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Exhibit 99.1

SandRidge Energy, Inc. Reports Financial and Operational Results for Fourth Quarter and Full Year 2008

Oklahoma City, Oklahoma, February 26, 2009 — SandRidge Energy, Inc. (NYSE: SD) today announced financial and operational results for the quarter and year ended December 31, 2008.

Financial Results

Fourth Quarter

	•		Adjusted EBITDA increased 17% to $158.1 million from $135.5 million in fourth quarter 2007

	•		Operating cash flow increased 5% to $114.7 million from $109.2 million in fourth quarter 2007

	•		Adjusted net income available to common stockholders (which excludes non-cash asset impairments and unrealized gains or losses on derivative contracts) was $10.3 million, or $0.06 per share fully diluted, in fourth quarter 2008 compared to adjusted net income available to common stockholders of $11.1 million, or $0.09 per share fully diluted, in fourth quarter 2007

	•		Net loss applicable to common stockholders (including $1.68 billion after-tax non-cash full cost ceiling impairment due to sharp fourth quarter declines in natural gas and crude oil prices) was $1.6 billion, or $9.78 per share fully diluted, compared to net income available to common stockholders of $4.9 million, or $0.04 per share fully diluted, in fourth quarter 2007

Full Year

	•		Adjusted EBITDA increased 74% to $688.3 million from $395.7 million in 2007

	•		Operating cash flow increased 83% to $540.3 million from $295.6 million in 2007

	•		Adjusted net income available to common stockholders (which excludes non-cash asset impairments and unrealized gains or losses on derivative contracts) was $151.5 million, or $0.97 per share fully diluted, in 2008 compared to an adjusted net loss applicable to common stockholders of $6.2 million, or $0.06 per share fully diluted, in 2007

	•		Net loss applicable to common stockholders (including $1.68 billion fourth quarter after-tax non-cash full cost ceiling impairment) was $1.5 billion, or $9.36 per share fully diluted, compared to net income available to common stockholders of $10.3 million, or $0.09 per share fully diluted, in 2007

Adjusted EBITDA, operating cash flow and adjusted net income available to common stockholders 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 12.

Operational Results

	•		Daily production rate of 325 MMcfe per day at December 31, 2008 increased 38.9% from 234 MMcfe per day at December 31, 2007

	•		2008 natural gas and crude oil production increased to 101.4 Bcfe (277 MMcfe per day) compared to 64.2 Bcfe (176 MMcfe per day) in 2007

	•		Proved reserves at December 31, 2008 of 2.159 Tcfe increased 42% from December 31, 2007

	•		Drilling finding costs and all-in finding costs for 2008 were $1.50 and $1.90 per Mcfe, respectively, excluding the negative impact of price related reserve revisions, and $2.00 and $2.50 per Mcfe, respectively, including the revisions

	•		Estimated ultimate recovery per well from the Warwick Caballos reservoir increased to 7.5 Bcfe from 7.0 Bcfe of total wet gas with an average CO₂content of 55%; 1,265 drilling locations currently identified in this reservoir

	•		Two Haynesville shale vertical test wells were drilled in East Texas, encountering 260 feet and 288 feet of shale thickness. The initial well tested at a rate of 1.5 MMcfe per day.

Tom L. Ward, Chief Executive Officer of SandRidge, observed, “We are very pleased with the company’s continued success in 2008, as demonstrated by several key financial and operating measures. Since the end of 2007, we have grown our adjusted EBITDA by 74%, our production by 58% and our reserves by 42%, all reflective of the company’s strong assets, especially those in the West Texas Overthrust.

“Our continuing drilling success in the WTO, specifically in the Warwick thrust, illustrates we control one of the premier gas reservoirs in North America. We expect our results in the Warwick thrust will be among the best in the industry for production, reserves and finding cost. Our drilling efforts have focused on less than 15% of our vast holdings of nearly 700,000 contiguous acres. We are confident we will make significant new discoveries in the Warwick thrust.

“Outside of the WTO, we have drilled two vertical test wells in the Haynesville shale in East Texas. The initial well encountered 260 feet of shale thickness and tested at a rate of 1.5 MMcfe per day. The second well encountered 288 feet of shale thickness and is awaiting completion. We are very pleased to have a prime acreage position in both the Haynesville shale and the Warwick thrust.

“Our industry and the broader economy have experienced unprecedented volatility in 2008 and early 2009. In response, we have substantially reduced our 2009 capital expenditure budget, hedged the majority of our gas production for 2009 and 2010, strengthened our balance sheet by issuing convertible preferred stock, and initiated a sale process of our WTO midstream assets.

“This fiscal discipline and our strong asset base position us to return to our historical significant growth levels when conditions improve.”

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


	Three Months Ended December 31,						Year Ended December 31,
	2008			2007			2008			2007
Production:
Natural gas (MMcf)		24,305			16,810			87,402			51,958
Crude oil (MBbl)⁽¹⁾		583			601			2,334			2,042
Natural gas equivalent (MMcfe)		27,801			20,418			101,405			64,211
Daily Production (MMcfed)		302			222			277			176

Average price per unit:
Realized natural gas price per Mcf — as reported	$	5.01		$	6.41		$	7.95		$	6.51
Realized impact of derivatives per Mcf		2.35			0.92			(0.05	)		0.67

Net realized price per Mcf	$	7.36		$	7.33		$	7.90		$	7.18


Realized crude oil price per barrel — as reported ⁽¹⁾	$	51.92		$	83.60		$	91.54		$	68.12
Realized impact of derivatives per barrel ⁽¹⁾		13.42			(0.10	)		(3.45	)		(0.02	)

Net realized price per barrel ⁽¹⁾	$	65.34		$	83.50		$	88.09		$	68.10


Realized price per Mcfe — as reported	$	5.46		$	7.74		$	8.96		$	7.45

Net realized price per Mcfe — including impact of derivatives per Mcfe	$	7.80		$	8.49		$	8.83		$	7.98


Average cost per Mcfe:
Lease operating	$	1.56		$	1.40		$	1.57		$	1.65
Production taxes		0.04			0.35			0.30			0.30
General and administrative:
General and administrative, excluding stock-based compensation		1.02			0.67			0.89			0.85
Stock-based compensation		0.16			0.11			0.19			0.11
Depletion		2.94			2.83			2.87			2.70

Lease operating cost per Mcfe:
Excluding offshore and tertiary recovery	$	1.30		$	1.14		$	1.35		$	1.38
Offshore operations		12.86			3.08			4.53			3.15
Tertiary recovery operations		10.95			16.21			11.16			13.09

Earnings per share:
Basic and diluted net (loss) income per share (applicable) available to common stockholders	$	(9.78	)	$	0.04		$	(9.36	)	$	0.09

Basic and diluted adjusted net income (loss) per share available (applicable) to common stockholders		0.06			0.09			0.97			(0.06	)

Weighted average number of common shares outstanding (thousands)
Basic		163,044			127,047			155,619			108,828
Diluted		163,044			128,478			155,619			110,041


⁽¹⁾		Includes NGLs

2008 Financial Results

Due to a fourth quarter non-cash $1.86 billion ceiling impairment on its natural gas and crude oil properties, the company reported a net loss applicable to common stockholders for 2008 of $1.6 billion compared to net income available to common stockholders of $4.9 million in 2007. Partially offsetting the impairment were increases in natural gas and crude oil production and average prices received for production during the full year 2008 and an increase in non-cash mark-to-market gains on natural gas and crude oil derivative contracts. Excluding the non-cash impairment and unrealized gains on natural gas and crude oil derivatives, which are detailed below, SandRidge had adjusted net income available to common stockholders of $151.5 million in 2008 compared to an adjusted net loss applicable to common stockholders of $6.2 million in 2007.

Ceiling Test Impairment

The company utilizes the full cost method of accounting for its natural gas and crude oil properties. As required by current U.S. Securities and Exchange Commission (“SEC”) rules, proved reserve volumes are calculated using fixed prices as of the last day of a period. Due to low commodity prices at December 31, 2008, the company recorded a pre-tax, non-cash impairment charge of approximately $1.86 billion ($1.68 billion after tax) against the carrying value of its natural gas and crude oil properties for the fourth quarter of 2008.

Under full cost accounting rules, costs associated with unproved properties may be classified as unevaluated. As such, they are excluded from the full cost pool, decreasing the size of any ceiling

limitation write-down on a dollar-for-dollar basis. The company’s unevaluated costs at December 31, 2008 constituted only 6% of total natural gas and crude oil properties. Additionally, because the company utilizes mark-to-market accounting (as opposed to hedge accounting) for its derivative contracts, the $246.6 million fair value benefit of its December 31, 2008 commodity hedge positions was excluded from the ceiling limitation calculation.

Production, Pricing and Operating Costs

Successful drilling throughout 2008 increased natural gas and crude oil production by 57.9% to 101.4 Bcfe for 2008 from 64.2 Bcfe for 2007. Fourth quarter 2008 production was 36.2% higher, or 27.8 Bcfe, compared to 20.4 Bcfe in the same period of 2007.

The average price received, excluding the impact of derivative contract settlements, for natural gas increased 22.1% in the full year 2008 to $7.95 per Mcf compared to $6.51 per Mcf in 2007. Due to sharp pricing declines in fourth quarter 2008, however, the average price received, excluding the impact of derivative contract settlements, for natural gas sales declined 21.8% in fourth quarter 2008 to $5.01 per Mcf from $6.41 per Mcf in fourth quarter 2007. Similarly, average prices received, excluding the impact of derivative contract settlements, for crude oil production in the full year 2008 increased 34.4% to $91.54 per barrel, while average prices received, excluding the impact of derivative contract settlements, for crude oil production in the fourth quarter of 2008 decreased 37.9%, to $51.92 per barrel from fourth quarter 2007.

The increase in total production for 2008 coupled with higher average commodity prices received during 2008 resulted in higher natural gas and crude oil revenues of $908.7 million for 2008 compared to $477.6 million in 2007. Increased fourth quarter 2008 production levels were offset by lower prices received during that time resulting in decreased natural gas and crude oil revenues of $151.9 million compared to $158.1 million for the same period in 2007.

Total production expense increased to $159.0 million for full year 2008 from $106.2 million in 2007 and increased to $43.5 million for fourth quarter 2008 from $28.5 million during the same period in 2007. The increased expenses primarily were due to increased volumes produced during the 2008 periods compared to the 2007 periods. Additionally, production losses from the Grey Ranch plant fire and Hurricane Ike resulted in an 11% increase in cost per Mcfe produced during fourth quarter 2008 compared to the same period in 2007.

Gains (Losses) on Derivative Contracts

The company enters into natural gas and crude oil swaps and basis swaps for a portion of its production in order to stabilize future cash inflows for planning purposes. In that regard, the net loss for 2008 was offset by a net gain of $211.4 million ($224.4 million unrealized gain and $13.0 million realized loss) on derivative commodity contracts. This compares to a $60.7 million gain ($26.2 million unrealized gain and $34.5 million realized gain) for 2007. The net gain on derivative commodity contracts for fourth quarter 2008 was $215.5 million ($150.5 million unrealized gain and $65.0 million realized gain) compared to a net gain of $5.5 million ($9.8 million unrealized loss and $15.3 million realized gain) for the same period in 2007.

Production and Drilling Activities

SandRidge owned working interests in 2,059 producing wells at December 31, 2008 compared to 1,654 producing wells at December 31, 2007. Daily production averaged 277 MMcfe during full year 2008 with a year end exit rate of 325 MMcfe per day. The company exceeded its 2008 production guidance of 100.0 Bcfe (issued May 2008), ending the year with total production of 101.4 Bcfe.

In response to the continued weak commodity and economic environment, the company began to decrease the number of rigs running on its properties during December 2008 in preparation for reduced 2009 activity levels. At December 31, 2008, the company had 17 rigs running compared to a high of 47 rigs operating in the second quarter of 2008. The company currently has nine rigs running.

The following is an operational update for each of the company’s key areas:

West Texas Overthrust (WTO): The company averaged 26 rigs operating in the WTO and drilled 64 wells during the fourth quarter of 2008, bringing the total number of wells drilled in the WTO during 2008 to 257. There are currently 6 rigs active in the WTO. A total of 258 gross (250 net) wells were completed and brought on production in the WTO throughout 2008. At December 31, 2008, the company owned and operated 660 gross (632.7 net) wells in the WTO.

SandRidge acquired 903 square miles of 3-D seismic data in 2008, bringing the total 3-D seismic data acquired to date in the WTO to 1,292 square miles. SandRidge continues to exploit and expand the Piñon field utilizing 3-D data and historical well information to identify new reservoirs in the three primary thrusts (Dugout Creek, Warwick, and Frog Creek).

The 5.7 Tcfe of net proved, possible and probable reserves identified in the company’s Piñon holdings are located almost exclusively in the Dugout Creek and Warwick thrusts. The Frog Creek thrust is the most recent of the three thrusts discovered in the Piñon field to have commercial production and provides drilling opportunities in the Caballos chert at depths ranging from 3,500 feet to 5,500 feet. The Frog Creek thrust as interpreted by 3-D data appears to be similar in size to that of the Dugout Creek and Warwick thrusts. Recent production tests from the Frog Creek thrust confirm low (less than 3%) CO₂gas. The company believes the Frog Creek thrust may contain substantial quantities of reserves that can be developed at or below current Piñon drilling finding costs. With the aid of 3-D seismic data and historical well information, SandRidge believes it can high-grade its drilling locations in the multiple thrusts within the Piñon field and continue to deliver drilling finding costs below $1.75 per Mcfe.

The Big Canyon A 121-1A exploratory well was drilled in the Warwick thrust to a total depth of 16,847 feet and encountered 543 feet of chert. This is comparable in thickness to the prolific chert reservoirs found in the Piñon field. However, the reservoir in the Big Canyon A 121-1A well is less fractured than those typically associated with prolific producing wells found along the WTO and in the Piñon field. The Big Canyon A 121-1A well’s results are encouraging for future exploration in that it tested 225 Mcf per day of methane gas with only trace amounts of CO₂. The Big Canyon A 121-1A is located approximately 25 miles east of the Piñon field.

High CO₂ Gas Update: The most prolific reservoir in the Piñon field is the Warwick Caballos chert high CO₂reservoir at depths of 6,000 feet to 8,000 feet. Based on the company’s experience with approximately 137 wells drilled to date, the average estimated ultimate recovery per well for this reservoir is 7.5 Bcfe of total gas. The expected drilling finding cost for this reservoir is $1.11 per Mcfe of methane. Production from this reservoir is limited to the company’s current inlet high CO₂ gas treating capacity of approximately 300.0 MMcf per day. The company is expanding the capacity of existing plants as well as constructing the new Century Plant. The Century Plant is designed to have treating capacity of 800.0 MMcf per day and is expected to be completed in two phases with the first phase coming on line in the second quarter of 2010 and the second phase coming on line in 2011. Upon completion of these phases, methane production from the Warwick thrust high CO₂reservoirs could be developed as follows (volumes in MMcf per day):


			Approximate		Approximate
	Plant Inlet		Gross		SandRidge
Date	Capacity		Methane		Net Methane (1)		Plant Source

YE 2008		300		105		77	Existing Plants
2009		350		120		88	Existing Plants
2010		750		260		190	Existing + Century Phase 1
2011		1,150		400		290	Existing + Century Phase 2


⁽¹⁾		Based on estimated net revenue interest and 65% CO₂

The current CO₂ treating capacity limits the company’s ability to aggressively develop the Warwick thrust where gas contains CO₂ levels above pipeline specifications. Once the Century Plant commences operations in 2010, the company intends to implement a more aggressive drilling program and accelerate production and reserves growth from the Warwick thrust.

East Texas Cotton Valley Development: An average of 5 rigs operated on the company’s properties in East Texas in 2008, drilling 54 wells during that period. A total of 54 gross (53.3 net) wells were completed and brought on production in East Texas during 2008. At December 31, 2008, the company owned 232 gross (218.4 net) wells in East Texas.

East Texas/North Louisiana — Haynesville Shale Play: The company controls approximately 36,000 acres in the developing Haynesville shale play of East Texas and North Louisiana. About 22,500 acres of that total are in Rusk and Harrison Counties, Texas. The company drilled two vertical test wells within the Oakhill field area in Rusk County to evaluate the potential for Haynesville shale production. The initial well had a total of 260 feet of Haynesville shale thickness and tested at a rate of 1.5 MMcfe per day. The second well encountered 288 feet of shale thickness and is awaiting completion.

Mid-Continent: An average of 3 rigs operated on the company’s prospects located in Oklahoma in 2008, drilling 98 wells during that period. A total of 154 gross (85.4 net) Oklahoma wells were completed and brought on production in 2008. At December 31, 2008, the company owned 611 gross (242.5 net) wells in the Mid-Continent area.

Capital Expenditures

The table below summarizes the company’s capital expenditures for the three-month periods and years ended December 31, 2008 and 2007:


	Three Months Ended December 31,				Year Ended December 31,
	2008		2007		2008		2007
	(in thousands)				(in thousands)

Drilling and production
WTO	$	234,552	$	219,334	$	985,435	$	592,844
Non-WTO (excluding tertiary)		117,354		57,262		390,684		191,973
Tertiary		12,800		6,563		31,564		23,904

		364,706		283,159		1,407,683		808,721

Leasehold and seismic
WTO		70,349		35,839		303,289		171,672
Non-WTO (excluding tertiary)		44,231		20,783		148,703		61,059
Tertiary		—		1		87		2,501

		114,580		56,623		452,079		235,232

Pipe inventory		14,324		—		47,245		—

Total exploration and development		493,610		339,782		1,907,007		1,043,953


Drilling and oil field services		2,030		18,435		52,869		123,232
Midstream		50,335		18,401		160,460		63,828
Other — general		22,517		9,070		57,511		49,835


Total capital expenditures, excluding acquisitions		568,492		385,688		2,177,847		1,280,848


Acquisitions		—		116,650		—		116,650


Total capital expenditures	$	568,492	$	502,338	$	2,177,847	$	1,397,498

Exploration and development expenditures in 2008 totaled $1.9 billion and were 83% higher than 2007 exploration and development expenditures as the company expanded drilling activity in its key operating areas, gathered and processed WTO 3-D seismic data, and acquired leasehold positions in its core development areas. The company’s midstream business had capital expenditures of $160.5 million during 2008 compared to $63.8 million during 2007 as the company continued to build pipeline infrastructure and add compression in the WTO in order to accommodate the growth in its exploration and production business.

Proved Reserves

The company’s estimated proved reserves as of December 31, 2008 were 2.159 Tcfe, representing a 42% increase from December 31, 2007 proved reserves of 1.516 Tcfe. Estimates of approximately 96% of the company’s total proved reserves as of December 31, 2008 were prepared by third-party engineers. Proved developed reserves constituted 44% of total reserves as of both December 31, 2008 and 2007. The December 31, 2008 estimated future net cash flows from proved reserves, discounted at an annual rate of 10%, before income taxes (“PV-10”) were $2.26 billion, a decrease of 36% from December 31, 2007 PV-10 of $3.55 billion. Decreases in price per unit of future production accounted for a $2.31 billion decrease in PV-10 from December 31, 2007 to December 31, 2008 which was partially offset by extensions and positive revisions of reserve quantities. The standardized measure of discounted cash flows as of December 31, 2008 was $2.22 billion compared to $2.72 billion at December 31, 2007. PV-10 is calculated before considering the impact of future income tax expenses, while the standardized measure includes such effects.

Excluding the negative impact of price related reserve revisions, drilling finding costs and all-in finding costs, which include drilling, acquisitions, land, and seismic costs, were $1.50 and $1.90 per Mcfe, respectively, for the year ended December 31, 2008. After consideration of these revisions, drilling finding costs and all-in finding costs were $2.00 and $2.50 per Mcfe, respectively, for 2008. The calculated weighted average per unit prices for the company’s proved reserves and future net revenues were $4.94 per Mcf for natural gas and $39.42 per barrel for crude oil at December 31, 2008 compared to $6.46 per Mcf for natural gas and $87.47 per barrel for crude oil at December 31, 2007. This decline in commodity prices caused some of the company’s reserves to be removed from its proved reserves as those quantities could not be economically developed in the pricing environment prevalent at December 31, 2008, compounding the negative effect on PV-10. As required by current rules, year-end proved reserve volumes were calculated using prices as of a single day (December 31, 2008). Beginning with the December 31, 2009 reserve estimates, under reporting rules recently promulgated by the SEC, the company’s reserve estimates will be calculated using a 12-month average pricing provision.

Analysis of Changes in Proved Reserves


	Crude Oil			Natural Gas			Combined
	(MBbls)			(Bcf)			(Bcfe)
As of December 31, 2007		36,527			1,297			1,516
Revisions — quantity		11,931			616			688
Revisions — pricing		(5,193	)		(204	)		(235	)
Acquisitions of new reserves		513			38			41
Sales of reserves in place		(8	)		(2	)		(2	)
Extensions and discoveries		1,728			242			252
Production		(2,334	)		(87	)		(101	)

As of December 31, 2008		43,164			1,900			2,159

Reserve Replacement Economics


										3-Year
	2008			2007			2006			Average
	(in millions except as noted)
Proved reserves (Bcfe)		2,158.6			1,516.2			1,001.8
% Proved reserve growth		42	%		51	%		234	%
% Proved developed		44	%		44	%		32	%
Annual Production (Bcfe)		101.4			64.2			15.3			60.3
% Production growth		58	%		320	%		110	%		72.8	(1)
Proved reserve life (years)		21.3			23.6			19.0	(1)
PDP reserve life (years)		9.3			10.4			7.1	(1)

Excluding acquisitions
F&D Reserve additions (Bcfe)		704.5			503.2			120.4			442.7
F&D Costs incurred	$	1,407.7		$	808.7		$	133.8		$	783.4
F&D Costs per Mcfe	$	2.00		$	1.61		$	1.11		$	1.77
Drillbit reserve replacement		695	%		784	%		787	%		734	%

Including acquisitions
Total reserve additions (Bcfe)		743.8			578.7			717.1			679.9
Total costs incurred	$	1,859.8		$	1,150.6		$	1,713.6		$	1,574.7
Reserve replacement cost per Mcfe	$	2.50		$	1.99		$	2.39		$	2.32
Proved reserve replacement		734	%		901	%		1,361	%(1)		934	%(1)


(1)		Based upon pro forma 2006 production of 52.7 Bcfe

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

Derivative Contracts

The table below sets forth the company’s natural gas price and basis swaps and crude oil swaps for 2009 and 2010 as of February 20, 2009. Current natural gas and crude oil derivative contracts excluding basis swaps account for 67% to 73% of anticipated production for 2009 at $8.59 per Mcfe. The company also has natural gas basis swaps in place in 2011 for 20.08 Bcf at an average price of $0.68 per Mcf.


									Year
	Quarter Ending								Ending
	3/31/2009		6/30/2009		9/30/2009		12/31/2009		12/31/2009

Natural Gas Swaps:
Volume (Bcf)		20.70		20.93		18.71		19.01		79.35
Swap	$	9.14	$	7.96	$	8.09	$	8.46	$	8.42

Natural Gas Basis Swaps:
Volume (Bcf)		15.30		15.47		15.64		15.64		62.05
Swap	$	0.74	$	0.74	$	0.74	$	0.74	$	0.74

Crude Oil Hedges:
Swap Volume (MMBbls)		0.05		0.05		0.05		0.05		0.18
Swap	$	126.38	$	126.71	$	126.61	$	126.51	$	126.55


									Year
	Quarter Ending								Ending
	3/31/2010		6/30/2010		9/30/2010		12/31/2010		12/31/2010

Natural Gas Swaps:
Volume (Bcf)		20.48		19.79		20.01		20.01		80.29
Swap	$	7.95	$	7.32	$	7.55	$	7.97	$	7.70

Natural Gas Basis Swaps:
Volume (Bcf)		20.25		20.48		20.70		20.70		82.13
Swap	$	0.74	$	0.74	$	0.74	$	0.74	$	0.74

Crude Oil Hedges:
Swap Volume (MMBbls)		0.00		0.00		0.00		0.00		0.00
Swap	NM		NM		NM		NM		NM

Balance Sheet

The company’s total debt (short-term and long-term) increased $1.307 billion during 2008 primarily as a result of borrowings made under its senior credit facility to fund its 2008 capital expenditure program and the issuance in May 2008 of $750.0 million of 8.0% Senior Notes Due 2018. The company used $478.0 million of the $735.0 million of net proceeds from the May 2008 offering to repay borrowings under the company’s senior credit facility. Additionally, during 2008, the company made principal payments on its rig loan and mortgage totaling $16.0 million and $0.9 million, respectively. At December 31, 2008, the company had classified $16.5 million of its long-term debt as current. This total included $15.6 million related to its rig loan and $0.9 million related to the company’s mortgage. Total debt as of December 31, 2008 was $2.375 billion compared to $1.068 billion at year-end 2007. The company was in compliance with all of the financial covenants contained in its debt agreements at December 31, 2008.

The company’s capital structure at December 31, 2008 and 2007 are presented below:


	December 31,
	2008			2007
	(in thousands)

Cash and cash equivalents	$	636		$	63,135


Current maturities of long-term debt		16,532			15,350
Long-term debt (net of current maturities):
Senior credit facility		573,457			—
Notes payable — Drilling rig fleet and oil field services equipment		17,375			33,416
Mortgage		17,952			18,829
Notes payable — Other equipment and vehicles		—			54
Term loans and Senior Notes:
Senior Floating Rate Term Loan		—			350,000
8.625% Senior Term Loan		—			650,000
Senior Floating Rate Notes due 2014		350,000			—
8.625% Senior Notes due 2015		650,000			—
8.0% Senior Notes due 2018		750,000			—

Total debt		2,375,316			1,067,649

Minority interest		30			4,672

Redeemable convertible preferred stock		—			450,715

Stockholders’ equity:
Preferred stock		—			—
Common stock		163			140
Additional paid-in capital		2,170,986			1,686,113
Treasury stock, at cost		(19,332	)		(18,578	)
Retained earnings		(1,358,296	)		99,216

Total stockholders’ equity		793,521			1,766,891


Total capitalization	$	3,168,867		$	3,289,927

2009 Operational Guidance

In response to unprecedented volatility in natural gas and crude oil pricing, the company is introducing a 2009 production guidance range of 110.0 Bcfe to 120.0 Bcfe based upon a capital expenditure guidance range of $500 million to $700 million. Based on the current and anticipated near-term drilling activity and associated expenditures, it is currently expected that full year results will trend toward the lower half of the ranges. The guidance presented below includes the effects of a potential sale of the company’s WTO midstream assets.


		Year Ending
		December 31, 2009

Production
Natural Gas (Bcf)		92 - 102
Crude Oil (MMBbls)		3 - 3

Total (Bcfe)		110 - 120

Differentials
Natural Gas		$0.70
Crude Oil		5.00

Costs per Mcfe
Lifting		$1.80 - $1.93
Production Taxes		0.18 - 0.19
DD&A — oil & gas		2.09 - 2.19
DD&A — other		0.63 - 0.73

Total DD&A		$2.72 - $2.92
G&A — cash		0.67 - 0.78
G&A — stock		0.25 - 0.29

Total G&A		$0.92 - $1.07
Interest Expense		$1.29 - $1.47

Corporate Tax Rate		36%
Deferral Rate		95%

Shares Outstanding at End of Period (in millions)
Common Stock		169.5
Preferred Stock (converted)		33.1

Fully Diluted		202.6

Capital Expenditures ($ in millions)
Exploration and Production		$400 - $565
Land and Seismic		25 - 50

Total Exploration and Production		$425 - $615
Oil Field Services		10 - 20
Midstream and Other		65 - 65

Total Capital Expenditures		$500 - $700

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 is EBITDA excluding interest income and various non-cash items (including asset impairments, income from equity investments, minority interest, stock-based compensation, unrealized (gain) loss on derivative contracts, and provision for doubtful accounts). This generally conforms to the EBITDA definition in the company’s credit agreement.

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

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

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

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


	Three Months Ended December 31,					Year Ended December 31,
	2008		2007			2008			2007
	(in thousands)					(in thousands)
Net cash provided by operating activities	$	44,821	$	117,896		$	579,189		$	357,452
Add (deduct):
Change in operating assets and liabilities		69,860		(8,680	)		(38,875	)		(61,813	)

Operating cash flow	$	114,681	$	109,216		$	540,314		$	295,639

Reconciliation of Net Income to EBITDA and Adjusted EBITDA


	Three Months Ended December 31,						Year Ended December 31,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net (loss) income⁽¹⁾	$	(1,594,658	)	$	14,230		$	(1,441,280	)	$	50,221

Adjusted for:
Income tax (benefit) expense		(127,636	)		8,522			(38,328	)		29,524
Interest expense⁽²⁾		42,112			28,555			138,282			117,185
Depreciation, depletion and amortization — other		19,106			16,996			70,448			53,541
Depreciation, depletion and amortization — natural gas and crude oil		81,621			57,692			290,917			173,568

EBITDA		(1,579,455	)		125,995			(979,961	)		424,039

Asset impairments		1,867,497			—			1,867,497			—
Provision for doubtful accounts		125			—			1,748			—
Income from equity investments		(43	)		(973	)		(1,398	)		(4,372	)
Minority interest		2			(597	)		855			(276	)
Interest income		(501	)		(1,022	)		(3,569	)		(4,694	)
Stock-based compensation		4,501			2,240			18,784			7,202
Unrealized (gains) losses on derivative contracts		(134,072	)		9,814			(215,675	)		(26,238	)

Adjusted EBITDA	$	158,054		$	135,457		$	688,281		$	395,661


⁽¹⁾		Includes gain on sale of assets

⁽²⁾		Excludes unrealized loss of $16.5 million and $8.7 million on interest rate swap for the three months and year ended December 31, 2008, respectively.

Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA


	Three Months Ended December 31,						Year Ended December 31,
	2008			2007			2008			2007
	(in thousands)						(in thousands)
Net cash provided by operating activities	$	44,821		$	117,896		$	579,189		$	357,452
Changes in operating assets and liabilities		69,860			(8,680	)		(38,875	)		(61,813	)
Interest expense⁽¹⁾		42,112			28,555			138,282			117,185
Unrealized gains (losses) on derivative contracts		134,072			(9,814	)		215,675			26,238
Gain on sale of assets		142			73			9,273			1,777
Other non-cash items		(132,953	)		7,427			(215,263	)		(45,178	)

Adjusted EBITDA	$	158,054		$	135,457		$	688,281		$	395,661


⁽¹⁾		Excludes unrealized loss of $16.5 million and $8.7 million on interest rate swap for the three months and year ended December 31, 2008, respectively.

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


	Three Months Ended December 31,						Year Ended December 31,
	2008			2007			2008			2007
	(in thousands)						(in thousands)

Net income available (loss applicable) to common stockholders	$	(1,594,658	)	$	4,916		$	(1,457,512	)	$	10,333
Asset impairments		1,867,497			—			1,867,497			—
Unrealized (gains) losses on derivative contracts		(134,072	)		9,814			(215,675	)		(26,238	)
Effect of income taxes		(128,461	)		(3,676	)		(42,789	)		9,714

Adjusted net income available (loss applicable) to common stockholders	$	10,306		$	11,054		$	151,521		$	(6,191	)

Per share — basic and diluted	$	0.06		$	0.09		$	0.97		$	(0.06	)

Conference Call Information

The company will host a conference call to discuss these results on Friday, February 27, 2009 at 9:00 am EST. The telephone number to access the conference call from within the U.S. is 866-356-4279 and from outside the U.S. is 617-597-5394. The passcode for the call is 78732749. An audio replay of the call will be available at noon EST on February 27, 2009 until March 20, 2009. 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 40126090.

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.

2009 Investor/Analyst Conference Information and First Quarter 2009 Earnings Release and Conference Call Information

2009 Investor/Analyst Conference:

March 3, 2009 (Tuesday) — New York, NY at the Grand Hyatt New York, 109 East 42^nd Street at 8:00 am EST

First Quarter Earnings and Conference Call:

May 7, 2009 (Thursday) — Earnings press release and filing of 10-Q after market close

May 8, 2009 (Friday) — Earnings conference call at 9:00 am EDT

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations


	Three Months Ended
	December 31,						Years Ended December 31,
	2008			2007			2008			2007
	(In thousands, except per share amounts)

Revenues:
Natural gas and crude oil	$	151,927		$	158,056		$	908,689		$	477,612
Drilling and services		10,854			16,269			47,199			73,197
Midstream and marketing		33,362			36,634			207,602			107,765
Other		4,512			4,718			18,324			18,878

Total revenues		200,655			215,677			1,181,814			677,452

Expenses:
Production		43,492			28,485			159,004			106,192
Production taxes		1,138			7,229			30,594			19,557
Drilling and services		5,760			13,276			26,186			44,211
Midstream and marketing		29,596			33,062			186,655			94,253
Depreciation, depletion and amortization — natural gas and crude oil		81,621			57,692			290,917			173,568
Depreciation, depletion and amortization — other		19,106			16,996			70,448			53,541
Impairments		1,867,497			—			1,867,497			—
General and administrative		32,940			15,999			109,372			61,780
Gain on derivative contracts		(215,525	)		(5,504	)		(211,439	)		(60,732	)
Gain on sale of assets		(142	)		(73	)		(9,273	)		(1,777	)

Total expenses		1,865,483			167,162			2,519,961			490,593

(Loss) income from operations		(1,664,828	)		48,515			(1,338,147	)		186,859


Other income (expense):
Interest income		501			1,022			3,569			4,694
Interest expense		(58,606	)		(28,555	)		(147,027	)		(117,185	)
Minority interest		(2	)		597			(855	)		276
Income from equity investments		43			973			1,398			4,372
Other income, net		598			200			1,454			729

Total other (expense) income		(57,466	)		(25,763	)		(141,461	)		(107,114	)

(Loss) income before income tax (benefit) expense		(1,722,294	)		22,752			(1,479,608	)		79,745
Income tax (benefit) expense		(127,636	)		8,522			(38,328	)		29,524

Net (loss) income		(1,594,658	)		14,230			(1,441,280	)		50,221
Preferred stock dividends and accretion		—			9,314			16,232			39,888

(Loss applicable) income available to common stockholders	$	(1,594,658	)	$	4,916		$	(1,457,512	)	$	10,333


(Loss) income per share (applicable) available to common stockholders:
Basic	$	(9.78	)	$	0.04		$	(9.36	)	$	0.09

Diluted	$	(9.78	)	$	0.04		$	(9.36	)	$	0.09


Weighted average number of common shares outstanding:
Basic		163,044			127,047			155,619			108,828

Diluted		163,044			128,478			155,619			110,041

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets


	As of December 31,
	2008			2007
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	636		$	63,135
Accounts receivable, net:
Trade		102,746			94,741
Related parties		6,327			20,018
Derivative contracts		201,111			21,958
Inventories		3,686			3,993
Deferred income taxes		—			1,820
Other current assets		41,407			20,787

Total current assets		355,913			226,452

Natural gas and crude oil properties, using full cost method of accounting
Proved		4,676,072			2,848,531
Unproved		215,698			259,610
Less: accumulated depreciation, depletion and impairment		(2,369,840	)		(230,974	)

		2,521,930			2,877,167


Other property, plant and equipment, net		653,629			460,243
Derivative contracts		45,537			270
Investments		6,088			7,956
Restricted deposits		32,843			31,660
Other assets		39,118			26,818

Total assets	$	3,655,058		$	3,630,566


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current maturities of long-term debt	$	16,532		$	15,350
Accounts payable and accrued expenses:
Trade		366,337			215,497
Related parties		230			395
Derivative contracts		5,106			—
Asset retirement obligation		275			864
Billings in excess of costs incurred		14,144			—

Total current liabilities		402,624			232,106

Long-term debt		2,358,784			1,052,299
Other long-term obligations		11,963			16,817
Derivative contracts		3,639			—
Asset retirement obligation		84,497			57,716
Deferred income taxes		—			49,350

Total liabilities		2,861,507			1,408,288


Commitments and contingencies
Minority interest		30			4,672
Redeemable convertible preferred stock, $0.001 par value, 2,625 shares authorized; no shares issued and outstanding at December 31, 2008 and 2,184 shares issued and outstanding at December 31, 2007		—			450,715

Stockholders’ equity:
Preferred stock, $0.001 par value; 47,375 shares authorized; no shares issued and outstanding in 2008 and 2007		—			—
Common stock, $0.001 par value; 400,000 shares authorized; 167,372 issued and 166,046 outstanding at December 31, 2008 and 143,299 issued and 141,843 outstanding at December 31, 2007		163			140
Additional paid-in capital		2,170,986			1,686,113
Treasury stock, at cost		(19,332	)		(18,578	)
(Accumulated deficit) retained earnings		(1,358,296	)		99,216

Total stockholders’ equity		793,521			1,766,891

Total liability and stockholders’ equity	$	3,655,058		$	3,630,566

SandRidge Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows


	Years Ended December 31,
	2008			2007
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income	$	(1,441,280	)	$	50,221
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for doubtful accounts		1,748			—
Depreciation, depletion and amortization		361,365			227,109
Impairments		1,867,497			—
Debt issuance cost amortization		5,623			15,998
Deferred income taxes		(47,530	)		28,923
Provision for inventory obsolescence		—			203
Unrealized (gain) loss on derivative contracts		(215,675	)		(26,238	)
Gain on sale of assets		(9,273	)		(1,777	)
Interest income — restricted deposits		(402	)		(1,354	)
Income from equity investments		(1,398	)		(4,372	)
Stock-based compensation		18,784			7,202
Minority interest		855			(276	)
Changes in operating assets and liabilities		38,875			61,813

Net cash provided by operating activities		579,189			357,452


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(2,058,415	)		(1,280,848	)
Acquisition of assets		—			(116,650	)
Proceeds from sale of assets		158,781			9,034
Contributions on equity investments		(1,528	)		—
Loans to equity investee		(7,500	)		—
Refunds of restricted deposits		—			10,328
Fundings of restricted deposits		(781	)		(7,445	)
Restricted cash		—			—

Net cash used in investing activities		(1,909,443	)		(1,385,581	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		3,252,209			1,331,541
Repayments of borrowings		(1,944,542	)		(1,332,219	)
Dividends paid preferred		(17,552	)		(33,321	)
Minority interest distributions		(5,497	)		(144	)
Proceeds from issuance of common stock		—			1,114,660
Stock-based compensation excess tax benefit		4,594			—
Purchase of treasury stock		(3,553	)		(1,661	)
Debt issuance costs		(17,904	)		(26,540	)

Net cash provided by financing activities		1,267,755			1,052,316


NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(62,499	)		24,187
CASH AND CASH EQUIVALENTS, beginning of year		63,135			38,948

CASH AND CASH EQUIVALENTS, end of period	$	636		$	63,135


Supplemental Disclosure of Cash Flow Information:
Cash paid for interest, net of amounts capitalized	$	131,183		$	83,567
Cash paid for income taxes	$	2,191		$	2,371
Supplemental Disclosure of Noncash Investing and Financing Activities:
Accrued capital expenditures	$	119,432		$	—
Redeemable convertible preferred stock dividends, net of dividends paid	$	—		$	8,956
Insurance premium financed	$	—		$	1,496
Accretion on redeemable convertible preferred stock	$	7,636		$	1,421

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 Notes 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. These statements express a belief, expectation or intention and are generally accompanied by words that convey projected future events or outcomes. The forward-looking statements include projections and estimates of future natural gas and crude oil production, pricing differentials, operating costs and capital spending, descriptions of our development plans and provide internal estimates of proved reserves and future net cash flows. We have based these forward-looking statements on our current expectations and assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments, as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the volatility of natural gas and oil prices, our success in discovering, estimating, developing and replacing natural gas and oil reserves, 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, the risk of a recession, the receipt of adequate proceeds for our WTO midstream assets, construction risks related to the Century Plant, including the reliance we place on third parties, the amount and timing of future development costs, the availability and demand for alternative energy sources, regulatory changes, including those related to carbon dioxide, and other factors, many of which are beyond our control. We refer you to the discussion of risk factors in Item 1A — “Risk Factors” of the Annual Report on Form 10-K we filed with the U.S. Securities and Exchange Commission (“SEC”) today. 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.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in the press release, such as “probable reserves,” “possible reserves,” and “estimated ultimate recovery” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the disclosures in our 2008 Form 10-K, File No. 001-33784, available from us at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 or www.sandridgeenergy.com. You may also access our filings with the SEC at www.sec.gov or obtain copies from the SEC by calling 1-800-732-0330.

SandRidge Energy, Inc. is a natural gas and crude oil company headquartered in Oklahoma City, Oklahoma with its principal focus on exploration and production. SandRidge and its subsidiaries also own and operate gas gathering and processing facilities and CO₂treating and transportation facilities and conduct marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc., a wholly-owned subsidiary of SandRidge, owns and operates a drilling rig and related oil field services business. SandRidge focuses its exploration and production activities in West Texas, the Cotton Valley Trend in East Texas, the Gulf Coast, the Mid-Continent, and the Gulf of Mexico. SandRidge’s Internet address is www.sandridgeenergy.com.


Delaware	1-33784	20-8084793
(State or Other Jurisdiction of	(Commission File Number)	(I.R.S. Employer
Incorporation or Organization)		Identification No.)


123 Robert S. Kerr Avenue		73102
Oklahoma City, Oklahoma		(Zip Code)
(Address of Principal Executive Offices)

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

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

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

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


	SANDRIDGE ENERGY, INC. (Registrant)
Date: February 26, 2009	By:	/s/ Dirk M. Van Doren
		Dirk M. Van Doren
		Executive Vice President and Chief Financial Officer


Exhibit Number		Name of Exhibit

99.1		Press release issued February 26, 2009 announcing operational and financial results for the quarter and year ended December 31, 2008