors in the our Annual Report on Form 10-K, as amended, for the year ended December 31, 2011 filed with the SEC. All of the forward-looking statements made in this Current Report on Form 8-K are qualified by these cautionary statements. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. The Company undertakes no obligation to update or revise any forward-looking statements.

 

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Table of Contents

INDEX TO FINANCIAL STATEMENTS

 

DYNAMIC OFFSHORE RESOURCES, LLC

  

Report of Independent Registered Public Accounting Firm

     F-1  

Consolidated Balance Sheets as of December 31, 2011 and 2010

     F-2  

Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009

     F-3  

Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009

     F-4   

Consolidated Statements of Owner’s Equity for the Years Ended December 31, 2011, 2010 and 2009

     F-5   

Notes to Consolidated Financial Statements

     F-6  

UNAUDITED PRO FORMA FINANCIAL INFORMATION—DYNAMIC OFFSHORE RESOURCES, LLC

  

Unaudited Pro Forma Condensed Statement of Operations for the Year Ended December 31, 2011

     F-33  

Notes to Unaudited Pro Forma Condensed Financial Statements

     F-34  

XTO PROPERTIES

  

Report of Independent Registered Public Accounting Firm

     F-35   

Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2010 and 2009

     F-36  

Notes to Statements of Revenues and Direct Operating Expenses

     F-37  


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of

Dynamic Offshore Resources, LLC

We have audited the accompanying consolidated balance sheets of Dynamic Offshore Resources, LLC (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows and owners’ equity for the years ended December 31, 2011, 2010 and 2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Dynamic Offshore Resources, LLC as of December 31, 2011 and 2010 and the results of their consolidated operations and their consolidated cash flows for the years ended December 31, 2011, 2010 and 2009, in conformity with accounting principles generally accepted in the United States of America.

Hein & Associates LLP

Houston, Texas

March 29, 2012

 

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Table of Contents

DYNAMIC OFFSHORE RESOURCES, LLC

CONSOLIDATED BALANCE SHEETS

(In thousands)

     December 31,  
     2011     2010  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 58,696      $ 75,162   

Accounts receivable—third parties

     92,635        57,796   

Accounts receivable—affiliates

     4        6   

Insurance receivable

     —          933   

Derivative assets

     44,471        11,990   

Current portion of notes receivable—abandonments

     3,843        4,922   

Other current assets

     21,834        15,789   
  

 

 

   

 

 

 

Total current assets

     221,483        166,598   
  

 

 

   

 

 

 

Property and equipment:

    

Oil and gas properties, successful efforts method

     1,728,289        1,220,407   

Other property and equipment

     4,073        3,223   

Accumulated depreciation, depletion and amortization

     (532,951     (358,985
  

 

 

   

 

 

 

Property and equipment, net

     1,199,411        864,645   

Long-term derivative assets

     9,953        4,919   

Notes receivable—abandonments

     17,108        15,274   

Other assets

     15,814        15,695   
  

 

 

   

 

 

 

Total assets

   $ 1,463,769      $ 1,067,131   
  

 

 

   

 

 

 

Liabilities and Owners’ Equity

    

Current liabilities:

    

Accounts payable—third parties

   $ 65,488      $ 26,846   

Accounts payable—affiliates

     601        50   

Current portion of asset retirement obligations

     51,133        71,225   

Other current liabilities

     83,952        56,780   
  

 

 

   

 

 

 

Total current liabilities

     201,174        154,901   
  

 

 

   

 

 

 

Long-term debt

     365,000        203,205   

Asset retirement obligations

     326,483        161,845   

Deferred income taxes

     43,481        49,561   

Other long-term liabilities

     8,544        20,588   
  

 

 

   

 

 

 

Total liabilities

     944,682        590,100   
  

 

 

   

 

 

 

Commitments and contingencies (see Note 17)

    

Owners’ equity:

    

Member’s capital

     519,087        381,383   

Noncontrolling interests in subsidiaries

     —          95,648   
  

 

 

   

 

 

 

Total owners’ equity

     519,087        477,031   
  

 

 

   

 

 

 

Total liabilities and owners’ equity

   $ 1,463,769      $ 1,067,131   
  

 

 

   

 

 

 

See notes to consolidated financial statements

 

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DYNAMIC OFFSHORE RESOURCES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

 

     Year Ended December 31,  
     2011     2010     2009  

Oil and gas revenues

   $ 504,286      $ 345,812      $ 178,992   

Other operating revenues

     16,496        12,815        2,017   
  

 

 

   

 

 

   

 

 

 
     520,782        358,627        181,009   
  

 

 

   

 

 

   

 

 

 

Operating expenses:

      

Lease operating expense

     113,487        89,399        60,618   

Exploration expense

     15,085        2,100        8,999   

Depreciation, depletion and amortization

     173,585        195,122        88,573   

General and administrative expense

     24,400        22,547        24,481   

Other operating expense

     77,505        73,047        51,142   
  

 

 

   

 

 

   

 

 

 
     404,062        382,215        233,813   
  

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     116,720        (23,588     (52,804

Other income (expense):

      

Interest expense, net

     (9,503     (13,541     (7,138

Commodity derivative income (expense)

     43,734        6,990        (21,887

Bargain purchase gain

     282        4,024        161,351   

Other

     (145     (1,080     —     
  

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     151,088        (27,195     79,522   

Income tax benefit

     5,359        14,814        20,387   
  

 

 

   

 

 

   

 

 

 

Net income (loss)

     156,447        (12,381     99,909   

Less: Net income (loss) attributable to noncontrolling interests

     460        (4,070     57,663   
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to Dynamic Offshore Resources, LLC

   $ 155,987      $ (8,311   $ 42,246   
  

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements

 

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DYNAMIC OFFSHORE RESOURCES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

     Year Ended December 31,  
     2011     2010     2009  

Cash flows from operating activities:

      

Net income (loss)

   $ 156,447      $ (12,381   $ 99,909   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Amortization in interest expense, net

     1,292        287        (219

Accretion of asset retirement obligations

     12,534        13,183        7,211   

Depreciation, depletion and amortization

     173,585        195,122        88,573   

Commodity derivative (income) expense

     (43,734     (6,990     21,887   

Deferred income tax benefit

     (5,359     (14,814     (18,199

Bargain purchase gain

     (282     (4,024     (161,351

Other

     —          71        —     

(Gain) loss on sale of assets

     (19     8,139        (140

Changes in operating assets and liabilities, net of acquisitions:

      

Accounts receivable and other assets

     (25,308     51,716        18,172   

Accounts payable and other liabilities

     7,986        (71,153     (16,931
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     277,142        159,156        38,912   
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Additions to property and equipment

     (98,681     (57,726     (42,154

Acquisitions, net of cash acquired

     (232,906     (92,442     26,072   

Derivative settlements

     (5,867     43,171        76,088   

Proceeds from asset sales

     —          12,392        2,069   
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) investing activities

     (337,454     (94,605     62,075   
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

      

Borrowings from revolving credit facility

     390,000        —          —     

Repayments of revolving credit facility

     (170,000     (39,795     (5,000

Repayment of second lien term loan

     (58,205     —          (46,223

Payments on insurance note payable

     —          —          (1,111

Contributions from member

     524        28,000        21,808   

Distributions to member

     (40,075     (53,076     (34,664

Distribution for net assets transferred under common control

     (68,000     —          —     

Net contributions from (distributions to) noncontrolling interest

     —          (11,375     2,844   

Acquisition of noncontrolling interest in DBH, LLC

     (6,840     (1,600     (2,160

Debt issuance costs

     (3,558     —          (199
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     43,846        (77,846     (64,705
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (16,466     (13,295     36,282   

Cash and cash equivalents, beginning of period

     75,162        88,457        52,175   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 58,696      $ 75,162      $ 88,457   
  

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements

 

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DYNAMIC OFFSHORE RESOURCES, LLC

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY

(In thousands)

 

000000000 000000000 000000000 000000000 000000000
      Dynamic Offshore
Resources, LLC
    Net  Parent
Investment
    Total     Noncontrolling
Interests
    Total  

Balance, December 31, 2008

   $ 331,131      $ 44,226      $ 375,357      $ 59,073      $ 434,430   

Contributions

     21,835        —          21,835        15,886        37,721   

Distributions

     (34,664     —          (34,664     (9,933     (44,597

Acquisition of noncontrolling interest in DBH, LLC

     6,544        —          6,544        (6,544     —     

Net income (loss)

     42,403        (157     42,246        57,663        99,909   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2009

     367,249        44,069        411,318        116,145        527,463   

Contributions

     28,000        —          28,000        —          28,000   

Distributions

     (50,639     (2,437     (53,076     (11,375     (64,451

Acquisition of noncontrolling interest in DBH, LLC

     3,452        —          3,452        (5,052     (1,600

Net income (loss)

     (10,496     2,185        (8,311     (4,070     (12,381
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2010

     337,566        43,817        381,383        95,648        477,031   

Contributions

     524        —          524        —          524   

Distributions

     (32,378     (7,697     (40,075     —          (40,075

Acquisition of noncontrolling interests in subsidiaries

     89,268        —          89,268        (96,108     (6,840

Book value of net assets transferred under common control

     42,518        (42,518     —          —          —     

Distribution for net assets transferred under common control

     (68,000     —          (68,000     —          (68,000

Net income

     149,589        6,398        155,987        460        156,447   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2011

   $ 519,087      $ —        $ 519,087      $ —        $ 519,087   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See notes to consolidated financial statements

 

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Dynamic Offshore Resources, LLC

Notes to Consolidated Financial Statements

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Note 1—Organization and Basis of Presentation

Dynamic Offshore Resources, LLC (“DOR”) is a Delaware limited liability company wholly owned by Dynamic Offshore Holding, LP (“DOH”), a Delaware limited partnership. DOR was organized on September 17, 2007 for the purpose of acquiring and developing oil and gas properties. As a limited liability company, DOR is solely responsible for the debts, obligations and liabilities of the Company and no member or manager of the Company is obligated personally for any such debt, obligation or liability of the Company. Unless the context requires otherwise, references to “we”, “us”, “our”, or “the Company” are intended to mean the consolidated business and operations of DOR.

Basis of Presentation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

In September 2011, we acquired certain oil and natural gas properties in the Gulf of Mexico from a subsidiary of Moreno Group Holdings, LLC (“MOR”) for $68.0 million. Because the Company and MOR are under the common control of Riverstone Holdings, LLC (“Riverstone”), the acquisition was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at MOR’s carrying value and the Company’s historical financial information was recast to include the acquired properties for all periods in which the Company and MOR were under the common control of Riverstone. Accordingly, the consolidated financial statements and notes thereto reflect the historical results of the Company combined with those of the acquired properties.

The effect of recasting the Company’s consolidated financial statements to account for this common control transaction is shown below:

 

      December 31, 2010  
     Historical      MOR      Recast  

Current assets

   $ 163,209       $ 3,389       $ 166,598   

Property and equipment

     809,035         55,610         864,645   

Other assets

     35,870         18         35,888   
  

 

 

    

 

 

    

 

 

 

Total assets

   $ 1,008,114       $ 59,017       $ 1,067,131   
  

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 153,828       $ 1,073       $ 154,901   

Long-term liabilities

     421,072         14,127         435,199   

Owners’ equity

     433,214         43,817         477,031   
  

 

 

    

 

 

    

 

 

 

Total liabilities and owners’ equity

   $ 1,008,114       $ 59,017       $ 1,067,131   
  

 

 

    

 

 

    

 

 

 

 

      Year Ended December 31, 2010     Year Ended December 31, 2009  
     Historical     MOR     Recast     Historical     MOR     Recast  

Operating revenues

   $ 330,136      $ 28,491      $ 358,627      $ 157,153      $ 23,856      $ 181,009   

Operating expenses

     (355,909     (26,306     (382,215     (209,800     (24,013     (233,813
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (14,566   $ 2,185      $ (12,381   $ 100,066      $ (157   $ 99,909   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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On October 13, 2009 (the “acquisition date”), DBH, LLC (“DBH”) acquired Bandon Oil and Gas, LP and Bandon Oil and Gas GP, LLC (“Bandon LP” and “Bandon GP”; collectively, “Bandon”). DBH accounted for its acquisition of Bandon using the acquisition method, under which 100% of Bandon’s assets and liabilities were recorded at fair value as of the acquisition date. During the measurement period, which ended October 12, 2010, DBH finalized the acquisition date valuation of certain assets and liabilities related to the acquisition. As a result, the bargain purchase gain increased $0.5 million. See Note 4 and Note 5. The consolidated balance sheet at December 31, 2009 and the consolidated statement of operations for the year ended December 31, 2009 have been retrospectively adjusted to reflect these adjustments as required by the business combinations accounting guidance.

Certain other reclassifications have been made to the prior year financial statements to conform to the current year presentation. These other reclassifications had no affect on total net assets, owners’ equity or net income.

In preparing the accompanying consolidated financial statements, the Company has reviewed, as determined necessary by the Company’s management, events that have occurred after December 31, 2011, up until the issuance of the consolidated financial statements, which occurred on March 29, 2012. See Note 18.

Note 2—Significant Accounting Policies and Related Matters

Asset Retirement Obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operations. The Company’s AROs are based on the estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties. An ARO is initially measured at its estimated fair value. Upon initial recognition, the Company records an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The cost of the long-lived asset (including the ARO-related increase) is depreciated using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, AROs will be extinguished by the Company at either the recorded amount or the Company will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. The Company considers cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. As of December 31, 2011, accounts payable included $2.1 million of outstanding checks that were reclassified from cash and cash equivalents. There was no reclassification necessary as of December 31, 2010.

Concentration of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trade accounts receivable and commodity derivative instruments.

The Company extends credit, primarily in the form of uoncollateralized oil and gas sales and joint interest owners’ receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within the Company’s industry and may accordingly impact its overall credit risk. The Company believes that the risk of these unsecured receivables is mitigated by the size, reputation and nature of the companies to which the Company extends credit.

 

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The following table lists the percentage of the Company’s consolidated oil and gas revenues with purchasers that accounted for more than 10% of the Company’s consolidated oil and gas revenues for the periods indicated:

 

     Year Ended December 31,  
     2011     2010     2009  

Shell Trading (US) Company

     51     45     23

Conoco Phillips Corporation

     22     13     28

Texon LP

     4     14     20

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts, based on the specific identification method. In evaluating the collectability of accounts receivable, the Company makes judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required. The Company did not have an allowance for doubtful accounts as of December 31, 2011 and 2010.

The Company uses commodity derivative instruments to mitigate the effects of commodity price fluctuations. These derivative instruments expose the Company to counterparty credit risk. The Company’s counterparties are generally major banks or financial institutions. All derivative instruments are executed under master agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. The Company monitors the creditworthiness of its counterparties. However, the Company is not able to predict sudden changes in its counterparties’ creditworthiness. Should a financial counterparty not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices as well as incur a loss.

As of December 31, 2011, Citibank, Credit Suisse, Deutsche Bank, and an affiliate of The Royal Bank of Scotland (“RBS”) accounted for 38%, 34%, 14% and 14% of the Company’s counterparty credit exposure related to commodity derivative instruments. These counterparties are major financial institutions possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.

Consolidation Policy. The Company’s consolidated financial statements include the accounts of the Company and those subsidiaries in which the Company has a controlling interest, after the elimination of all material intercompany accounts and transactions. Third-party or affiliate ownership interests in the Company’s controlled subsidiaries are presented as noncontrolling interests.

Contingencies. Certain conditions may exist as of the date the Company’s consolidated financial statements are issued, which may result in a loss to the Company but which will only be resolved when one or more future events occur or fail to occur. The Company’s management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment.

In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.

 

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Table of Contents

Liabilities for environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and charged to interest expense over the term of the related debt.

Income Taxes. The Company’s provision for income taxes is solely applicable to federal tax obligations of Dynamic Offshore Resources NS Parent, Inc. (“DOR NS”), a wholly-owned subsidiary of the Company. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of DOR NS for financial reporting and tax purposes. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax assets will not be realized. The profits and losses of the Company’s consolidated operations other than within DOR NS are reported directly to the taxing authorities by the sole member of the Company. Accordingly, no provision for income taxes has been included for those profits and losses in the accompanying consolidated financial statements, except as they relate to DOR NS.

The Company must recognize the tax effects of any uncertain tax positions it may adopt, if the position taken by it is more-likely-than-not sustainable. If a tax position meets such criteria, the tax effect to be recognized by the Company would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. See Note 12 for additional information regarding income taxes.

Natural Gas Imbalances. Quantities of natural gas over-delivered or under-delivered are recorded monthly as receivables and payables using weighted average prices as of the time the imbalance was created. Imbalances not governed by operational balancing agreements are subject to annual adjustment to the lower of cost or market. Certain contracts require cash settlement of imbalances on a current basis. Under these contracts, imbalance cash-outs are recorded in the consolidated statements of operations as a sale or purchase of natural gas, as appropriate.

Derivative Instruments (Hedging). All derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value. The Company does not designate its commodity derivative instruments as cash-flow hedges. Changes in the fair value of the Company’s commodity derivative instruments are recorded in earnings as they occur and are included in other income (expense) in the Company’s consolidated statements of operations.

Property and Equipment. The Company uses the successful efforts method to account for its oil and gas exploration and production activities. All costs for development wells, related plant and equipment, proved mineral interests in oil and gas properties, and related ARO costs are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells find proved reserves. Costs of wells that are assigned proved reserves remain capitalized. Costs also are capitalized for exploratory wells that have found oil and gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the exploratory well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress toward assessing the reserves and the economic and operating viability of the project. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease-by-lease basis if unsuccessful or the lease term has expired. All other exploratory wells and costs are expensed. Oil and gas property costs associated with

 

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unproved oil and gas reserves, arising from business combinations, are assessed for transfer to proved properties based on the change in estimated field-by-field unproved reserve volumes from the acquisition closing date, beginning with the second fiscal year-end subsequent to the acquisition closing date.

Capitalized costs of producing oil and gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved oil and gas reserves on a field-by-field basis. Upon sale or retirement, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss is recognized.

Long-lived assets to be held and used, including proved and unproved oil and gas properties, are assessed for possible impairment by comparing their carrying values with their associated undiscounted, risk-weighted estimated future net cash flows. Events that can trigger assessments for possible impairments include write-downs of proved and unproved reserves based on field performance, significant decreases in the market value of an asset, significant changes in the extent or manner of use or a physical change in an asset, significant changes in the relationship between an asset’s capitalized cost and the associated oil and gas reserves, and a more-likely-than-not expectation that a long-lived asset will be sold or otherwise disposed of significantly sooner than the end of its previously estimated useful life. Impaired assets are written down to their estimated fair values, generally their estimated discounted future net cash flows as adjusted by additional risk-weighting factors. For proved and unproved oil and gas properties, the Company performs the impairment review on an individual field basis. Impairment amounts are recorded as incremental depreciation, depletion and amortization expense. The Company recorded property impairment charges in 2011, 2010 and 2009 as described in Note 6. It is reasonably possible that other proved and unproved oil and gas properties could become impaired in the future if commodity prices decline.

In determining the fair values of proved and unproved properties acquired in business combinations, the Company prepares estimates of oil and gas reserves. The Company estimates future prices to apply to the estimated reserve quantities acquired, and estimates future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved, probable and possible reserves, the estimated future net cash flows are discounted using a market-based weighted average cost of capital rate deemed appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing reserves, the discounted future net cash flows of proved, probable and possible reserves are reduced by additional risk-weighting factors.

Other property and equipment, consisting primarily of office furniture, equipment, leasehold improvements, computers and computer software, is stated at cost. Depreciation on other property and equipment is calculated on the straight-line method over the estimated useful lives of the assets, which range from three to seven years.

Revenue Recognition. The Company records revenues from the sales of crude oil, natural gas and natural gas liquids when product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured.

When the Company has an interest with other producers in properties from which natural gas is produced, the Company uses the entitlement method to account for any imbalances. Imbalances occur when the Company sells more or less product than the Company is entitled to under its ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that the Company sells in excess of its entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount the Company sells is recognized as revenue and a receivable is accrued.

Segment Information. The Company acquires, exploits, develops, explores for and produces oil and gas. All of the Company’s operations are located in the United States. The Company’s management team administers all properties as a whole rather than as discrete operating segments. The Company tracks basic operational data by

 

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area. However, the Company measures financial performance as a single enterprise and not on an area-by-area basis. The Company allocates capital resources on a project-by-project basis across its entire asset base to maximize profitability without regard to individual areas or segments.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available.

Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating oil and gas reserves, (2) estimating uncollected revenues, unbilled operating and general and administrative costs, capital expenditures and abandonment costs, (3) developing fair value assumptions, including estimates of future cash flows and discount rates, (4) analyzing long-lived assets for possible impairment, (5) estimating the useful lives of assets and (6) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from estimated amounts.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance requiring entities to disclose both gross and net information about financial instruments and transactions eligible for offset in the statement of financial position as well as financial instruments and transactions subject to agreements similar to master netting arrangements. The additional disclosures will enable users of the financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning after January 1, 2013, and will primarily impact our disclosures associated with our commodity derivative instruments. We are currently evaluating the impact of this guidance.

In May 2011, FASB issued authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies (i) the requirement that the highest and best use concept is only relevant for measuring nonfinancial assets, (ii) requirements to measure the fair value of instruments classified in shareholders’ equity and (iii) the requirement to disclose quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy. The guidance also (i) permits a reporting entity to measure the fair value of certain financial assets and liabilities managed in a portfolio at the price that would be received to sell a net asset position or transfer a net liability position for a particular risk, (ii) eliminates premiums or discounts related to size as a characteristic of the reporting entity’s holding and (iii) expands disclosures for fair value measurement. The guidance is effective for interim and annual periods beginning after December 15, 2011. We are currently evaluating the impact of this guidance, but do not expect it to have a material impact on the Company’s financial position or results of operations.

In December 2010, FASB issued authoritative guidance clarifying the acquisition date that should be used for reporting the pro forma financial information disclosures when comparative financial statements are presented. The guidance also improves the usefulness of the pro forma revenue and earnings disclosures by requiring a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. We adopted the provisions of this standard effective January 1, 2011, and it did not have a significant impact on our consolidated financial position, results of operations or cash flows.

 

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Note 3—Consolidated Financial Statements Information

The following table shows additional consolidated balance sheets information at the dates indicated:

 

      December 31,  
     2011      2010  

Accounts receivable from third parties

     

Operating revenues

   $ 70,231       $ 40,749   

Joint interest receivables

     13,565         13,908   

Derivative assets

     2,590         195   

Other

     6,249         2,944   
  

 

 

    

 

 

 
   $ 92,635       $ 57,796   
  

 

 

    

 

 

 

Other current assets

     

Prepaid insurance

   $ 5,067       $ 5,982   

Prepaid royalties

     10,782         5,871   

Advances to operators

     1,543         644   

Deferred income taxes

     2,571         3,292   

Other

     1,871         —     
  

 

 

    

 

 

 
   $ 21,834       $ 15,789   
  

 

 

    

 

 

 

Other assets

     

Natural gas imbalances receivable (1)

   $ 10,768       $ 12,916   

Debt issue costs, net

     3,546         1,279   

Restricted cash

     1,500         1,500   
  

 

 

    

 

 

 
   $ 15,814       $ 15,695   
  

 

 

    

 

 

 

Other current liabilities

     

Accrued expenses

   $ 69,702       $ 37,372   

Derivative liabilities

     14,250         17,176   

Other

     —           2,232   
  

 

 

    

 

 

 
   $ 83,952       $ 56,780   
  

 

 

    

 

 

 

Other long-term liabilities

     

Natural gas imbalances payable (1)

   $ 5,919       $ 11,117   

Long-term derivative liabilities

     2,625         9,254   

Other

     —           217   
  

 

 

    

 

 

 
   $ 8,544       $ 20,588   
  

 

 

    

 

 

 

 

(1) As of December 31, 2011 and 2010, natural gas imbalances receivable were 3,068 MMcf and 3,946 MMcf. Natural gas imbalances payable were 1,282 MMcf and 3,516 MMcf as of the same dates.

 

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Other operating expense comprised the following for the periods indicated:

 

      Year Ended December 31,  
     2011     2010     2009  

Other operating expense

      

Insurance expense

   $ 36,078      $ 36,677      $ 32,688   

Workover expense

     20,701        15,827        6,696   

Accretion expense

     12,534        13,183        7,211   

Casualty loss (gain), net (See Note 15)

     (164     (3,380     —     

Loss on abandonments

     10,231        2,601        4,687   

Loss (gain) on sale of assets

     (19     8,139        (140

Other

     (1,856     —          —     
  

 

 

   

 

 

   

 

 

 
   $ 77,505      $ 73,047      $ 51,142   
  

 

 

   

 

 

   

 

 

 

Note 4—Noncontrolling Interest in Subsidiaries

DBH, LLC

DBH is a Delaware limited liability company that was formed on September 24, 2009 to acquire and own Bandon. As of December 31, 2009, the Company owned a 66.1% controlling interest in DBH.

In December 2010 DOR repurchased a 2.4% member interest for $1.6 million. The Company’s capital accounts were adjusted for the $3.5 million difference between the settlement price paid to the withdrawing member and the book value of the withdrawing member’s share of total members’ capital at the time of the withdrawal. This amount is reflected in the consolidated statements of owners’ equity.

During 2011 DOR repurchased the remaining member interests in DBH from various members for $6.8 million. The Company’s capital accounts were adjusted for the $5.1 million difference between the settlement price paid to the withdrawing members and the book value of the withdrawing members’ share of total members’ capital at the time of the withdrawal. Beginning June 1, 2011, the Company owned a 100% controlling interest in DBH.

SPN Resources, LLC (“SPN”)

On March 10, 2011, the Company acquired a Superior affiliate’s membership interests in SPN and DBH. Consideration for the acquisition was a 10% ownership interest in the DOH and a modification of SPN’s turnkey platform abandonment contract with Superior as described in Note 7. As a result of this transaction, the Company owns a 100% interest in SPN.

Note 5—Acquisitions

XTO Acquisition

On August 31, 2011, we acquired certain oil and natural gas interests in the Gulf of Mexico from XTO Offshore Inc. and other related subsidiaries of ExxonMobil Corporation (“Exxon”), for $173.7 million (the “XTO Acquisition”). This acquisition further strengthens our Gulf of Mexico shelf presence. The purchase price allocation was preliminary as of December 31, 2011. Acquisition-related expenses of $0.4 million are included in general and administrative expense in the accompanying consolidated statements of operations.

 

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Consideration paid

  

Cash

   $ 173,732   
  

 

 

 
   $ 173,732   
  

 

 

 

Assets acquired:

  

Other current assets

   $ 10,737   

Property and equipment

     246,508   
  

 

 

 

Total assets acquired

     257,245   
  

 

 

 

Liabilities assumed:

  

Other current liabilities

     7,903   

AROs, noncurrent portion

     75,610   
  

 

 

 

Total liabilities assumed

     83,513   
  

 

 

 

Net assets acquired

   $ 173,732   
  

 

 

 

Actual and Pro Forma Impact of 2011 Acquisition (Unaudited). Revenues and direct operating expenses attributable to the XTO acquisition included in the Company’s consolidated statement of operations for the year ended December 31, 2011 were $47.1 million and $6.9 million.

The following table presents pro forma information for the Company as if the XTO acquisition occurred on January 1, 2010:

 

      Year Ended
December 31,
 
     2011      2010  

Revenues

   $ 616,420       $ 512,994   

Income from operations

     156,260         28,833   

Net income

     192,483         34,756   

Less: Net income attributable to noncontrolling interests

     460         (4,070

Net income attributable to Dynamic Offshore Resources, LLC

     192,023         38,826   

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisitions and factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would have been had the acquisitions been completed on January 1, 2010. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma results reflect the direct operating expenses of the properties acquired, interest expense on acquisition-related indebtedness and an adjustment to recognize incremental depreciation, depletion and amortization expense, using the unit-of-production method, resulting from the purchase of the properties.

MOR Acquisition

On September 14, 2011, we acquired certain oil and natural gas properties in the Gulf of Mexico from a subsidiary of Moreno Group Holdings, LLC (“MOR”) for $68.0 million. Because the Company and MOR are under the common control of Riverstone Holdings, LLC (“Riverstone”), the acquisitions were accounted for as transactions between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of the acquired properties were recorded at MOR’s carrying value and the Company’s historical financial information was recast to include the acquired properties for all periods in which the Company and

 

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MOR were under the common control of Riverstone. Accordingly, the consolidated financial statements and notes thereto, including the historical financial statements and notes thereto, reflect the results of the Company combined with those of the acquired properties.

2010 Acquisitions

Bullwinkle Acquisition. On February 1, 2010, DOR and a wholly-owned subsidiary of Superior acquired the deepwater Gulf of Mexico Bullwinkle field and related infrastructure. DOR is now the operator and 49% owner of the field with Superior retaining the remaining interest. DOR is required to fund its share of the assumed asset retirement obligations, which has been capped at $49 million, by no later than January 31, 2013. The $49 million is payable in the following increments: (i) $1.8 million upon the permanent abandonment of each existing wellbore, (ii) sixteen monthly payments of $1.5 million, beginning on the last business day of February 2010, (iii) $1.0 million on the last business day of June 2011, and (iv) any remainder on January 31, 2013. In addition to the revenue generated from oil and gas production, the platform also generates revenue from several production handling arrangements for other third-party fields. Acquisition-related expenses of $0.1 million are included in general and administrative expense in the accompanying consolidated statements of operations.

Samson Acquisition. On July 8, 2010, DOR purchased substantially all of the oil and gas properties of Samson Offshore Company and Samson Contour Energy E&P, LLC (collectively, “Samson”) located in the Gulf of Mexico for $97.7 million. Acquisition-related expenses of $0.1 million are included in general and administrative expense in the accompanying consolidated statements of operations. The acquisition broadens the Company’s leasehold footprint in the Gulf of Mexico.

 

      Year Ended December 31, 2010  
     Bullwinkle      Samson      Other (1)      Total  

Consideration paid

           

Cash

   $ —         $ 97,693       $ 3,664       $ 101,357   
  

 

 

    

 

 

    

 

 

    

 

 

 
   $ —         $ 97,693       $ 3,664       $ 101,357   
  

 

 

    

 

 

    

 

 

    

 

 

 

Assets acquired:

           

Cash

   $ 3,498       $ —         $ 5,417       $ 8,915   

Hurricane insurance claims

     —           1,775         —           1,775   

Property and equipment

     43,761         109,567         4,107         157,435   

Other noncurrent assets

     148         —           17         165   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets acquired

     47,407         111,342         9,541         168,290   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities assumed:

           

AROs, current portion

     34,079         —           1,410         35,489   

Other current liabilities

     —           70         —           70   

AROs, noncurrent portion

     13,328         13,579         443         27,350   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities assumed

     47,407         13,649         1,853         62,909   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net assets acquired

   $ —         $ 97,693       $ 7,688       $ 105,381   
  

 

 

    

 

 

    

 

 

    

 

 

 

Bargain purchase gain

   $ —         $ —         $ 4,024       $ 4,024   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes an acquisition pursuant to a preferential purchase right, wherein the seller had attributed a negative fair value to a property. As a result, the Company received $5.4 million in cash and the property, and recognized a bargain purchase gain of $4.0 million.

 

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2009 Acquisitions

Bayou Bend Acquisition. On May 29, 2009, DOR purchased substantially all of the U.S. oil and gas properties of Bayou Bend Petroleum Ltd. and its subsidiaries (“Bayou Bend”) for $12.5 million. An additional payment of $1.1 million was made on April 1, 2011, based upon the increase in proved oil and gas reserves attributable to the purchased interests as of December 31, 2010 above a specified threshold. The purchase price allocation did not reflect a liability for this contingent obligation. As a result, the amount was recorded to other expense during 2010.

The acquisition broadens the Company’s leasehold footprint in the Gulf of Mexico and provides a new growth area for the Company in the shallow Louisiana state waters centered on the Marsh Island exploration project. Acquisition-related expenses of $0.3 million are included in general and administrative expense in the accompanying consolidated statements of operations.

Bandon Acquisition. On October 13, 2009, in a nonmonetary exchange with the prior owners of Bandon, DBH acquired a 100% ownership interest in Bandon.

The acquisition substantially increased the Company’s presence in the Gulf of Mexico. Acquisition-related expenses of $0.8 million are included in general and administrative expense in the accompanying consolidated statements of operations.

The acquisition was accounted for using the acquisition method and Bandon’s results of operations were included in the Company’s consolidated statement of operations effective October 13, 2009.

 

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     Year Ended December 31, 2009  
     Bandon (1)      Bayou Bend      Total  

Consideration paid

        

Cash

   $ —         $ 12,500       $ 12,500   
  

 

 

    

 

 

    

 

 

 
   $ 5,294       $ 12,500       $ 17,794   
  

 

 

    

 

 

    

 

 

 

Assets acquired:

        

Cash

   $ 41,740       $ —         $ 41,740   

Other current assets

     41,329         —           41,329   

Property and equipment

     327,872         13,645         341,517   

Other noncurrent assets

     8,308         —           8,308   
  

 

 

    

 

 

    

 

 

 

Total assets acquired

     449,124         13,645         462,769   
  

 

 

    

 

 

    

 

 

 

Liabilities assumed:

        

AROs, current portion

     44,986         214         45,200   

Other current liabilities

     23,269         —           23,269   

AROs, noncurrent portion

     55,726         931         56,657   

Other noncurrent liabilities

     7,274         —           7,274   
  

 

 

    

 

 

    

 

 

 

Total liabilities assumed

     282,479         1,145         283,624   
  

 

 

    

 

 

    

 

 

 

Net assets acquired

   $ 166,645       $ 12,500       $ 179,145   
  

 

 

    

 

 

    

 

 

 

Bargain purchase gain

   $ 161,351       $ —         $ 161,351   
  

 

 

    

 

 

    

 

 

 

 

(1) The Company’s estimate of the net assets’ fair value exceeded the fair value of the total consideration paid, which management believes resulted from Bandon’s financial difficulties prior to the acquisition.

Note 6—Property and Equipment

The components of property and equipment were as follows at the dates indicated:

 

     December 31,  
     2011     2010  

Proved oil and gas properties

   $ 1,592,698      $ 1,080,031   

Unproved oil and gas properties

     135,591        140,376   

Other property and equipment

     4,073        3,223   
  

 

 

   

 

 

 
     1,732,362        1,223,630   

Accumulated depreciation, depletion and amortization

     (532,951     (358,985
  

 

 

   

 

 

 
   $ 1,199,411      $ 864,645   
  

 

 

   

 

 

 

Substantially all of the Company’s assets serve as collateral under the debt agreements, as discussed in Note 9.

Asset Impairments. For the years ended December 31, 2011, 2010 and 2009, the Company determined that the carrying amount of certain of its oil and gas properties was not recoverable from estimated future net cash flows and, therefore, was impaired. The assets were written down to their estimated fair values, which were determined using discounted cash flow models. The discounted cash flow models used exchange-based forward commodity prices and a discount rate of 10%. Estimated future net cash flows from probable and possible reserves were risk-adjusted. The pre-tax impairment charges of $10.9 million ($10.2 million after-tax), $60.5 million ($52.5 million

 

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after-tax), and $10.8 million ($7.0 million after-tax) for 2011, 2010, and 2009 are included in the Company’s consolidated statements of operations as incremental depreciation, depletion and amortization expense. See Note 11. For the year ended December 31, 2011, the entire pre-tax amount resulted from declines in natural gas prices, well performance issues, and changes in the estimated abandonment costs of properties. For the year ended December 31, 2010, the entire pre-tax amount resulted from declines in natural gas prices and well performance issues. For the year ended December 31, 2009, the entire pre-tax amount resulted from changes in the estimated abandonment costs of properties acquired in the 2008 acquisition of DOR NS.

Note 7—Asset Retirement Obligations

The following table summarizes the activity for the Company’s asset retirement obligations for the periods indicated:

 

     Year Ended December 31,  
     2011     2010     2009  

Beginning of period

   $ 233,070      $ 218,902      $ 111,804   

Liabilities acquired

     96,070        62,837        101,858   

Liabilities sold

     (47     (1,287     (401

Liabilities settled

     (46,510     (63,350     (18,604

Accretion expense

     12,534        13,183        7,211   

Revisions to previous estimates

     82,499        2,785        17,034   
  

 

 

   

 

 

   

 

 

 

End of period

   $ 377,616      $ 233,070      $ 218,902   
  

 

 

   

 

 

   

 

 

 

Current portion

   $ 51,133      $ 71,225      $ 49,622   

Long-term portion

     326,483        161,845        169,280   
  

 

 

   

 

 

   

 

 

 
   $ 377,616      $ 233,070      $ 218,902   
  

 

 

   

 

 

   

 

 

 

SPN Resources, LLC (“SPN”), our wholly-owned subsidiary, has a platform abandonment contract with Superior Energy Services, Inc. (“Superior”) whereby Superior will provide well abandonment and pipeline and platform decommissioning services with respect to the specified properties for the greater of its actual cost or the fixed turnkey amount. This contract covers only routine end-of-life well abandonment and pipeline and platform decommissioning for properties owned and operated by SPN at March 14, 2008 and has a remaining fixed price of approximately $133.3 million as of December 31, 2011. For any additional wells drilled and completed after March 15, 2008, the abandonment liability was estimated based on similar wells in the field.

Note 8—Notes Receivable

Notes receivable consist of contractual obligations of sellers of oil and gas properties to reimburse the Company a specified amount following the abandonment of acquired properties. The Company invoices the seller specified amounts following the performance of decommissioning operations (abandonment and structure removal) in accordance with the applicable agreements with the seller. These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissioning. For the years ended December 31, 2011, 2010 and 2009 the amortization was $1.0 million, $1.1 million, and $1.2 million.

 

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Note 9—Long-Term Debt

The Company had the following debt outstanding at the dates indicated:

 

     December 31,  
     2011      2010  

Obligation of DOR

     

Revolving Credit Agreement, variable rate, due June 2015

   $ 365,000       $ 145,000   

Obligations of Bandon (1)

     

Second Lien Term Loan, variable rate, due October 2014

     —           58,205   
  

 

 

    

 

 

 
   $ 365,000       $ 203,205   
  

 

 

    

 

 

 

Letters of credit issued

   $ —         $ —     
  

 

 

    

 

 

 

 

(1) The Company consolidates the debt of Bandon; however, the debt of Bandon is secured by substantially all of the assets of Bandon. The Company does not provide guarantees of the indebtedness of Bandon and none of the Company’s directly owned assets are pledged as collateral for Bandon’s indebtedness.

Description of Debt Obligations

Obligation of DOR

$750 Million Amended and Restated Credit Agreement. On June 20, 2011, DOR amended and restated its existing credit agreement to provide for a four year $750 million revolving credit facility (the “DOR Credit Facility”) with a group of financial institutions (the “Lenders”). As of December 31, 2011 the borrowing base under the DOR Credit Facility was $430 million. In addition, $100 million of the borrowing base is available for the issuance of letters of credit.

The DOR Credit Facility is subject to semi-annual borrowing base redeterminations on April 1 and October 1 of each year. Due to the pending sale discussed in Note 18, the Company requested, and has received, a waiver for the borrowing base determination scheduled for April 1, 2012. In addition to the scheduled semi-annual borrowing base redeterminations, the Lenders or the Company have the right to re-determine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of the Company’s borrowing base is subject to a number of factors, including the quantities of proved oil and gas reserves, the Lenders’ price assumptions and other various factors, some of which may be out of the Company’s control. The Lenders can re-determine the borrowing base to a lower level than the current borrowing base if they determine that the Company’s oil and gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect. In this case, the Company would be required to make six monthly payments each equal to one sixth of the amount by which the aggregate outstanding loans and letters of credit exceed the borrowing base.

Obligations under the DOR Credit Facility are secured by liens on substantially all of the Company’s assets. The DOR Credit Facility also contains other restrictive covenants, including, among other items, maintenance of leverage ratio, interest coverage ratio and current ratio (all as defined in the credit agreement), restrictions on cash dividends and restrictions on incurring additional indebtedness. The DOR Credit Facility also requires DOR to enter into commodity price hedging agreements for at least half of its estimated oil and gas production from proved developed producing reserves.

 

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At our election, outstanding balances bear interest at either the alternate base rate plus a margin (based on a sliding scale of 1.25% to 2.00% based upon borrowing base usage) or the London Interbank Offered Rate (“LIBOR”) plus a margin (based on a sliding scale of 2.25% to 3.00% based upon borrowing base usage). The alternate base rate is equal to the higher of The Royal Bank of Scotland’s prime rate or the federal funds rate plus 0.5% per annum or the reference LIBOR plus 1%, and the LIBOR is equal to the applicable British Bankers’ Association LIBOR for deposits in U.S. dollars. The DOR Credit Facility also provides for commitment fees (based on a margin of 0.5%) calculated on the difference between the borrowing base and the aggregate outstanding loans and letters of credit under the DOR Credit Facility.

The Company’s management believes the Company was in compliance with its debt covenants as of December 31, 2011.

Obligations of Bandon

Second Lien Amended and Restated Credit Agreement. On October 13, 2009, Bandon entered into a Second Lien Amended and Restated Credit Agreement (the “Second Lien Agreement”). During 2011 the outstanding balance of the Second Lien Agreement was repaid and retired.

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations for the year ended December 31, 2011:

 

     Range of Interest Rates Paid   Weighted Average Interest Rate Paid

Revolving Credit Agreement

   2.8% to 5.0%   2.9%

Second Lien Term Loan

   8.0% to 8.0%   8.0%

Note 10—Risk Management Activities

The Company’s principal market risks are its exposure to changes in commodity prices, particularly to the prices of oil and gas, nonperformance by the Company’s counterparties, and changes in interest rates.

The Company’s revenues are derived principally from the sale of oil and gas. The prices of oil and gas are subject to market fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond the Company’s control. The Company monitors these risks and enters into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on the Company’s business.

The primary purpose of the Company’s commodity risk management activities is to hedge the Company’s exposure to commodity price risk and reduce fluctuations in the Company’s operating cash flow despite fluctuations in commodity prices. As of December 31, 2011, the Company has hedged the commodity price associated with a portion of its expected oil and gas sales volumes for the years 2012 through 2013 by entering into derivative financial instruments comprising swaps and collars. The percentages of the Company’s expected oil and gas that are hedged decrease over time.

With swaps, the Company receives an agreed upon fixed price for a specified notional quantity of oil or gas and the Company pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since the Company receives from its oil and gas marketing counterparties a price based on the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged.

For basis swaps, the Company receives a fixed differential between two regional oil index prices and pays a floating differential on the same two index prices to the contract counterparty. Since the Company receives from

 

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its oil and gas marketing counterparties a price based on the same floating differential from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed differential in advance for the volumes hedged.

In order to avoid having a greater volume hedged than the Company’s actual oil and gas sales volumes, the Company typically limits its use of swaps and basis swaps to hedge the prices of less than the Company’s expected sales volumes.

In a typical collar transaction, if the floating price based on a market index is below the floor price in the derivative contract, the Company receives from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, the Company must pay the counterparty an amount equal to the difference multiplied by the specified volume. If the Company has less production than the volumes specified under the collar transaction when the floating price exceeds the ceiling price, the Company must make payments against which there is no offsetting revenues from production.

The Company’s commodity hedges may expose the Company to the risk of financial loss in certain circumstances. The Company’s hedging arrangements provide the Company protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which the Company has hedged, the Company will receive less revenue on the hedged volumes than in the absence of hedges.

Interest Rate Risk. The Company is exposed to changes in interest rates, primarily as a result of variable rate borrowings under its debt agreements. To the extent that interest rates increase, interest expense for the Company’s variable rate debt will also increase.

Credit Risk. The Company’s credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to the Company at the reporting date. At such times, these outstanding instruments expose the Company to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the Company’s counterparties decline, the Company’s ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, the Company may sustain a loss and the Company’s cash receipts could be negatively impacted.

As of December 31, 2011, Citibank, Credit Suisse, Deutsche Bank, and an affiliate of The Royal Bank of Scotland (“RBS”) accounted for 38%, 34%, 14% and 14% of the Company’s counterparty credit exposure related to commodity derivative instruments. These counterparties are major financial institutions possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.

 

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The Company had commodity derivatives with the following terms outstanding as of December 31, 2011, none of which have been designated as cash-flow hedges:

 

     Year Ending December 31,  
     2012      2013  

Crude Oil

     

Swaps (Bbl)

     1,662,000         1,250,000   

Average price ($ per Bbl)

     91.86         100.47   

Collars (Bbl)

     418,000         168,000   

Average price ($ per Bbl)

     

Floor price (put)

     82.99         80.00   

Ceiling price (call)

     108.51         102.50   

LLS-WTI Differential Spread (Bbl)

     2,300,000         —     

Average price ($ per Bbl)

     17.17         —     

Natural Gas

     

Swaps (MMBtu)

     3,630,000         —     

Average price ($ per MMBtu)

     6.16         —     

Collars (MMBtu)

     8,115,000         6,000,000   

Average price ($ per MMBtu)

     

Floor price (put)

     4.08         3.75   

Ceiling price (call)

     6.62         6.65   

The following reflects the fair values of derivative instruments in the Company’s consolidated balance sheets as of the dates indicated:

 

     Asset Derivatives  
     Balance    Fair Value as of  

Derivatives not designated as hedging

instruments under ASC 815

   Sheet    December 31,  
   Location    2011      2010  

Commodity derivatives

   Current assets    $   44,471       $   11,990   

Commodity derivatives

   Long-term assets      9,953         4,919   

 

     Liability Derivatives  
     Balance    Fair Value as of  

Derivatives not designated as hedging

instruments under ASC 815

   Sheet    December 31,  
   Location    2011      2010  

Commodity derivatives

   Current liabilities    $   14,250       $   17,176   

Commodity derivatives

   Long-term liabilities      2,625         9,254   

See Note 11 for additional disclosures related to derivative instruments.

 

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Note 11—Fair Value Measurements

Accounting standards pertaining to fair value measurements establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include:

 

   

Level 1, defined as observable inputs such as quoted prices in active markets;

 

   

Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and

 

   

Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Company’s derivative contracts are reported in its consolidated financial statements at fair value. These contracts consist of over-the-counter swaps and collars, which are not traded on a public exchange.

The fair values of swap contracts are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Therefore, the Company has categorized these swap contracts as Level 2.

For collars, the Company estimates the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract terms. Therefore, the Company has categorized its collars as Level 2.

The Company has consistently applied these valuation techniques and believes it has obtained the most accurate information available for the types of derivative contracts it holds.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities measured at fair value on a recurring basis as of the dates indicated:

 

0000000 0000000 0000000 0000000

As of December 31, 2011

   Total      Level 1      Level 2      Level 3  

Commodity derivative assets

   $ 54,424       $ —         $ 54,424       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Commodity derivative liabilities

   $ 16,875       $ —         $ 16,875       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

0000000 0000000 0000000 0000000

As of December 31, 2010

   Total      Level 1      Level 2      Level 3  

Commodity derivative assets

   $ 16,909       $ —         $ 16,909       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Commodity derivative liabilities

   $ 26,430       $ —         $ 26,430       $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments under certain circumstances (e.g., when there is evidence of impairment).

 

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Asset Impairments. Information about impaired assets as of the dates of the assessment is as follows:

 

0000000 0000000 0000000
     Year Ended December 31,  
     2011      2010      2009  

Net Book Value (1)

   $ 17,248       $ 91,052       $ 12,044   

Impairment Charge

     10,851         60,513         10,808   
  

 

 

    

 

 

    

 

 

 

Level 3

   $ 6,397       $ 30,539       $ 1,236   
  

 

 

    

 

 

    

 

 

 

 

(1) Amount represents net book value at the date of impairment.

See Note 6 for a discussion of the methods and assumptions used to estimate the fair values of the impaired assets.

Note 12—Income Taxes

The components of the Company’s provisions for federal income taxes were as follows for the periods indicated:

 

0000000 0000000 0000000
     Year Ended December 31,  
     2011     2010     2009  

Current benefit

   $ —        $ —        $ (2,188

Deferred (benefit) expense

     (5,359     (14,814     (18,199
  

 

 

   

 

 

   

 

 

 
   $ (5,359   $ (14,814   $ (20,387
  

 

 

   

 

 

   

 

 

 

Set forth below is a reconciliation between DOR NS’ income tax benefit (expense) computed at the United States statutory rate on income (loss) before income taxes and the income tax benefit (expense) in the accompanying consolidated statements of operations:

 

0000000 0000000 0000000
     Year Ended December 31,  
     2011     2010     2009  

U.S. federal income tax provision at statutory rate

   $ 5,729      $ 15,507      $ 20,198   

Non-deductible expenses

     (15     (8     (22

Audit settlement

     —          (647     —     

Return to provision

     —          (507     —     

Other

     (355     469        211   
  

 

 

   

 

 

   

 

 

 
   $ 5,359      $ 14,814      $ 20,387   
  

 

 

   

 

 

   

 

 

 

No material uncertain tax positions were identified during 2011. The Company believes that DOR NS’ income tax filing positions and deductions will more-likely-than-not be sustained on audit and does not anticipate any adjustments that will result in a material adverse effect on the Company’s financial condition, results of operations or cash flows. Therefore, no reserves for uncertain income tax positions have been recorded.

As of December 31, 2011, DOR NS had regular federal net operating loss carryforwards of $1.0 million, which begin to expire in 2027.

 

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The components of DOR NS’ deferred income tax assets and liabilities as of the dates indicated were as follows:

 

     December 31,  
     2011     2010  

Deferred tax assets:

    

Asset retirement obligation

   $ 13,806      $ 11,913   

Loss carryforwards

     356        144   

Alternative minimum tax

     2,571        2,571   

Allowance for bad debts

     479        577   

Other

     —          —     
  

 

 

   

 

 

 
     17,212        15,205   
  

 

 

   

 

 

 

Deferred tax liabilities:

    

Property and equipment

     (57,943     (61,474

Other

     (179     —     
  

 

 

   

 

 

 
     (58,122     (61,474
  

 

 

   

 

 

 

Net deferred tax liabilities

   $ (40,910   $ (46,269
  

 

 

   

 

 

 

Balance sheet classification of deferred tax assets and liabilities:

    

Current asset

   $ 2,571      $ 3,292   

Long-term liability

     (43,481     (49,561
  

 

 

   

 

 

 
   $ (40,910   $ (46,269
  

 

 

   

 

 

 

Note 13—Related Party Transactions

Relationship with Superior. Superior owns a 10% ownership interest in DOH, and is party to the turnkey platform abandonment contract described in Note 7. Superior provides various field-level services to the Company. These transactions were recorded in the consolidated financial statements as follows:

 

00000000 00000000 00000000
     December 31,  
     2011      2010      2009  

Insurance receivable

   $ 7       $ 4,436       $ 1,454   

Additions to property and equipment

     14,602         4,429         3,815   

Asset retirement obligations settled

     12,864         13,410         5,845   

Lease operating expense

     1,895         2,311         1,665   

Workover expense

     4,882         1,301         360   
  

 

 

    

 

 

    

 

 

 
   $ 34,250       $ 25,887       $ 13,139   
  

 

 

    

 

 

    

 

 

 

Relationship with DOH GP. The Company has no employees. Dynamic Offshore Holding GP, LLC (“DOH GP”), the general partner of DOH, charges all of its employee costs to the Company, at cost, as part of the administrative services agreement between DOH GP and the Company. The Company allocates employee costs charged by DOH GP and other general and administrative costs, at cost, among its consolidated subsidiaries based on an agreed sharing percentage. For the years ended December 31, 2011, 2010, and 2009, DOH GP charged DOR $20.0 million, $15.4 million, and $17.3 million under the agreement, which is included in the accompanying consolidated statements of operations as general and administrative expense and lease operating expense.

 

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Affiliate receivables and payables were as follows as of the dates indicated:

 

0000000 0000000
     December 31,  
     2011      2010  

Receivable from DOH GP

   $ 4       $ 6   
  

 

 

    

 

 

 

Payable to SESI and its affiliates

   $ 601       $ 50   
  

 

 

    

 

 

 

Note 14—Owners’ Equity

The limited company agreement (the “Agreement”) of DOR, dated September 17, 2007 does not provide for any shares of stock representing the membership interests. Membership interests are determined in accordance with the contributions, distributions and profit and loss allocations made by, to, or on behalf of, each individual member in accordance with the Agreement.

As of December 31, 2011, DOH was the sole member of DOR.

See also Note 18.

Note 15—Hurricane Remediation and Insurance Claims

During 2008, Hurricanes Ike and Gustav caused property damage and disruptions to the Company’s exploitation and production activities. The Company currently has insurance coverage for named windstorms but does not carry business interruption insurance. The Company recognizes insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when the Company deems collection of those receivables to be reasonably assured.

Except for the removal of a toppled platform that was supporting the Company’s Ship Shoal Block 253 operations, activities related to the 2008 hurricanes are complete and the Company expects no further recognition of casualty gain or loss in its consolidated statements of operations with respect to those storms.

Note 16—Supplemental Cash Flow Information

The following table provides supplemental cash flow information for the periods indicated:

 

0000000 0000000 0000000
     Year Ended December 31,  
     2011      2010      2009  

Cash:

        

Interest paid

   $ 8,409       $ 11,589       $ 7,871   

Non-cash:

        

Contribution from noncontrolling interest

     5,032         —           5,294   

Acquisition of Bandon

     —           —           5,294   

Increase arising from purchase accounting:

        

Purchase of oil and gas properties

     —           44,189         —     

Purchase of noncontrolling interest in DBH (see Note 4)

     89,268         3,452         4,384   

 

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Note 17—Commitments and Contingencies

Operating Leases. The Company holds leases for office space in Houston, Texas. Noncancellable commitments under the leases are $2.0 million for the year ending December 31, 2012. During 2011, 2010 and 2009, the Company paid $2.0 million, $2.3 million, and $0.5 million in rent under its operating leases.

Legal Proceedings. From time to time, the Company may be involved in litigation arising out of the normal course of its business. In management’s opinion, the Company is not involved in any litigation, the outcome of which would have a material effect on its consolidated financial position, results of operations, or liquidity.

Note 18—Subsequent Event

On February 1, 2012, SandRidge Energy, Inc. entered into an agreement to acquire DOR for aggregate consideration of $1.3 billion, consisting of approximately $680 million in cash and approximately 74 million shares of SandRidge common stock valued at $8.02 per share. The acquisition is expected to close in April 2012.

Note 19—Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The supplemental data presented herein reflects information for the Company’s crude oil and natural gas producing activities, all of which are in the United States of America.

Results of Operations for Oil and Gas Producing Activities

Our results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges and interest income. Income tax expense was determined by applying the statutory rates to pretax operating results of our taxable subsidiary:

 

00000000 00000000 00000000
     Year Ended December 31,  
     2011     2010     2009  

Revenues from oil and gas producing activities

   $ 504,286      $ 345,812      $ 178,992   

Production costs

     (113,487     (89,399     (60,618

Workover costs

     (20,701     (15,827     (6,696

Accretion expense

     (12,534     (13,183     (7,211

Loss on abandonments

     (10,231     (2,601     (4,687

Exploration expenses

     (15,085     (2,100     (8,999

Depreciation, depletion and amortization expense (1)

     (172,801     (194,358     (87,917

Income tax (expense) benefit

     930        10,548        3,505   
  

 

 

   

 

 

   

 

 

 

Results of operations from producing activities

   $ 160,377      $ 38,892      $ 6,369   
  

 

 

   

 

 

   

 

 

 

(excluding general and administrative and interest costs)

      

 

(1) This amount only reflects DD&A of capitalized costs of proved oil and gas properties and,therefore, does not agree with DD&A reflected in the statement of operations.

Oil and Gas Reserves

The Company’s estimates of proved reserves as of December 31, 2011, 2010 and 2009 are based on estimates prepared by our internal engineers, in accordance with the rules and regulations regarding oil and natural gas reserve reporting. Users of this information should be aware that the process of estimating quantities of “proved” and “proved-developed” crude oil and natural gas reserves is very complex, requiring significant subjective

 

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decision making in the analysis and evaluation of all geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, additional production data, evolving production history, and continual reassessment of the viability of production under different economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

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The following table sets forth the Company’s net proved reserves, including changes therein:

 

     Crude oil
(MBbl)
    Natural gas
(MMcf)
 

2009

    

Proved Reserves

    

Beginning balance

     13,136        61,636   

Revision of previous estimates

     1,570        (935

Extensions, discoveries and other additions

     —          —     

Purchase of reserves in-place

     3,783        69,795   

Sale of reserves in-place

     —          —     

Production

     (2,145     (10,555
  

 

 

   

 

 

 

Ending balance

     16,344        119,941   
  

 

 

   

 

 

 

Proved Developed Reserves, December 31, 2009

     14,031        101,771   
  

 

 

   

 

 

 

Proved Undeveloped Reserves, December 31, 2009

     2,313        18,170   
  

 

 

   

 

 

 

2010

    

Proved Reserves

    

Beginning balance

     16,344        119,941   

Revision of previous estimates

     3,266        5,554   

Extensions, discoveries and other additions

     196        2,696   

Purchase of reserves in-place

     7,959        19,455   

Sale of reserves in-place

     (132     (5,475

Production

     (3,289     (18,468
  

 

 

   

 

 

 

Ending balance

     24,344        123,703   
  

 

 

   

 

 

 

Proved Developed Reserves, December 31, 2010

     20,191        110,253   
  

 

 

   

 

 

 

Proved Undeveloped Reserves, December 31, 2010

     4,153        13,450   
  

 

 

   

 

 

 

2011

    

Proved Reserves

    

Beginning balance

     24,344        123,703   

Revision of previous estimates

     4,317        8,022   

Extensions, discoveries and other additions

     —          —     

Purchase of reserves in-place

     7,139        72,701   

Sale of reserves in-place

     —          —     

Production

     (3,728     (22,070
  

 

 

   

 

 

 

Ending balance

     32,072        182,356   
  

 

 

   

 

 

 

Proved Developed Reserves, December 31, 2011

     26,055        146,947   
  

 

 

   

 

 

 

Proved Undeveloped Reserves, December 31, 2011

     6,017        35,409   
  

 

 

   

 

 

 

As of December 31, 2011, 2010 and 2009, proved reserves attributable to noncontrolling interests in consolidated subsidiaries were 0%, 17%, and 23% of the total.

 

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Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

Costs incurred, on an accrual basis, represent amounts capitalized or expensed during the three years ended December 31, 2011 for property acquisition, exploration, development and abandonment activities. Costs incurred for property acquisitions, exploration, development and abandonment activities were as follows:

 

0000000 0000000 0000000
     Year Ended December 31,  
     2011      2010      2009  

Acquisition costs

        

Proved properties

   $ 324,191       $ 157,435       $ 251,976   

Unproved properties

     9         541         94,459   

Exploration costs

     15,085         19,357         10,531   

Development costs

     171,388         39,600         41,182   

Asset retirement costs

     56,745         65,951         23,291   
  

 

 

    

 

 

    

 

 

 

Total costs incurred

   $ 567,418       $ 282,884       $ 421,439   
  

 

 

    

 

 

    

 

 

 

Capitalized Costs

The following table presents the aggregate capitalized costs relating to our oil and gas acquisition, exploration and development activities, and the aggregate related accumulated DD&A:

 

00000000 00000000 00000000
     December 31,  
     2011     2010     2009  

Unproved oil and gas properties

   $ 135,591      $ 140,376      $ 178,073   

Proved oil and gas properties

     1,592,698        1,080,031        845,835   

Accumulated depreciation, depletion and amortization

     (528,965     (356,695     (164,347
  

 

 

   

 

 

   

 

 

 

Capitalized costs, net

   $ 1,199,324      $ 863,712      $ 859,561   
  

 

 

   

 

 

   

 

 

 

The costs of unproved oil and gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are assessed periodically, at least annually, to determine whether impairment has occurred. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment considers the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the associated costs are transferred to proved properties and are then subject to amortization. The transfer of costs into proved properties involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, geological and geophysical evaluations, the assignment of proved reserves, availability of capital, and other factors. Costs not subject to amortization consist primarily of the estimated fair value of acquired unproved reserves. Due to the nature of the reserves, the ultimate evaluation of the properties will occur over a period of several years.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

 

The following tables set forth the computation of the standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved reserves and the changes in such cash flows of the Company’s oil and gas properties in accordance with the FASB’s authoritative guidance related to disclosures about oil and gas producing activities. The Standardized Measure is the estimated net future cash inflows from

 

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proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, estimated future income taxes (if applicable) and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the un-weighted arithmetic average first-day-of-the-month index prices for the preceding 12 months for proved reserves as of December 31, 2011, 2010 and 2009. These prices were $103.34/Bbl for oil and $4.48/MMBtu for natural gas at December 31, 2011; $79.40/Bbl for oil and $4.38/MMBtu for natural gas at December 31, 2010; and $61.04/Bbl for oil and $3.86/MMBtu for natural gas at December 31, 2009. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the FASB’s authoritative guidance, a discount rate of 10% is applied to the annual future net cash flows. Future income taxes were calculated by applying the statutory federal income tax rate to pre-tax future net cash flows of properties owned by our taxable subsidiary, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

The Standardized Measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

The Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows:

 

     December 31,  
     2011     2010     2009  

Future cash inflows

   $ 4,142,460      $ 2,528,761      $ 1,414,485   

Future production costs

     (1,000,235     (499,846     (373,641

Future development and abandonment costs

     (677,603     (511,596     (450,839

Future income tax expense

     (97,035     (30,106     (29,113
  

 

 

   

 

 

   

 

 

 

Future net cash flows

     2,367,587        1,487,213        560,892   

10% annual discount for estimated timing of cash flows

     (540,915     (302,695     (85,254
  

 

 

   

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 1,826,672      $ 1,184,518      $ 475,638   
  

 

 

   

 

 

   

 

 

 

As of December 31, 2011, 2010 and 2009, 0%, 14%, and 22% of the Standardized Measure was attributable to noncontrolling interests in consolidated subsidiaries.

 

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A summary of the changes in the Standardized Measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the three years ended December 31, 2011 is as follows:

 

     Year Ended December 31,  
     2011     2010     2009  

Beginning of year

   $ 1,184,518      $ 475,638      $ 254,706   

Sales and transfers of oil and natural gas produced, net of production costs

     (390,799     (256,413     (118,374

Net changes in prices and production costs

     301,750        383,400        48,305   

Net changes in estimated future development costs

     (87,249     11,277        (6,435

Extensions and discoveries

     —          18,672        —     

Revisions of quantity estimates

     172,144        157,489        29,079   

Development costs incurred

     144,567        99,983        45,652   

Purchase and sales of reserves in place

     440,165        231,933        191,268   

Changes in production rates (timing) and other

     (15,566     (3,144     (1,503

Net change in income taxes

     (43,798     1,224        3,326   

Accretion of discount

     120,940        64,459        29,614   
  

 

 

   

 

 

   

 

 

 

Net increase

     642,154        708,880        220,932   
  

 

 

   

 

 

   

 

 

 

End of year

   $ 1,826,672      $ 1,184,518      $ 475,638   
  

 

 

   

 

 

   

 

 

 

 

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DYNAMIC OFFSHORE RESOURCES, LLC

UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS

Year Ended December 31, 2011

(In thousands)

     Historical               
     Dynamic     XTO               
     Offshore     Acquisition      Pro Forma        
     Resources, LLC     Properties      Adjustments     Pro Forma  

Operating revenues

   $ 520,782      $ 95,638       $ —        $ 616,420   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating expenses:

         

Lease operating expense

     113,487        19,607         —          133,094   

Exploration expense

     15,085        —           —          15,085   

Depreciation, depletion and amortization

     173,585        —           29,872 (a)      203,457   

General and administrative expense

     24,400        —           —          24,400   

Other operating expense

     77,505        4,125         2,494 (a)      84,124   
  

 

 

   

 

 

    

 

 

   

 

 

 
     404,062        23,732         32,366        460,160   
  

 

 

   

 

 

    

 

 

   

 

 

 

Income (loss) from operations

     116,720        71,906         (32,366     156,260   

Other income (expense):

         

Interest expense, net

     (9,503     —           (3,504 )(a)      (13,007

Commodity derivative income

     43,734        —           —          43,734   

Bargain purchase gain

     282        —           —          282   

Other

     (145     —           —          (145
  

 

 

   

 

 

    

 

 

   

 

 

 

Income (loss) before income taxes

     151,088        71,906         (35,870     187,124   

Income tax benefit

     5,359        —           —          5,359   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss)

     156,447        71,906         (35,870     192,483   

Less: Net income attributable to noncontrolling interests

     460        —           —          460   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss) attributable to Dynamic Resources, LLC

   $ 155,987      $ 71,906       $ (35,870   $ 192,023   
  

 

 

   

 

 

    

 

 

   

 

 

 

See notes to unaudited pro forma condensed financial statements

 

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Dynamic Offshore Resources, LLC

Notes to Unaudited Pro Forma Condensed Financial Statements

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Note 1—Basis of Presentation

The historical financial information is derived from the historical consolidated financial statements of Dynamic Offshore Resources, LLC for the year ended December 31, 2011 and the historical statements of revenue and direct operating expenses of the XTO Acquisition Properties for the eight months ended August 31, 2011. The unaudited pro forma condensed financial information has been prepared by applying pro forma adjustments to the historical audited financial statements of Dynamic Offshore Resources, LLC. The pro forma adjustments have been prepared as if our acquisition of the XTO Acquisition Properties had taken place as of January 1, 2011.

Note 2—Pro Forma Adjustments and Assumptions

Purchase of XTO Acquisition Properties

Our purchase of the XTO Acquisition Properties was completed on August 31, 2011. As a result, the acquisition is included in the historical financial statements of Dynamic Offshore Resources, LLC with effect from that date.

(a) Reflects our purchase of the XTO Acquisition Properties, including:

 

   

depreciation, depletion and amortization expense and accretion expense based on our preliminary fair value determination and our closing date oil and gas reserve estimates;

 

   

interest expense on $173.7 million in borrowings for the period from January 1, 2011 through August 31, 2011, at an estimated annual rate of approximately 3.0%. A one percentage point change in the interest rate would change pro forma interest expense by $1.2 million for the year ended December 31, 2011.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Partners of

Dynamic Offshore Holding, LP

We have audited the accompanying statements of revenues and direct operating expenses of the XTO Acquisition Properties for the years ended December 31, 2010 and 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the XTO Acquisition Properties described in Note 1 for the years ended December 31, 2010 and 2009, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements reflect the revenues and direct operating expenses of the XTO Acquisition Properties as described in Note 1 and are not intended to be a complete presentation of the financial position, results of operations, or cash flows of the XTO Acquisition Properties.

Hein & Associates LLP

Houston, Texas

November 8, 2011

 

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XTO ACQUISITION PROPERTIES

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

(In thousands)

 

     Six Months Ended
June 30,
     Year Ended
December 31,
 
     2011      2010      2010      2009  
     (Unaudited)                

Oil and gas revenues

   $ 67,793       $ 85,173       $ 154,367       $ 170,045   

Direct operating expenses

     17,006         19,419         37,530         37,862   
  

 

 

    

 

 

    

 

 

    

 

 

 

Excess of revenues over direct operating expenses

   $ 50,787       $ 65,754       $ 116,837       $ 132,183   
  

 

 

    

 

 

    

 

 

    

 

 

 

See notes to statements of revenues and direct operating expenses

 

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XTO ACQUISITION PROPERTIES

Notes to Statements of Revenues and Direct Operating Expenses

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Note 1—Properties and Basis of Presentation

The accompanying statements represent the interests in the revenues and direct operating expenses of the oil and natural gas producing properties acquired by Dynamic Offshore Holding, LP (the “Partnership”) from XTO Offshore Inc., HHE Energy Company and XH, LLC, each an indirect subsidiary of Exxon Mobil Corporation, (collectively, “XTO”) effective August 1, 2011. The Partnership paid $173.7 million for the properties. The properties are referred to herein as the “XTO Acquisition Properties” and are located in the Gulf of Mexico.

The statements of revenues and direct operating expenses have been derived from XTO’s historical financial records and prepared on the accrual basis of accounting. Revenues and direct operating expenses relate to the historical net revenue interests and net working interests in the XTO Acquisition Properties. Oil, gas and condensate revenues are recognized on the sales method when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues are reported net of overriding and other royalties due to third parties. Direct operating expenses include lease operating expenses, production and ad valorem taxes, transportation and all other direct operating costs associated with the properties. Direct operating expenses include $0.3 million and $6.5 million of insurance costs allocated by XTO for the years ended December 31, 2010 and 2009. For each of the six months ended June 30, 2011 and 2010, direct operating expenses include $0.1 million of insurance costs allocated by XTO. Direct operating expenses do not include corporate overhead, interest expense and income taxes.

The statements of revenues and direct operating expenses are not indicative of the financial condition or results of operations of the XTO Acquisition Properties going forward due to the omission of various operating expenses. During the periods presented, the XTO Acquisition Properties were not accounted for by XTO as a separate business unit. As such, certain costs, such as depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses and interest expense were not allocated to the XTO Acquisition Properties.

Note 2—Omitted Financial Information

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not available on a property-by-property basis, nor is it practicable to obtain such information in these circumstances. Historically, no allocation of general and administrative, interest expense, corporate taxes, accretion of asset retirement obligations, and depreciation, depletion and amortization was made to the XTO Acquisition Properties. Accordingly, the statements of revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-01 and Rule 3-02 of the Securities and Exchange Commission’s Regulation S-X.

 

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Supplemental Oil and Gas Reserve Information (Unaudited)

Except as noted within the context of each disclosure, the dollar amounts presented in the tabular data herein are stated in thousands of dollars.

Oil and Gas Reserve Information

The following tables summarize the net ownership interests in estimated quantities of proved and proved developed oil and natural gas reserves of the XTO Acquisition Properties for the periods indicated, estimated by the Partnership’s petroleum engineers, and the related summary of changes in estimated quantities of net remaining proved reserves during the periods indicated.

 

     Crude oil
(MBbl)
    Natural gas
(MMcf)
 

2009

    

Proved Reserves

    

Beginning balance

     8,494        85,199   

Production

     (1,594     (17,568
  

 

 

   

 

 

 

Ending balance

     6,900        67,631   
  

 

 

   

 

 

 

Proved Developed Reserves, December 31, 2009

     6,087        49,674   
  

 

 

   

 

 

 

Proved Undeveloped Reserves, December 31, 2009

     813        17,957   
  

 

 

   

 

 

 

2010

    

Proved Reserves

    

Beginning balance

     6,900        67,631   

Production

     (1,145     (12,899
  

 

 

   

 

 

 

Ending balance

     5,755        54,732   
  

 

 

   

 

 

 

Proved Developed Reserves, December 31, 2010

     4,958        36,878   
  

 

 

   

 

 

 

Proved Undeveloped Reserves, December 31, 2010

     797        17,854   
  

 

 

   

 

 

 

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves.

The following tables set forth the computation of the standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved reserves and the changes in such cash flows of the XTO Acquisition Properties in accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance related to disclosures about oil and gas producing activities. The Standardized Measure is the estimated net future cash inflows from proved reserves less estimated future production and development costs, estimated plugging and abandonment costs, estimated future income taxes (if applicable) and a discount factor. Production costs do not include depreciation, depletion and amortization of capitalized acquisitions, exploration and development costs. Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the unweighted average of first-day-of-the-month commodity prices for the period and any fixed and determinable future price changes provided by contractual arrangements in existence at period end. Price changes based on inflation, federal regulatory changes and supply and demand are not considered. Estimated future production costs related to period-end reserves are based on period-end costs. Such costs include, but are not limited to, production taxes and direct operating costs. Inflation and other anticipatory costs are not considered until the actual cost change takes effect. In accordance with the FASB’s authoritative guidance, a discount rate of 10% is applied to the annual future net cash flows.

In calculating the Standardized Measure, future net cash inflows were estimated by using the unweighted average of first-day-of-the-month oil and gas prices for the period with the estimated future production of period-end proved reserves

 

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and assume continuation of existing economic conditions. These prices were $79.40 per barrel of oil and $4.38 per MMBtu of natural gas at December 31, 2010 and $61.04 per barrel of oil and $3.86 per MMBtu of natural gas at December 31, 2009. The index prices have been adjusted for historical average location and quality differentials. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs resulting in net cash flow before tax. Future income tax expense was not considered as the Partnership and the XTO Acquisition Properties are not tax-paying entities.

The Standardized Measure is not intended to be representative of the fair market value of the proved reserves. The calculations of revenues and costs do not necessarily represent the amounts to be received or expended. Accordingly, the estimates of future net cash flows from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimates to be incurred in developing and producing the estimated proved oil and gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other oil and gas producers.

 

     December 31,  
     2010     2009  

Future cash inflows

   $ 768,243      $ 766,742   

Future production costs

     (153,562     (185,230

Future development and abandonment costs

     (178,912     (192,601

Future income tax expense

     —          —     
  

 

 

   

 

 

 

Future net cash flows

     435,769        388,911   

10% annual discount for estimated timing of cash flows

     (101,813     (89,734
  

 

 

   

 

 

 

Standardized measure of discounted future net cash flows

   $ 333,956      $ 299,177   
  

 

 

   

 

 

 

Changes in the Standardized Measure are as follows:

 

     Year Ended December 31,  
     2010     2009  

Beginning of year

   $ 299,177      $ 404,634   

Sales of oil and natural gas, net of costs

     (116,837     (132,183

Net changes in prices and production costs

     90,295        (25,787

Development costs incurred

     13,689        28,962   

Accretion of discount

     25,678        33,988   

Changes in timing and other

     21,954        (10,437
  

 

 

   

 

 

 

Net increase (decrease)

     34,779        (105,457
  

 

 

   

 

 

 

End of year

   $ 333,956      $ 299,177   
  

 

 

   

 

 

 

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

   

SANDRIDGE ENERGY, INC.

(Registrant)

Date: April 2, 2012     By:    /s/ James D. Bennett
      Name: James D. Bennett
     

Title:   Executive Vice President and

            Chief Financial Officer