Attached files
| file | filename |
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| 8-K - FORM 8-K - SANDRIDGE ENERGY INC | d8k.htm |
Exhibit 99.1
SandRidge Energy, Inc. Reports Financial and Operational Results for Fourth
Quarter and Full Year 2010
Increases Total Production by 15% and Oil Production by 155% from 2009
Increases Proved Reserves by 149% and PV-10 by 189% from Year End 2009
Reports 2010 Finding Costs of $9.04 per Boe Excluding Revisions
Oklahoma City, Oklahoma, February 24, 2011 – SandRidge Energy, Inc. (NYSE: SD) today announced financial and operational results for the quarter and year ended December 31, 2010.
Key Financial Results
Fourth Quarter
| • | Net loss applicable to common stockholders of $208.0 million, or $0.53 per diluted share, for fourth quarter 2010 compared to net loss applicable to common stockholders of $434.2 million, or $2.36 per diluted share, in fourth quarter 2009. |
| • | Adjusted net loss of $35.4 million, or $0.07 per diluted share, (adjusted net loss of $31.6 million, or $0.06 per diluted share, including realized gains on out-of-period derivative contract settlements) in fourth quarter 2010 compared to adjusted net income of $32.6 million, or $0.14 per diluted share, in fourth quarter 2009. |
| • | Adjusted EBITDA of $130.5 million ($134.3 million including realized gains on out-of-period derivative contract settlements) for fourth quarter 2010 compared to $150.4 million in fourth quarter 2009. |
| • | Operating cash flow of $72.3 million for fourth quarter 2010 compared to $108.9 million in fourth quarter 2009. |
Full Year
| • | Net income available to common stockholders of $153.1 million, or $0.52 per diluted share, for 2010 compared to net loss applicable to common stockholders (including $1.69 billion non-cash full cost ceiling impairment) of $1.78 billion, or $10.20 per diluted share, in 2009. |
| • | Adjusted net income of $42.4 million, or $0.11 per diluted share, (adjusted net income of $65.7 million, or $0.17 per diluted share, including realized gains on out-of-period derivative contract settlements) in 2010 compared to $148.8 million, or $0.65 per diluted share, in 2009. |
| • | Adjusted EBITDA of $644.9 million ($668.1 million including realized gains on out-of-period derivative contract settlements) for 2010 compared to $584.2 million in 2009. |
| • | Operating cash flow of $410.2 million for 2010 compared to $417.6 million in 2009. |
Adjusted net (loss applicable) income available to common stockholders, adjusted EBITDA and operating cash flow are non-GAAP financial measures. Each measure is defined and reconciled to the most directly comparable GAAP measure under “Non-GAAP Financial Measures” beginning on page 11.
Highlights and Year End Reserves
| • | Record oil production in fourth quarter and full year 2010 of 2.612 MMBoe and 7.386 MMBoe, respectively. |
| • | 100% of current rig activity dedicated to drilling oil wells in the Central Basin Platform and the Mississippian formation. |
| • | Oil reserves increased 140% to 252 MMBbls at year end 2010 from 105 MMBbls at year end 2009. |
| • | Total reserves increased 149% to 546 MMBoe at year end 2010 from 219 MMBoe at year end 2009. |
| • | SEC PV-10 value increased 189% to $4.509 billion at year end 2010 from $1.561 billion at year end 2009. |
| • | Finding costs of $9.04 per Boe excluding revisions ($3.61 per Boe including revisions) |
| • | Reserve replacement of 521% excluding revisions. |
| • | 780,000 net acres in the Mississippian oil play. |
| • | Closed sales of non-core assets netting total proceeds of approximately $265.0 million during December 2010 and January 2011. |
| • | Announced an additional $400 million to $500 million in non-core asset sales and Mississippian acreage monetization. |
Tom L. Ward, Chairman and CEO commented, “We are now seeing the value of our transformation to oil. The present value of our reserves is $4.5 billion, nearly three times our year end 2009 present value. Our oil reserves have more than doubled from year end 2009. Our finding cost of $9.04 per Boe reflects the high quality of our drilling program. We have grown oil production from 7,900 barrels per day in fourth quarter 2009 to over 28,400 barrels per day in fourth quarter 2010 and expect oil sales to generate about 80% of our revenues in 2011.
“We have significantly enhanced our value with the early move to oil in two proven areas. We control 185,000 net acres in the Central Basin Platform in West Texas and have now leased 780,000 net acres in the Mississippian oil play in Northern Oklahoma and Southern Kansas. We expect to ultimately own over 900,000 net acres in the Mississippian as we wind down our leasing efforts in the first quarter. In both of these plays we develop shallow, permeable, carbonate reservoirs with decades of production history. As a result, our costs have remained low and we do not expect to see the type of cost increases the industry is experiencing.
“We plan to drill over 900 wells in the Central Basin Platform and the Mississippian in 2011 where our average wellhead return is expected to exceed 90%. We intend to fund this program with a combination of cash flow, proceeds from non-core asset sales and monetizing a portion of Mississippian acreage.”
Drilling Activities
The company averaged 24 rigs operating during the fourth quarter of 2010 and drilled 234 wells. A total of 227 gross (216 net) operated wells were completed and brought on production during the fourth quarter of 2010. The company drilled a total of 656 wells during 2010 compared to 140 wells in 2009. The total number of operated wells completed and brought on production during 2010 was 594 gross (554 net) compared to 156 gross (126 net) wells during 2009. At December 31, 2010, the company had 26 rigs operating compared to 15 at December 31, 2009. Currently, the company has 29 rigs operating, of which 17 are drilling in the Permian Basin and 12 are drilling in the Mid-Continent.
Permian Basin
The company drilled 484 wells in the Permian Basin during 2010 and, through acquisitions and an active drilling program, grew production there from 3,500 Boe per day in the fourth quarter of 2009 to 28,500 Boe per day in the fourth quarter of 2010. SandRidge currently controls approximately 210,000 net acres in the Permian Basin on which it has identified over 7,700 drilling locations. The company presently operates 17 rigs in the Permian Basin, 16 of which are operating on the Central Basin Platform drilling primarily San Andreas and Clear Fork vertical wells at depths from 4,500 feet to 7,500 feet. The company plans to drill over 800 wells in the Permian Basin in 2011 and operate 16 rigs there throughout the remainder of the year.
2
Mississippian Horizontal Play
The Mississippian horizontal oil play in the Mid-Continent area of Oklahoma and Kansas is an expansive carbonate hydrocarbon system that lies stratigraphically between the Pennsylvanian-aged Morrow Sand and the Devonian-aged Woodford Shale formations, its top being encountered between 4,000 and 6,000 feet. During 2010, SandRidge drilled 37 horizontal wells in the Mississippian play. The company organically grew its Mid-Continent production from 4,220 Boe per day in fourth quarter 2009 to 6,850 Boe per day in fourth quarter 2010, primarily through its horizontal development of the Mississippian play, where oil production increased from 525 Bbls per day to 2,520 Bbls per day during the same period. SandRidge has approximately 780,000 net acres leased in the Mississippian play on which it has currently identified over 3,400 additional drilling locations. The company presently operates 12 rigs in the play, of which eight are drilling horizontal producer wells and four are drilling saltwater disposal wells. SandRidge plans to drill over 130 horizontal wells in the Mississippian play in 2011, using 12 rigs there beginning in second quarter 2011 and throughout the remainder of the year.
Proved Reserves
The company’s estimated proved reserves as of December 31, 2010 were 546 MMBoe, representing a 149% increase from December 31, 2009. During 2010, the company recognized additional proved reserves of 347 MMBoe, which were primarily attributable to the acquisition of reserves in place from Arena and extensions and discoveries associated with successful drilling in the Permian Basin and Mid-Continent areas and oil and natural gas price increases. Proved developed reserves constituted 41% of total reserves as of December 31, 2010. Estimates of approximately 96% of the company’s total proved reserves as of December 31, 2010 were prepared by third-party engineers.
The December 31, 2010 estimated future net cash flows from proved reserves, discounted at an annual rate of 10%, before income taxes (“PV-10”) were $4.509 billion, an increase of 189% from December 31, 2009 PV-10 of $1.561 billion. Revisions due to increases in price per unit of future production accounted for approximately $1.366 billion in PV-10 from December 31, 2009 to December 31, 2010. The weighted average wellhead prices, which are based on index prices and adjusted for transportation and regional price differentials, used to estimate the company’s proved reserves and future net revenues were $66.93 per barrel for oil and $3.80 per Mcf for natural gas at December 31, 2010 compared to $49.98 per barrel for oil and $3.41 per Mcf for natural gas at December 31, 2009. An additional $2.090 billion of increase in PV-10 was attributable to the increase in proved reserves as a result of the Arena acquisition and extensions and discoveries associated with the successful drilling program.
Excluding the positive impact of price related reserve revisions, drilling finding costs and all-in finding costs, which include drilling, acquisitions, land and seismic costs, were $9.04 and $12.86 per Boe, respectively, for the year ended December 31, 2010.
Analysis of Proved Reserves and Replacement Economics
| Liquids (MBbls) |
Natural Gas (MMcf) |
Combined MBoe |
||||||||||
| As of December 31, 2009 |
105,349 | 680,075 | 218,695 | |||||||||
| Acquisition of new reserves |
71,640 | 79,942 | 84,964 | |||||||||
| Sales of reserves |
— | (207 | ) | (35 | ) | |||||||
| Production |
(7,386 | ) | (76,226 | ) | (20,090 | ) | ||||||
| Extensions and discoveries |
69,512 | 211,150 | 104,704 | |||||||||
| Revisions of previous estimates |
12,999 | 867,931 | 157,653 | |||||||||
| As of December 31, 2010 |
252,114 | 1,762,665 | 545,891 | |||||||||
| 2010 | 2009 | |||||||
| PV-10 (in Millions) | ||||||||
| Oil properties |
$ | 3,961 | $ | 1,076 | ||||
| Gas properties |
$ | 548 | $ | 485 | ||||
| Total |
$ | 4,509 | $ | 1,561 | ||||
| % Oil Properties to Total |
88 | % | 69 | % | ||||
| PV-10 of proved Reserves ($/Boe) |
$ | 8.26 | $ | 7.14 | ||||
| 2010 | ||||
| Reserve Replacement (MBoe) (1) |
104,704 | |||
| Reserve Replacement ratio |
521 | % | ||
| Drilling and Production Capital (in Millions) |
$ | 947 | ||
| All in Capital (in Millions) (2) |
$ | 2,438 | ||
| Drilling and Production finding Costs ($/Boe) |
9.04 | |||
| All in finding Costs ($/Boe) |
12.86 | |||
| (1) | Reserve Replacement without revisions of previous estimates |
| (2) | Total exploration and development adjusted for pipe with acquisition costs |
3
Operational and Financial Statistics
Information regarding the company’s production, pricing, costs and earnings is presented below:
| Three Months Ended December 31, |
Years Ended December 31, |
|||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| Production: |
||||||||||||||||
| Oil (MBbl)(1) |
2,612 | 731 | 7,386 | 2,894 | ||||||||||||
| Natural gas (MMcf) |
18,753 | 19,877 | 76,226 | 87,461 | ||||||||||||
| Oil equivalent (MBoe) |
5,738 | 4,044 | 20,090 | 17,471 | ||||||||||||
| Natural gas equivalent (MMcfe) |
34,425 | 24,263 | 120,542 | 104,823 | ||||||||||||
| Daily production (MBoed) |
62 | 44 | 55 | 48 | ||||||||||||
| Daily production (MMcfed) |
374 | 264 | 330 | 287 | ||||||||||||
| Average price per unit: |
||||||||||||||||
| Realized oil price per barrel - as reported (1) |
$ | 71.84 | $ | 69.22 | $ | 66.89 | $ | 55.62 | ||||||||
| Realized impact of derivatives per barrel (1) |
(3.69 | ) | 3.16 | 1.26 | 4.07 | |||||||||||
| Net realized price per barrel (1) |
$ | 68.15 | $ | 72.38 | $ | 68.15 | $ | 59.69 | ||||||||
| Realized natural gas price per Mcf - as reported |
$ | 3.07 | $ | 3.80 | $ | 3.68 | $ | 3.36 | ||||||||
| Realized impact of derivatives per Mcf |
(0.43 | ) | 3.50 | 2.52 | 3.84 | |||||||||||
| Net realized price per Mcf |
$ | 2.64 | $ | 7.30 | $ | 6.20 | $ | 7.20 | ||||||||
| Realized price per Boe - as reported |
$ | 42.73 | $ | 31.18 | $ | 38.56 | $ | 26.03 | ||||||||
| Net realized price per Boe - including impact of derivatives |
$ | 39.64 | $ | 48.95 | $ | 48.58 | $ | 45.95 | ||||||||
| Realized price per Mcfe - as reported |
$ | 7.12 | $ | 5.20 | $ | 6.43 | $ | 4.34 | ||||||||
| Net realized price per Mcfe - including impact of derivatives |
$ | 6.61 | $ | 8.16 | $ | 8.10 | $ | 7.66 | ||||||||
| Average cost per Boe: |
||||||||||||||||
| Lease operating |
$ | 11.42 | $ | 10.16 | $ | 11.84 | $ | 9.72 | ||||||||
| Production taxes |
1.75 | 0.21 | 1.45 | 0.23 | ||||||||||||
| General and administrative: |
||||||||||||||||
| General and administrative, excluding stock-based compensation |
6.73 | 4.17 | 7.06 | 4.43 | ||||||||||||
| Stock-based compensation |
2.35 | 1.55 | 1.88 | 1.30 | ||||||||||||
| Depletion |
13.51 | 12.00 | 13.70 | 10.08 | ||||||||||||
| Lease operating cost per Boe: |
||||||||||||||||
| Excluding offshore and tertiary recovery |
$ | 10.70 | $ | 7.88 | $ | 10.77 | $ | 8.45 | ||||||||
| Offshore operations |
25.52 | 25.36 | 25.74 | 20.01 | ||||||||||||
| Tertiary recovery operations |
34.50 | 98.93 | 53.17 | 65.10 | ||||||||||||
| Average cost per Mcfe: |
||||||||||||||||
| Lease operating |
$ | 1.90 | $ | 1.69 | $ | 1.97 | $ | 1.62 | ||||||||
| Production taxes |
0.29 | 0.04 | 0.24 | 0.04 | ||||||||||||
| General and administrative: |
||||||||||||||||
| General and administrative, excluding stock-based compensation |
1.12 | 0.70 | 1.18 | 0.74 | ||||||||||||
| Stock-based compensation |
0.39 | 0.26 | 0.31 | 0.22 | ||||||||||||
| Depletion |
2.25 | 2.00 | 2.28 | 1.68 | ||||||||||||
| Lease operating cost per Mcfe: |
||||||||||||||||
| Excluding offshore and tertiary recovery |
$ | 1.78 | $ | 1.31 | $ | 1.79 | $ | 1.41 | ||||||||
| Offshore operations |
4.25 | 4.23 | 4.29 | 3.34 | ||||||||||||
| Tertiary recovery operations |
5.75 | 16.49 | 8.86 | 10.85 | ||||||||||||
| Earnings per share: |
||||||||||||||||
| (Loss) income per share (applicable) available to common stockholders |
||||||||||||||||
| Basic |
$ | (0.53 | ) | $ | (2.36 | ) | $ | 0.52 | $ | (10.20 | ) | |||||
| Diluted |
(0.53 | ) | (2.36 | ) | 0.52 | (10.20 | ) | |||||||||
| Adjusted net (loss) income per share (applicable) available to common stockholders |
||||||||||||||||
| Basic |
$ | (0.12 | ) | $ | 0.14 | $ | 0.02 | $ | 0.80 | |||||||
| Diluted |
(0.07 | ) | 0.14 | 0.11 | 0.65 | |||||||||||
| Weighted average number of common shares outstanding (in thousands): |
||||||||||||||||
| Basic |
395,255 | 184,211 | 291,869 | 175,005 | ||||||||||||
| Diluted(2) |
491,329 | 238,912 | 387,059 | 229,337 | ||||||||||||
| (1) | Includes NGLs. |
| (2) | Includes shares considered antidilutive for calculating earnings per share in accordance with GAAP for certain periods presented. |
4
Discussion of 2010 Financial Results
Fourth Quarter
Oil and natural gas revenue increased 94% to $245.2 million in fourth quarter 2010 from $126.1 million in the same period of 2009 as a result of increases in oil production and realized reported oil prices. Oil production increased 257% to 2.6 MMBbls from fourth quarter 2009 production of 0.7 MMBbls mainly due to oil production from Permian Basin properties acquired in December 2009 and July 2010 and a continued focus on oil drilling. Fourth quarter 2010 total production increased 42% to 5.7 MMBoe (34.4 Bcfe) from 4.0 MMBoe (24.3 Bcfe) in fourth quarter 2009. Realized reported prices, which exclude the impact of derivative settlements, were $71.84 per barrel and $3.07 per Mcf during fourth quarter 2010. Realized reported prices in the same period of 2009 were $69.22 per barrel and $3.80 per Mcf.
Production expense increased 59% to $65.5 million in fourth quarter 2010 from $41.1 million in the same period of 2009 due to increases in production volumes and cost per unit produced as oil volumes comprised a larger percentage of the company’s total production in the 2010 period. Fourth quarter 2010 production expense was $11.42 per Boe ($1.90 per Mcfe) compared to fourth quarter 2009 production expense of $10.16 per Boe ($1.69 per Mcfe).
Depletion per unit in fourth quarter 2010 was $13.51 per Boe ($2.25 per Mcfe) compared to $12.00 per Boe ($2.00 per Mcfe) in the same period of 2009. The increase in rate per unit primarily was a result of an increase in the company’s depreciable oil and natural gas properties, mainly due to property acquisitions in December 2009 and July 2010.
Full Year
Oil and natural gas revenue increased 70% to $774.8 million in 2010 from $454.7 million in 2009 as a result of increases in oil production and realized reported prices. Oil production increased 155% to 7.4 MMBbls from 2009 production of 2.9 MMBbls mainly due to oil production from Permian Basin properties acquired in December 2009 and July 2010 and the continued focus on oil drilling. Total 2010 production increased 15% to 20.1 MMBoe (120.5 Bcfe) from 2009 production of 17.5 MMBoe (104.8 Bcfe). Realized reported prices were $66.89 per barrel and $3.68 per Mcf during 2010 compared to $55.62 per barrel and $3.36 per Mcf in 2009.
Production expense increased 40% to $237.9 million in 2010 from $169.9 million in 2009 due to higher total production volume as well as a larger percentage of oil produced relative to total volumes. Production expense was $11.84 per Boe ($1.97 per Mcfe) in 2010 compared to $9.72 per Boe ($1.62 per Mcfe) in 2009.
Depletion per unit in 2010 was $13.70 per barrel ($2.28 per Mcf) compared to $10.08 per barrel ($1.68 per Mcf) in 2009 due to an increase in the company’s depreciable oil and natural gas properties, mainly due to acquisitions in December 2009 and July 2010.
5
Capital Expenditures
The table below summarizes the company’s capital expenditures for the quarters and years ended December 31, 2010 and 2009:
| Three Months Ended December 31, |
Years Ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Drilling and production |
||||||||||||||||
| Permian Basin |
$ | 166,044 | $ | 24,178 | $ | 446,230 | $ | 69,277 | ||||||||
| Mid-Continent |
63,533 | 6,300 | 146,455 | 41,993 | ||||||||||||
| WTO |
41,125 | 52,731 | 299,910 | 249,187 | ||||||||||||
| Tertiary |
10,024 | 1,852 | 23,030 | 14,057 | ||||||||||||
| Other |
2,252 | 10,164 | 31,167 | 74,765 | ||||||||||||
| 282,978 | 95,225 | 946,792 | 449,279 | |||||||||||||
| Leasehold and seismic |
||||||||||||||||
| Permian Basin |
5,540 | 2,394 | 27,582 | 4,413 | ||||||||||||
| Mid-Continent |
37,798 | 1,902 | 63,641 | 3,390 | ||||||||||||
| WTO |
323 | 772 | 7,239 | 10,461 | ||||||||||||
| Tertiary |
— | — | 88 | — | ||||||||||||
| Other |
1,198 | 3,605 | 4,515 | 10,033 | ||||||||||||
| 44,859 | 8,673 | 103,065 | 28,297 | |||||||||||||
| Pipe inventory(1) |
(6,089 | ) | (18,613 | ) | (22,962 | ) | 77,652 | |||||||||
| Total exploration and development(2) |
321,748 | 85,285 | 1,026,895 | 555,228 | ||||||||||||
| Drilling and oil field services |
5,149 | 1,320 | 31,658 | 4,090 | ||||||||||||
| Midstream |
1,499 | 8,637 | 48,401 | 52,425 | ||||||||||||
| Other - general |
5,664 | 7,699 | 22,699 | 33,399 | ||||||||||||
| Total capital expenditures, excluding acquisitions |
334,060 | 102,941 | 1,129,653 | 645,142 | ||||||||||||
| Acquisition(3) |
— | 795,074 | 138,428 | 795,074 | ||||||||||||
| Total capital expenditures |
$ | 334,060 | $ | 898,015 | $ | 1,268,081 | $ | 1,440,216 | ||||||||
| (1) | Pipe inventory expenditures for the three-month periods ended December 31, 2010 and 2009 and year ended December 31, 2010 represent transfers of pipe to the full cost pool for use in drilling and production activities. |
| (2) | 2010 exploration and development expenditures exclude $105.0 million estimated loss on construction contract. |
| (3) | 2010 acquisition expenditures exclude common stock valued at approximately $1.25 billion issued in connection with and tax liability adjustments resulting from the Arena acquisition. |
6
Derivative Contracts
The table below sets forth the company’s oil swaps and natural gas price and basis swaps for the years 2011 through 2013 as of February 18, 2011. During the fourth quarter of 2010, the company settled various oil swaps with contractual maturity dates after December 31, 2010, and entered into additional oil swaps for 2013 and additional natural gas swaps for 2011 and 2012. In addition to price swaps, the company has 3.2 Bcf of natural gas collars in place for the second half of 2012 through 2015, with a floor of $4.00 per Mcf and an average cap of $7.66 per Mcf. The company currently does not have natural gas swaps for 2013.
| Year Ending | ||||||||||||
| 12/31/2011 | 12/31/2012 | 12/31/2013 | ||||||||||
| Oil Swaps |
||||||||||||
| Volume (MMBbls) |
8.29 | 9.55 | 7.94 | |||||||||
| Swap |
$ | 86.08 | $ | 87.10 | $ | 92.21 | ||||||
| Natural Gas Swaps |
||||||||||||
| Volume (Bcf) |
59.57 | 26.85 | 0.00 | |||||||||
| Swap |
$ | 4.69 | $ | 5.15 | NM | |||||||
| Natural Gas Basis Swaps |
||||||||||||
| Volume (Bcf) |
104.03 | 113.46 | 14.60 | |||||||||
| Swap |
$ | 0.47 | $ | 0.55 | $ | 0.46 | ||||||
7
Balance Sheet
The company’s capital structure at December 31, 2010 and 2009 is presented below:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (in thousands) | ||||||||
| Cash and cash equivalents |
$ | 5,863 | $ | 7,861 | ||||
| Current maturities of long-term debt |
$ | 7,293 | $ | 12,003 | ||||
| Long-term debt (net of current maturities) |
||||||||
| Senior credit facility |
340,000 | — | ||||||
| Notes payable - Drilling rig fleet and oil field services equipment |
— | 6,304 | ||||||
| Mortgage |
16,029 | 17,020 | ||||||
| Senior Notes |
||||||||
| Senior Floating Rate Notes due 2014 |
350,000 | 350,000 | ||||||
| 8.625% Senior Notes due 2015 |
650,000 | 650,000 | ||||||
| 9.875% Senior Notes due 2016, net |
352,707 | 351,021 | ||||||
| 8.0% Senior Notes due 2018 |
750,000 | 750,000 | ||||||
| 8.75% Senior Notes due 2020, net |
443,057 | 442,590 | ||||||
| Total debt |
2,909,086 | 2,578,938 | ||||||
| Stockholders’ equity |
||||||||
| Preferred stock |
8 | 5 | ||||||
| Common stock |
398 | 203 | ||||||
| Additional paid-in capital |
4,528,912 | 2,961,613 | ||||||
| Treasury stock, at cost |
(3,547 | ) | (25,079 | ) | ||||
| Accumulated deficit |
(2,989,576 | ) | (3,142,699 | ) | ||||
| Total SandRidge Energy, Inc. stockholders’ equity (deficit) |
1,536,195 | (205,957 | ) | |||||
| Noncontrolling interest |
11,288 | 10,052 | ||||||
| Total capitalization |
$ | 4,456,569 | $ | 2,383,033 | ||||
The company’s total debt (short-term and long-term) increased $330 million during 2010 due to draws on its senior credit facility to partially fund capital expenditures, including the cash portion of the Arena purchase price. At February 22, 2011, the company had $382 million drawn under its senior credit facility, leaving $434 million of available liquidity (including the impact of letters of credit). The company was in compliance with all of the financial and other covenants contained in its debt agreements at December 31, 2010.
8
Operational Guidance
| Year Ending | ||||||||
| December 31, 2011 | ||||||||
| Initial Projection as of |
Updated Projection as of February 24, 2011 |
|||||||
| Production |
||||||||
| Oil (MMBbls) (1) |
11.2 | 12.3 | ||||||
| Natural Gas (Bcf) |
62.5 | 66.5 | ||||||
| Total (MMBoe) |
21.6 | 23.3 | ||||||
| Differentials |
||||||||
| Oil (1) |
$ | 11.00 | $ | 11.00 | ||||
| Natural Gas |
0.75 | 0.75 | ||||||
| Costs per Boe |
||||||||
| Lifting |
$12.10 - $13.40 | $11.80 -$13.10 | ||||||
| Production Taxes |
1.95 - 2.15 | 2.05 - 2.30 | ||||||
| DD&A - oil & gas |
16.00 - 17.70 | 12.80 - 14.20 | ||||||
| DD&A - other |
2.40 - 2.65 | 2.40 - 2.65 | ||||||
| Total DD&A |
$18.40 -$20.35 | $15.20 - $16.85 | ||||||
| G&A - cash |
4.50 - 5.00 | 4.25 - 4.75 | ||||||
| G&A - stock |
1.60 - 1.75 | 1.55 - 1.75 | ||||||
| Total G&A |
$6.10 - $6.75 | $5.80 - $6.50 | ||||||
| Interest Expense |
$10.15 -$11.25 | $10.20 - $11.30 | ||||||
| Corporate Tax Rate |
0 | % | 0 | % | ||||
| Deferral Rate |
0 | % | 0 | % | ||||
| Shares Outstanding at End of Period (in millions) |
||||||||
| Common Stock |
412.7 | 415.6 | ||||||
| Preferred Stock (as converted) |
51.5 | 90.1 | ||||||
| Fully Diluted |
464.2 | 505.7 | ||||||
| Capital Expenditures ($ in millions) |
||||||||
| Exploration and Production |
$ | 960 | $ | 1,065 | ||||
| Land and Seismic |
50 | 105 | ||||||
| Total Exploration and Production |
$ | 1,010 | $ | 1,170 | ||||
| Oil Field Services |
25 | 25 | ||||||
| Midstream and Other |
65 | 105 | ||||||
| Total Capital Expenditures |
$ | 1,100 | $ | 1,300 | ||||
| (1) | Includes NGLs. |
2011 Operational Guidance: The company has increased production guidance to 23.3 MMBoe from 21.6 MMBoe. Lifting costs are projected based upon costs realized in 2010. Projected production taxes have increased due to increased projected oil revenues. Projected DD&A – oil & gas has decreased due to an increase in proved reserves. Other projected per unit costs have decreased primarily due to the anticipated increase in production. Total planned capital expenditures have increased to $1.3 billion from $1.1 billion, primarily due to planned increases in drilling activity in the Mid-Continent, workovers and recompletions in the Permian Basin, land acquisitions in the Mid-Continent area, and anticipated midstream and other expenditures. Common stock outstanding has been updated to reflect recent and projected employee stock compensation, while preferred stock outstanding now includes the company’s November 2010 issuance of 7% convertible perpetual preferred stock.
9
Non-GAAP Financial Measures
Operating cash flow, adjusted EBITDA, adjusted net (loss applicable) income available and PV-10 are non-GAAP financial measures.
The company defines operating cash flow as net cash provided by operating activities before changes in operating assets and liabilities. It defines EBITDA as net (loss) income before income tax expense (benefit), interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA excluding interest income, realized gains on out-of-period derivative contract settlements, loss on the sale of assets, acquisition costs, settlements for prior claims and other various non-cash items (including asset impairments, (loss) income from equity investments, noncontrolling interest, stock-based compensation, unrealized loss on derivative contracts and provision for doubtful accounts).
Operating cash flow and adjusted EBITDA are supplemental financial measures used by the company’s management and by securities analysts, investors, lenders, rating agencies and others who follow the industry as an indicator of the company’s ability to internally fund exploration and development activities and to service or incur additional debt. The company also uses these measures because operating cash flow and adjusted EBITDA relate to the timing of cash receipts and disbursements that the company may not control and may not relate to the period in which the operating activities occurred. Further, operating cash flow and adjusted EBITDA allow the company to compare its operating performance and return on capital with those of other companies without regard to financing methods and capital structure. These measures should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with generally accepted accounting principles (“GAAP”). Adjusted EBITDA should not be considered as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, the company’s adjusted EBITDA may not be comparable to similarly titled measures used by other companies.
Management also uses the supplemental financial measure of adjusted net (loss applicable) income available to common stockholders, which excludes asset impairments, unrealized loss on derivative contracts, realized gains on out-of-period derivative contract settlements, acquisition costs, settlements for prior claims and loss on the sale of assets from net (loss applicable) income available to common stockholders. Management uses this financial measure as an indicator of the company’s operational trends and performance relative to other oil and natural gas companies and believes it is more comparable to earnings estimates provided by securities analysts. Adjusted net (loss applicable) income available to common stockholders is not a measure of financial performance under GAAP and should not be considered a substitute for net (loss applicable) income available to common stockholders.
PV-10 represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Management uses PV-10 as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the tax-paying status of the entity.
The tables below reconcile the most directly comparable GAAP financial measures to operating cash flow, EBITDA, adjusted EBITDA, adjusted net income available (loss applicable) to common stockholders and PV-10.
10
Reconciliation of Net Cash Provided by Operating Activities to Operating Cash Flow
| Three Months Ended December 31, |
Years Ended December 31, |
|||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Net cash provided by operating activities |
$ | 50,915 | $ | 34,475 | $ | 390,128 | $ | 311,559 | ||||||||
| Add |
||||||||||||||||
| Changes in operating assets and liabilities |
21,367 | 74,429 | 20,030 | 106,022 | ||||||||||||
| Operating cash flow |
$ | 72,282 | $ | 108,904 | $ | 410,158 | $ | 417,581 | ||||||||
Reconciliation of Net (Loss) Income to EBITDA and Adjusted EBITDA
| Three Months Ended December 31, |
Years
Ended December 31, |
|||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Net (loss) income |
$ | (196,475 | ) | $ | (428,243 | ) | $ | 190,565 | $ | (1,775,590 | ) | |||||
| Adjusted for |
||||||||||||||||
| Income tax expense (benefit) |
10,406 | (4,602 | ) | (446,680 | ) | (8,716 | ) | |||||||||
| Interest expense(1) |
60,856 | 50,630 | 239,343 | 186,137 | ||||||||||||
| Depreciation and amortization - other |
14,212 | 12,014 | 50,776 | 50,865 | ||||||||||||
| Depreciation and depletion - oil and natural gas |
77,501 | 48,524 | 275,335 | 176,027 | ||||||||||||
| EBITDA |
(33,500 | ) | (321,677 | ) | 309,339 | (1,371,277 | ) | |||||||||
| Asset impairment |
— | 402,732 | — | 1,707,150 | ||||||||||||
| Provision for doubtful accounts |
27 | 152 | 129 | 214 | ||||||||||||
| Inventory obsolescence |
(200 | ) | — | — | — | |||||||||||
| Loss (income) from equity investments |
— | 7 | — | (1,020 | ) | |||||||||||
| Interest income |
(60 | ) | (88 | ) | (296 | ) | (375 | ) | ||||||||
| Stock-based compensation |
13,507 | 6,267 | 37,681 | 22,793 | ||||||||||||
| Unrealized losses on derivative contracts |
148,240 | 62,736 | 283,604 | 200,049 | ||||||||||||
| Realized gains on out-of-period derivative contract settlements |
(3,847 | ) | — | (23,202 | ) | — | ||||||||||
| Other non-cash expense |
(243 | ) | — | (371 | ) | — | ||||||||||
| Loss on sale of assets |
2,385 | 60 | 2,424 | 26,419 | ||||||||||||
| Acquisition costs |
1,941 | 255 | 17,375 | 255 | ||||||||||||
| Settlement for prior claims |
2,200 | — | 18,200 | — | ||||||||||||
| Adjusted EBITDA |
$ | 130,450 | $ | 150,444 | $ | 644,883 | $ | 584,208 | ||||||||
| (1) | Excludes unrealized (gain) loss on interest rate swaps of ($3.1) million and ($1.3) million for the three-month periods ended December 31, 2010 and 2009, respectively, and $8.4 million and ($0.4) million for the years ended December 31, 2010 and 2009, respectively. |
Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA
| Three Months Ended December 31, |
Years Ended December 31, |
|||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (in thousands) | ||||||||||||||||
| Net cash provided by operating activities |
$ | 50,915 | $ | 34,475 | $ | 390,128 | $ | 311,559 | ||||||||
| Changes in operating assets and liabilities |
21,367 | 74,429 | 20,030 | 106,022 | ||||||||||||
| Interest expense(1) |
60,856 | 50,630 | 239,343 | 186,137 | ||||||||||||
| Realized gains on out-of-period derivative contract settlements |
(3,847 | ) | — | (23,202 | ) | — | ||||||||||
| Acquisition costs |
1,941 | 255 | 17,375 | 255 | ||||||||||||
| Settlement for prior claims |
2,200 | — | 18,200 | — | ||||||||||||
| Other non-cash items |
(2,982 | ) | (9,345 | ) | (16,991 | ) | (19,765 | ) | ||||||||
| Adjusted EBITDA |
$ | 130,450 | $ | 150,444 | $ | 644,883 | $ | 584,208 | ||||||||
| (1) | Excludes unrealized (gain) loss on interest rate swaps of ($3.1) million and ($1.3) million for the three-month periods ended December 31, 2010 and 2009, respectively, and $8.4 million and ($0.4) million for the years ended December 31, 2010 and 2009, respectively. |
11
Reconciliation of (Loss Applicable) Income Available to Common Stockholders to Adjusted Net
(Loss Applicable) Income Available to Common Stockholders
| Three Months Ended December 31, | Years Ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (in thousands, except per share data) | ||||||||||||||||
| (Loss applicable) income available to common stockholders |
$ | (208,023 | ) | $ | (434,240 | ) | $ | 153,123 | $ | (1,784,403 | ) | |||||
| Tax benefit resulting from Arena acquisition |
8,937 | — | (447,500 | ) | — | |||||||||||
| Asset impairment |
— | 402,732 | — | 1,707,150 | ||||||||||||
| Unrealized losses on derivative contracts |
148,240 | 62,736 | 283,604 | 200,049 | ||||||||||||
| Realized gains on out-of-period derivative contract settlements |
(3,847 | ) | — | (23,202 | ) | — | ||||||||||
| Loss on sale of assets |
2,385 | 60 | 2,424 | 26,419 | ||||||||||||
| Acquisition costs |
1,941 | 255 | 17,375 | 255 | ||||||||||||
| Settlement for prior claims |
2,200 | — | 18,200 | — | ||||||||||||
| Effect of income taxes |
1,191 | (4,952 | ) | 955 | (9,447 | ) | ||||||||||
| Adjusted net (loss applicable) income available to common stockholders |
(46,976 | ) | 26,591 | 4,979 | 140,023 | |||||||||||
| Preferred stock dividends |
11,548 | 5,997 | 37,442 | 8,813 | ||||||||||||
| Total adjusted net (loss) income |
$ | (35,428 | ) | $ | 32,588 | $ | 42,421 | $ | 148,836 | |||||||
| Weighted average number of common shares outstanding |
||||||||||||||||
| Basic |
395,255 | 184,211 | 291,869 | 175,005 | ||||||||||||
| Diluted(1) |
491,329 | 238,912 | 387,059 | 229,337 | ||||||||||||
| Total adjusted net (loss) income |
||||||||||||||||
| Per share - basic |
$ | (0.12 | ) | $ | 0.14 | $ | 0.02 | $ | 0.80 | |||||||
| Per share - diluted |
$ | (0.07 | ) | $ | 0.14 | $ | 0.11 | $ | 0.65 | |||||||
| (1) | Weighted average fully diluted common shares outstanding for certain periods presented includes shares that are considered antidilutive for calculating earnings per share in accordance with GAAP. |
Reconciliation of Standardized Measure of Discounted Net Cash Flows to PV-10
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| (in millions) | ||||||||
| Standardized Measure of discounted net cash flows |
$ | 3,683.5 | $ | 1,561.0 | ||||
| Present value of future net income tax expense discounted at 10%(1) |
825.7 | — | ||||||
| PV-10 |
$ | 4,509.2 | $ | 1,561.0 | ||||
| (1) | Due to an excess of tax basis over estimated discounted net cash flows from future production and a full valuation allowance on net deferred tax assets at December 31, 2009, there was no effect of income taxes in the Standardized Measure at December 31, 2009 |
12
Conference Call Information
The company will host a conference call to discuss these results on Friday, February 25, 2011 at 8:00 am CST. The telephone number to access the conference call from within the U.S. is 800-299-8538 and from outside the U.S. is 617-786-2902. The passcode for the call is 48052538. An audio replay of the call will be available from February 25, 2011 until 11:59 pm CST on March 24, 2011. The number to access the conference call replay from within the U.S. is 888-286-8010 and from outside the U.S. is 617-801-6888. The passcode for the replay is 13652506.
A live audio webcast of the conference call also will be available via SandRidge’s website, www.sandridgeenergy.com, under Investor Relations/Events. The webcast will be archived for replay on the company’s website for 30 days.
4th Annual Investor/Analyst Meeting
March 1, 2011 (Tuesday) – New York, NY at the Grand Hyatt New York, 109 East 42nd Street at 8:00 am EST
Conference Participation
SandRidge Energy, Inc. will participate in the following upcoming events:
| • | March 4, 2011 – Simmons & Company International 11th Annual Energy Conference; Las Vegas, NV |
| • | March 7, 2011 – Raymond James & Assoc. 32nd Annual Institutional Investors Conference; Orlando, FL |
| • | March 25, 2011 – Barclays Capital 2011 High Yield Bond and Syndicated Loan Conference; Orlando, FL |
| • | March 29, 2011 – Howard Weil 39th Annual Energy Conference; New Orleans, LA |
| • | April 6, 2011 – UBS 2011 Energy Mini-Conference; New York, NY |
| • | April 11, 2011 – IPAA 2011 OGIS; New York, NY |
At 8:00 am Central Time on the day of each presentation, the corresponding slides and webcast information will be accessible on the Investor Relations portion of the company’s website at www.sandridgeenergy.com. Please check the website for updates regularly as this schedule is subject to change. Also, please note that SandRidge Energy, Inc. intends for its website to be used as a reliable source of information for all future events in which it may participate. Slides and webcasts (where applicable) will be archived and available for at least 30 days after each presentation.
First Quarter 2011 Earnings Release and Conference Call
May 5, 2011 (Thursday) – Earnings press release after market close
May 6, 2011 (Friday) – Earnings conference call at 8:00 am CDT
13
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(in thousands, except per share data)
| Three Months Ended | ||||||||||||||||
| December 31, | Years Ended December 31, | |||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| (Unaudited) | ||||||||||||||||
| Revenues |
||||||||||||||||
| Oil and natural gas |
$ | 245,185 | $ | 126,077 | $ | 774,763 | $ | 454,705 | ||||||||
| Drilling and services |
13,630 | 6,379 | 28,543 | 23,586 | ||||||||||||
| Midstream and marketing |
26,250 | 23,977 | 100,118 | 86,028 | ||||||||||||
| Other |
8,004 | 6,644 | 28,312 | 26,725 | ||||||||||||
| Total revenues |
293,069 | 163,077 | 931,736 | 591,044 | ||||||||||||
| Expenses |
||||||||||||||||
| Production |
65,496 | 41,069 | 237,863 | 169,880 | ||||||||||||
| Production taxes |
10,024 | 857 | 29,170 | 4,010 | ||||||||||||
| Drilling and services |
9,948 | 8,496 | 22,368 | 28,380 | ||||||||||||
| Midstream and marketing |
24,085 | 22,525 | 90,149 | 80,608 | ||||||||||||
| Depreciation and depletion - oil and natural gas |
77,501 | 48,524 | 275,335 | 176,027 | ||||||||||||
| Depreciation and amortization - other |
14,212 | 12,014 | 50,776 | 50,865 | ||||||||||||
| Impairment |
— | 402,732 | — | 1,707,150 | ||||||||||||
| General and administrative |
52,146 | 23,133 | 179,565 | 100,256 | ||||||||||||
| Loss (gain) on derivative contracts |
165,250 | (7,805 | ) | 50,872 | (147,527 | ) | ||||||||||
| Loss on sale of assets |
2,385 | 60 | 2,424 | 26,419 | ||||||||||||
| Total expenses |
421,047 | 551,605 | 938,522 | 2,196,068 | ||||||||||||
| Loss from operations |
(127,978 | ) | (388,528 | ) | (6,786 | ) | (1,605,024 | ) | ||||||||
| Other income (expense) |
||||||||||||||||
| Interest income |
60 | 88 | 296 | 375 | ||||||||||||
| Interest expense |
(57,749 | ) | (49,323 | ) | (247,738 | ) | (185,691 | ) | ||||||||
| (Loss) income from equity investments |
— | (7 | ) | — | 1,020 | |||||||||||
| Other income, net |
496 | 7,172 | 2,558 | 7,272 | ||||||||||||
| Total other expense |
(57,193 | ) | (42,070 | ) | (244,884 | ) | (177,024 | ) | ||||||||
| Loss before income taxes |
(185,171 | ) | (430,598 | ) | (251,670 | ) | (1,782,048 | ) | ||||||||
| Income tax expense (benefit) |
10,406 | (4,602 | ) | (446,680 | ) | (8,716 | ) | |||||||||
| Net (loss) income |
(195,577 | ) | (425,996 | ) | 195,010 | (1,773,332 | ) | |||||||||
| Less: net income attributable to noncontrolling interest |
898 | 2,247 | 4,445 | 2,258 | ||||||||||||
| Net (loss) income attributable to SandRidge Energy, Inc. |
(196,475 | ) | (428,243 | ) | 190,565 | (1,775,590 | ) | |||||||||
| Preferred stock dividends |
11,548 | 5,997 | 37,442 | 8,813 | ||||||||||||
| (Loss applicable) income available to SandRidge Energy, Inc. common stockholders |
$ | (208,023 | ) | $ | (434,240 | ) | $ | 153,123 | $ | (1,784,403 | ) | |||||
| Earnings (loss) per share |
||||||||||||||||
| Basic |
$ | (0.53 | ) | $ | (2.36 | ) | $ | 0.52 | $ | (10.20 | ) | |||||
| Diluted |
$ | (0.53 | ) | $ | (2.36 | ) | $ | 0.52 | $ | (10.20 | ) | |||||
| Weighted average number of common shares outstanding |
||||||||||||||||
| Basic |
395,255 | 184,211 | 291,869 | 175,005 | ||||||||||||
| Diluted |
395,255 | 184,211 | 315,349 | 175,005 | ||||||||||||
14
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(in thousands, except per share data)
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| ASSETS | ||||||||
| Current assets |
||||||||
| Cash and cash equivalents |
$ | 5,863 | $ | 7,861 | ||||
| Accounts receivable, net |
146,118 | 105,476 | ||||||
| Derivative contracts |
5,028 | 105,994 | ||||||
| Inventories |
3,945 | 3,707 | ||||||
| Costs in excess of billings |
— | 12,346 | ||||||
| Other current assets |
14,636 | 20,580 | ||||||
| Total current assets |
175,590 | 255,964 | ||||||
| Oil and natural gas properties, using full cost method of accounting |
||||||||
| Proved |
8,159,924 | 5,913,408 | ||||||
| Unproved |
547,953 | 281,811 | ||||||
| Less: accumulated depreciation, depletion and impairment |
(4,483,736 | ) | (4,223,437 | ) | ||||
| 4,224,141 | 1,971,782 | |||||||
| Other property, plant and equipment, net |
509,724 | 461,861 | ||||||
| Restricted deposits |
27,886 | 32,894 | ||||||
| Goodwill |
234,356 | — | ||||||
| Other assets |
59,751 | 57,816 | ||||||
| Total assets |
$ | 5,231,448 | $ | 2,780,317 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities |
||||||||
| Current maturities of long-term debt |
$ | 7,293 | $ | 12,003 | ||||
| Accounts payable and accrued expenses |
376,922 | 203,908 | ||||||
| Billings and estimated contract loss in excess of costs incurred |
31,474 | — | ||||||
| Derivative contracts |
103,409 | 7,080 | ||||||
| Asset retirement obligation |
25,360 | 2,553 | ||||||
| Total current liabilities |
544,458 | 225,544 | ||||||
| Long-term debt |
2,901,793 | 2,566,935 | ||||||
| Other long-term obligations |
19,024 | 14,099 | ||||||
| Derivative contracts |
124,173 | 61,060 | ||||||
| Asset retirement obligation |
94,517 | 108,584 | ||||||
| Total liabilities |
3,683,965 | 2,976,222 | ||||||
| Commitments and contingencies |
||||||||
| Equity |
||||||||
| SandRidge Energy, Inc. stockholders’ equity |
||||||||
| Preferred stock, $0.001 par value, 50,000 shares authorized |
||||||||
| 8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2010 and December 31, 2009; aggregate liquidation preference of $265,000 |
3 | 3 | ||||||
| 6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at December 31, 2010 and December 31, 2009; aggregate liquidation preference of $200,000 |
2 | 2 | ||||||
| 7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at December 31, 2010; aggregate liquidation preference of $300,000 |
3 | — | ||||||
| Common stock, $0.001 par value, 800,000 and 400,000 shares authorized at December 31, 2010 and December 31, 2009, respectively; 406,830 issued and 406,360 outstanding at December 31, 2010 and 210,581 issued and 208,715 outstanding at December 31, 2009 |
398 | 203 | ||||||
| Additional paid-in capital |
4,528,912 | 2,961,613 | ||||||
| Treasury stock, at cost |
(3,547 | ) | (25,079 | ) | ||||
| Accumulated deficit |
(2,989,576 | ) | (3,142,699 | ) | ||||
| Total SandRidge Energy, Inc. stockholders’ equity (deficit) |
1,536,195 | (205,957 | ) | |||||
| Noncontrolling interest |
11,288 | 10,052 | ||||||
| Total equity (deficit) |
1,547,483 | (195,905 | ) | |||||
| Total liabilities and equity |
$ | 5,231,448 | $ | 2,780,317 | ||||
15
SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(in thousands)
| Years Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
| Net income (loss) |
$ | 195,010 | $ | (1,773,332 | ) | |||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities |
||||||||
| Provision for doubtful accounts |
129 | 214 | ||||||
| Depreciation, depletion and amortization |
326,111 | 226,892 | ||||||
| Impairment |
— | 1,707,150 | ||||||
| Debt issuance costs amortization |
11,006 | 7,477 | ||||||
| Discount amortization on long-term debt |
2,153 | 990 | ||||||
| Deferred income taxes |
(447,500 | ) | — | |||||
| Unrealized loss on derivative contracts |
283,604 | 200,049 | ||||||
| Loss on sale of assets |
2,424 | 26,419 | ||||||
| Investment income |
(460 | ) | (51 | ) | ||||
| Income from equity investments |
— | (1,020 | ) | |||||
| Stock-based compensation |
37,681 | 22,793 | ||||||
| Changes in operating assets and liabilities increasing (decreasing) cash |
||||||||
| Receivables |
(11,480 | ) | 8,760 | |||||
| Inventories |
(238 | ) | 61 | |||||
| Other current assets |
8,079 | 47,317 | ||||||
| Billings in excess of costs/costs in excess of billings |
(61,180 | ) | (26,490 | ) | ||||
| Other assets and liabilities, net |
2,667 | (26,937 | ) | |||||
| Accounts payable and accrued expenses |
42,122 | (108,733 | ) | |||||
| Net cash provided by operating activities |
390,128 | 311,559 | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
| Capital expenditures for property, plant and equipment(1) |
(1,044,371 | ) | (715,205 | ) | ||||
| Acquisitions of assets, net $39,518 and $0 cash received |
(138,428 | ) | (795,074 | ) | ||||
| Proceeds from sale of assets |
204,951 | 263,220 | ||||||
| Deposit received on pending asset sale |
10,000 | — | ||||||
| Refunds of restricted deposits |
5,095 | — | ||||||
| Net cash used in investing activities |
(962,753 | ) | (1,247,059 | ) | ||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
| Proceeds from borrowings |
2,117,914 | 2,619,607 | ||||||
| Repayments of borrowings |
(1,789,919 | ) | (2,416,975 | ) | ||||
| Dividends paid-preferred |
(28,525 | ) | — | |||||
| Noncontrolling interest distributions |
(3,515 | ) | (26 | ) | ||||
| Noncontrolling interest contributions |
306 | — | ||||||
| Proceeds from issuance of common stock, net |
— | 324,830 | ||||||
| Proceeds from issuance of convertible perpetual preferred stock, net |
290,704 | 443,210 | ||||||
| Stock-based compensation excess tax benefit |
15 | (3,864 | ) | |||||
| Purchase of treasury stock |
(7,169 | ) | (5,747 | ) | ||||
| Derivative settlements |
3,356 | — | ||||||
| Debt issuance costs |
(12,540 | ) | (18,310 | ) | ||||
| Net cash provided by financing activities |
570,627 | 942,725 | ||||||
| NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS |
(1,998 | ) | 7,225 | |||||
| CASH AND CASH EQUIVALENTS, beginning of year |
7,861 | 636 | ||||||
| CASH AND CASH EQUIVALENTS, end of year |
$ | 5,863 | $ | 7,861 | ||||
| Supplemental Disclosure of Cash Flow Information |
||||||||
| Cash paid for interest, net of amounts capitalized |
$ | 211,377 | $ | 171,994 | ||||
| Cash (received) paid for income taxes |
(1,508 | ) | 2,908 | |||||
| Supplemental Disclosure of Noncash Investing and Financing Activities |
||||||||
| Change in accrued capital expenditures(1) |
$ | 85,282 | $ | (70,063 | ) | |||
| Convertible perpetual preferred stock dividends payable |
17,363 | 8,813 | ||||||
| Adjustment to oil and natural gas properties for estimated contract loss |
105,000 | — | ||||||
| Common stock issued in connection with acquisition |
1,246,334 | — | ||||||
| Stock issued to satisfy settlement |
12,200 | — | ||||||
| (1) | Capital expenditures on an accrual basis were $1,129,653 and $645,142 for the years ended December 31, 2010 and 2009, respectively. |
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For further information, please contact:
Kevin R. White
Senior Vice President
SandRidge Energy, Inc.
123 Robert S. Kerr Avenue
Oklahoma City, OK 73102-6406
(405) 429-5515
Cautionary Note to Investors - This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, but not limited to, the information appearing under the heading “Operational Guidance.” These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of rates of return, drilling rigs operating, drilling locations, acquisition, divestiture and monetization plans, oil and natural gas production, derivative transactions, shares outstanding, pricing differentials, operating costs and capital spending, tax rates, and descriptions of our development plans. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of oil and natural gas prices, our success in discovering, estimating, developing and replacing oil and natural gas reserves, actual decline curves and the actual effect of adding compression to gas wells, the availability and terms of capital, the ability of counterparties to transactions with us to meet their obligations, our timely execution of hedge transactions, credit conditions of global capital markets, changes in economic conditions, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide and greenhouse gas emissions, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Part I, Item 1A - “Risk Factors” of each of our Annual Report on Form 10-K for the year ended December 31, 2009 and our Quarterly Reports on Form 10-Q for the quarters ended June 30, 2010 and September 30, 2010; and in comparable “risk factors” sections of our Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q filed after the date of this press release. All of the forward-looking statements made in this press release are qualified by these cautionary statements. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to update or revise any forward-looking statements.
SandRidge Energy, Inc. is an oil and natural gas company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge and its subsidiaries also own and operate gas gathering and processing facilities and CO2 treating and transportation facilities and conduct marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and operates a drilling rig and related oil field services business. SandRidge focuses its exploration and production activities in the West Texas Overthrust, Permian Basin, Mid-Continent, Cotton Valley Trend in East Texas, Gulf Coast and the Gulf of Mexico. SandRidge’s internet address is www.sandridgeenergy.com.
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